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pdfDecember 21, 2011
VIA ELECTRONIC FILING
Ms. Kimberly D. Bose
Secretary
Federal Energy Regulatory Commission
888 First Street, NE
Washington, D.C. 20426
Re: North American Electric Reliability Corporation
Docket No._______
Dear Ms. Bose:
The North American Electric Reliability Corporation (“NERC”) hereby submits
this petition in accordance with Section 215(d)(1) of the Federal Power Act (“FPA”) and
Part 39.5 of the Federal Energy Regulatory Commission’s (“FERC” or the
“Commission”) regulations seeking:
•
approval of Reliability Standard FAC-003-2 — Transmission Vegetation
Management (FAC-003-2) and the associated Violation Risk Factors (“VRFs”)
and Violation Severity Levels (“VSLs”), included in Exhibit A to the petition,
effective the first day of the first calendar quarter one year following the effective
date of a Final Rule in this docket; 1
•
approval of three proposed definitions to be added to the NERC Glossary of
Terms used in the NERC Reliability Standards effective the first day of the first
calendar quarter one year following the effective date of a Final Rule in this
docket:
-
Right-of-Way
Vegetation Inspection
Minimum Vegetation Clearance Distance (“MVCD”)
1
Because the proposed FAC-003-2 standard has been substantially revised, a redlined version of FAC-0032 is not included in this filing, as it would be difficult to read and of limited value.
1
•
approval of the implementation plan for Reliability Standard FAC-003-2 —
Transmission Vegetation Management which is included in Exhibit B to the
petition; and
•
approval of the retirement of Reliability Standard FAC-003-1 — Transmission
Vegetation Management Program (FAC-003-1) and the currently effective NERC
Definitions for “Right-of-Way” and “Vegetation Inspection” effective midnight
immediately prior to the first day of the first calendar quarter that is a year
following the effective date of a Final Rule in this docket:
The proposed FAC-003-2 standard addresses the important goal of managing
vegetation to maintain a reliable electric transmission system and presents three themes
that all help to improve reliability. First, reliability will be improved with
implementation of the new standard. Second, enforceability of FAC-003-2, as compared
to FAC-003-1, will be improved and cleaner for NERC and the Regional Entities. And
third, NERC registered entities will have greater flexibility to address local vegetation
management conditions.
Ineffective vegetation management was identified as a major cause of the August
14, 2003, blackout, and has also been a causal factor in other large-scale North American
outages such as those that occurred in the summer of 1996 in the western United States. 2
Recommendation 16 of the Blackout Report 3 suggests the establishment of enforceable
standards for maintenance of electrical clearances in right-of-way areas. NERC “raised
the bar” with the development of the FAC-003-1 Reliability Standard, and the
2
See, Final Report on the August 14, 2003 Blackout in the United States and Canada: causes and
Recommendations, U.S.-Canada Power System Outage Task Force, April 5, 2004, at p. 154 (“Blackout
Report”).
3
Blackout Report, Recommendation 16.
enhancements to the standard included with this filing represents another “raising of the
bar.” Unlike the previous standard, which is primarily focused on the “Transmission
Vegetation Management Program,” the new version of FAC-003 has a broader focus on
“Transmission Vegetation Management,” which is reflected both in the title of the
standard and the fact that there are now results-based performance requirements that
require specific actions, rather than just documentation.
The general improvements compared to the previous version of the standard are
shown in the table below:
Requirement in Existing
FAC-003-1 Standard
Improvements in Proposed
FAC-003-2 Standard
Requires a document that includes
vegetation management objectives,
approved procedures, and work
specifications. (R1)
Requires documented vegetation management
maintenance strategies, procedures, processes,
or specifications that will prevent
encroachment into the Minimum Vegetation
Clearance Distance (MVCD) (R3)
Requires a document schedule for
ROW vegetation inspections. (R1.1)
Requires vegetation inspection of 100% of
applicable transmission lines at least once per
calendar year. (R6)
Requires documentation of a
“Clearance 1” value based on TO
assessment of situation and risk. (R1.2
and R1.2.1)
Requires vegetation be managed such that no
encroachments into the MVCD (as
established by the Gallet Equation) occur,
regardless of whether or not they result in a
sustained outage. (R3, parts 3.1 and 3.2)
Requires documentation of a
“Clearance 2” value based on IEEE
standard. (R1.2.2, R1.2.2.1, and
R1.2.2.2)
Requires vegetation be managed such that no
encroachments into the MVCD (as
established by the Gallet Equation) occur,
regardless of whether or not they result in a
sustained outage. (R1 and R2)
Requires documentation of mitigation
Requires corrective action to be taken in cases
measures to address locations on the
on the ROW where the TO is
restricted from attaining specified
clearances. (R1.4)
Requires documentation of a process
for communicating imminent threats
where vegetation conditions could lead
to a transmission line outage. (R1.5)
Requires the creation and
implementation of an annual
vegetation management plan, as well
as a process for documenting and
tracking the execution of the plan.
(R2)
where a TO is constrained from performing
vegetation work. (R5)
Requires TOs, without any intentional time
delay, to notify the control center holding
switching authority for the associated
applicable line when the TO has confirmed
the existence of a vegetation condition that is
likely to cause a Fault at any moment. (R4)
Requires the TOs annual vegetation
management plan be executed such that no
vegetation encroachments occur within the
MVCD. (R7)
Accordingly, the proposed FAC-003-2 standard should be approved because it
serves the important reliability goal of providing clear, unambiguous standards pertaining
to maintenance of safe clearances of transmission lines from obstructions in the lines’
right-of-way areas – in this case, specifically with regard to vegetation management.
The proposed FAC-003-2 standard was approved by the NERC Board of Trustees
on November 3, 2011.
This petition consists of the following:
•
•
•
•
•
This transmittal letter;
A table of contents for the entire petition;
A narrative description explaining how the proposed Reliability Standard FAC003-2 — Transmission Vegetation Management meets FERC’s requirements;
Reliability Standard FAC-003-2 — Transmission Vegetation Management
submitted for approval (Exhibit A);
Implementation Plan for Reliability Standard FAC-003-2 — Transmission
Vegetation Management submitted for Approval (Exhibit B);
•
•
•
•
•
•
•
Proposed Definitions to be Added to the NERC Glossary of Terms Used in NERC
Reliability Standards (Exhibit C)
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2
summarizing the transition of requirements and related information from FAC003-1 to FAC-003-2 (“Mapping Document”) (Exhibit D)
Consideration of Comments Reports created during the development of
Reliability Standard FAC-003-2 — Transmission Vegetation Management
(Exhibit E);
Analysis of how VRFs and VSLs Were Determined Using FERC Guidelines
(Exhibit F);
The complete development record of the proposed Reliability Standard (Exhibit
G);
The Standard Drafting Team Roster for NERC Standards Development Project
2007-07 Vegetation Management (Exhibit H); and
Transmission Vegetation Management – FAC-003-2 Technical Reference
Document (Exhibit I).
For the reasons stated above and in this petition, NERC respectfully requests that the
Commission approve the standard presented herein for approval.
Respectfully submitted,
/s/ Holly A. Hawkins
Holly A. Hawkins
Assistant General Counsel for North
American Electric Reliability
Corporation
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NORTH AMERICAN ELECTRIC RELIABILITY
CORPORATION
) Docket No. RM-__-000
)
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD
FAC-003-2 — TRANSMISSION VEGETATION MANAGEMENT
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability
Corporation
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326-1001
David N. Cook
Senior Vice President and General Counsel
North American Electric Reliability
Corporation
1120 G Street N.W., Suite 990
Washington, D.C. 20005-3801
[email protected]
Holly A. Hawkins
Assistant General Counsel for Standards
and Critical Infrastructure Protection
Andrew M. Dressel
Attorney
North American Electric Reliability
Corporation
1120 G Street, N.W., Suite 990
Washington, D.C. 20005-3801
(202) 393-3998
(202) 393-3955 – facsimile
[email protected]
[email protected]
December 21, 2011
TABLE OF CONTENTS
I. Introduction
1
II. Executive Summary
3
III. Notices and Communications
8
IV. Background:
9
a. Regulatory Framework
9
b. Basis for Approval of Proposed Reliability Standards
10
c. Reliability Standards Development Procedure
11
V. Justification for Approval of the Proposed Reliability Standard
12
a. Basis and Purpose of Proposed FAC-003-2 — Transmission Vegetation
Management
12
b. Improvements to FAC-003 in this Revision
15
c. Enforceability of the Proposed FAC-003-2 Reliability Standard
33
d. FERC Directives Addressed in the Proposed FAC-003-2 Standard
40
e. Demonstration that the Proposed Reliability Standard is
Just, Reasonable, Not Unduly Discriminatory or Preferential and
In the Public Interest
44
f. Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs)
52
VI. Summary of the Reliability Standard Development Proceedings
a. Development History
60
60
i. SAR Development
61
ii. Overview of the Standard Drafting Team
61
iii. The First Posting
62
iv. The Second Posting
63
i
VII.
v. Transition to Results-Based Format
63
vi. The Third Posting
64
vii. The Fourth Posting and Initial Ballot
65
viii. The Fifth Posting and Successive Ballot
66
ix. The Sixth Posting and Recirculation Ballot
67
x. Board of Trustees Approval
67
Conclusion
68
Exhibit A — Reliability Standard FAC-003-2 — Transmission Vegetation Management submitted
for Approval
Exhibit B — Implementation Plan for Reliability Standard FAC-003-2 — Transmission Vegetation
Management submitted for Approval
Exhibit C — Proposed Terms to be Added to the NERC Glossary of Terms Used in NERC
Reliability Standards
Exhibit D — FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2
Exhibit E — Consideration of Comments Reports Created During the Development of Reliability
Standard FAC-003-2 — Transmission Vegetation Management
Exhibit F — Analysis of how VRFs and VSLs Were Determined Using FERC Guidelines
Exhibit G — Record of Development of Proposed FAC-003-2 — Transmission Vegetation
Management Reliability Standard
Exhibit H — Standard Drafting Team Roster for NERC Standards Development Project 2007-07
Vegetation Management
Exhibit I — Transmission Vegetation Management – FAC-003-2 Technical Reference Document
ii
I.
INTRODUCTION
The North American Electric Reliability Corporation (“NERC”) 4 hereby requests
the Federal Energy Regulatory Commission (“FERC”) to approve, in accordance with
Section 215(d)(1) of the Federal Power Act (“FPA”) 5 and Section 39.5 of FERC’s
regulations, 18 C.F.R. § 39.5, the proposed FAC-003-2 — Transmission Vegetation
Management Reliability Standard approved by the NERC Board of Trustees on
November 3, 2011. The proposed FAC-003-2 Reliability Standard improves reliability
by maintaining a reliable electric transmission system by using a defense-in-depth strategy to
manage vegetation located on transmission rights of way (“ROW”) and by minimizing
encroachments from vegetation located adjacent to the ROW, thus preventing the risk of
those vegetation-related outages that could lead to Cascading. Additionally, the FAC-003-2
standard helps to enhance reliability by improving enforceability of FAC-003-2, as
compared to FAC-003-1, and by providing greater flexibility to NERC registered entities
to address local vegetation management conditions.
By this petition, NERC is requesting approval of the proposed FAC-003-2
Reliability Standard, three proposed NERC Glossary Definitions, Violation Risk Factors
(“VRFs”) and Violation Severity Levels (“VSLs”), the corresponding implementation
plan, and retirement of one currently-effective Reliability Standard. Specifically, NERC
requests approval of the following:
•
approval of Reliability Standard FAC-003-2 — Transmission Vegetation
Management and the associated Violation Risk Factors and Violation Severity
Levels (FAC-003-2), which is included in Exhibit A, effective the first day of
4
NERC has been certified by FERC as the electric reliability organization (“ERO”) in accordance with
Section 215 of the Federal Power Act. FERC certified NERC as the ERO in its order issued July 20, 2006
in Docket No. RR06-1-000. 116 FERC ¶ 61,062 (2006) (“ERO Certification Order).
5
16 U.S.C. 824o (2011).
1
the first calendar quarter that is twelve months following the effective date of
a Final Rule in this docket; 6
•
approval of the implementation plan for Reliability Standard FAC-003-2 —
Transmission Vegetation Management which is included in Exhibit B;
•
approval of three proposed Definitions included in Exhibit C to be added to
the NERC Glossary of Terms Used in NERC Reliability Standards effective
the first day of the first calendar quarter that is twelve months following the
effective date of a Final Rule in this docket:
o Right-of-Way (ROW) – The corridor of land under a transmission
line(s) needed to operate the line(s). The width of the corridor is
established by engineering or construction standards as documented in
either construction documents, pre-2007 vegetation maintenance
records, or by the blowout standard in effect when the line was built.
The ROW width in no case exceeds the Transmission Owner’s legal
rights but may be less based on the aforementioned criteria.
o Vegetation Inspection - The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation conditions under
the Transmission Owner’s control that are likely to pose a hazard to
the line(s) prior to the next planned maintenance or inspection. This
may be combined with a general line inspection.
o Minimum Vegetation Clearance Distance (MVCD) - The calculated
minimum distance stated in feet (meters) to prevent flash-over
between conductors and vegetation, for various altitudes and operating
voltages.
•
approval of the retirement of Reliability Standard FAC-003-1 —
Transmission Vegetation Management Program (FAC-003-1) and the
currently effective definitions of “Right-of-Way” and “Vegetation Inspection”
effective midnight immediately prior to the first day of the first calendar
quarter that is twelve months following the effective date of a Final Rule in
this docket.
The NERC Board of Trustees approved the proposed FAC-003-2 Reliability
Standard on November 3, 2011. Exhibit A to this petition sets forth FAC-003-2
submitted for approval. Exhibit B contains the Implementation Plan for FAC-003-2
submitted for Approval. Exhibit C contains three proposed glossary terms proposed for
6
Because the proposed FAC-003-2 standard has been substantially revised, a redlined version of FAC-0032 is not included in this filing.
2
approval to be added to the NERC Glossary of Terms Used in NERC Reliability
Standards. Exhibit D contains the FAC-003-1 Mapping to Proposed NERC Reliability
Standard FAC-003-2 document (“Mapping Document”) summarizing the transition of
requirements and related information from FAC-003-1 to FAC-003-2. Exhibit E
contains the Consideration of Comments Reports created during the development of the
FAC-003-2 standard. Exhibit F contains an analysis of how VRFs and VSLs were
determined using FERC Guidelines. Exhibit G contains the complete record of
development for FAC-003-2. Exhibit H includes the roster and biographies for the
standard drafting team appointed by the NERC Standards Committee to Project 2007-07 Transmission Vegetation Management, the standard drafting team responsible for
developing FAC-003-2. Exhibit I includes the Transmission Vegetation Management –
FAC-003-2 Technical Reference Document (Appendix 1 to that document discusses the
Gallet Equation).
II.
EXECUTIVE SUMMARY
The proposed FAC-003-2 Reliability Standard represents an improvement over
the currently-effective FAC-003-1 standard because it more clearly defines a defense-indepth strategy to manage vegetation located on transmission ROW to minimize
encroachments from vegetation located adjacent to the ROW, thus reducing the risk of those
vegetation-related outages that could lead to Cascading. The proposed FAC-003-2
Reliability Standard presents three themes that all help to improve reliability. First,
reliability will be improved with implementation of the new standard. Second,
enforceability of FAC-003-2, as compared to FAC-003-1, will be improved and cleaner
for NERC and the Regional Entities. And third, NERC registered entities will have
greater flexibility to address local vegetation management conditions.
3
The general improvements compared to the previous version of the standard are
shown in the table below:
Requirement in Existing
FAC-003-1 Standard
Improvements in Proposed
FAC-003-2 Standard
Requires a document that includes
vegetation management objectives,
approved procedures, and work
specifications. (R1)
Requires documented vegetation management
maintenance strategies, procedures, processes,
or specifications that will prevent
encroachment into the Minimum Vegetation
Clearance Distance (MVCD) (R3)
Requires a document schedule for
ROW vegetation inspections. (R1.1)
Requires vegetation inspection of 100% of
applicable transmission lines at least once per
calendar year. (R6)
Requires documentation of a
“Clearance 1” value based on TO
assessment of situation and risk. (R1.2
and R1.2.1)
Requires vegetation be managed such that no
encroachments into the MVCD (as
established by the Gallet Equation) occur,
regardless of whether or not they result in a
sustained outage. (R3, parts 3.1 and 3.2)
Requires documentation of a
“Clearance 2” value based on IEEE
standard. (R1.2.2, R1.2.2.1, and
R1.2.2.2)
Requires vegetation be managed such that no
encroachments into the MVCD (as
established by the Gallet Equation) occur,
regardless of whether or not they result in a
sustained outage. (R1 and R2)
Requires documentation of mitigation
measures to address locations on the
on the ROW where the TO is
restricted from attaining specified
clearances. (R1.4)
Requires documentation of a process
for communicating imminent threats
where vegetation conditions could lead
to a transmission line outage. (R1.5)
Requires corrective action to be taken in cases
where a TO is constrained from performing
vegetation work. (R5)
Requires the creation and
implementation of an annual
vegetation management plan, as well
as a process for documenting and
tracking the execution of the plan.
(R2)
Requires TOs, without any intentional time
delay, to notify the control center holding
switching authority for the associated
applicable line when the TO has confirmed
the existence of a vegetation condition that is
likely to cause a Fault at any moment. (R4)
Requires the TOs annual vegetation
management plan be executed such that no
vegetation encroachments occur within the
MVCD. (R7)
4
In Order No. 693, FERC identified shortcomings of the currently-effective FAC003-1 standard, which have been addressed in this proposed version. 7 Additionally,
FERC in its Order indicated the IEEE Standard 516-2003, upon which the previous
standard was based, was “intended for use as a guide by highly-trained maintenance
personnel to carry out live-line work using specialized tools under controlled
environments and operating conditions, not for those conditions necessary to safely carry
out vegetation management practices.” 8 Further, the Commission stated “use of IEEE
clearance provision as a basis for minimum clearance prior to the next tree trimming as a
Requirement in vegetation management is not appropriate for safety and reliability
reasons,” and directed NERC to develop a Reliability Standard that defines the minimum
clearance needed to avoid sustained vegetation-related outages. 9
Because of the direction provided by FERC in Order No. 693 relative to the use of
IEEE Standard 516-2003, the proposed FAC-003-2 Reliability Standard no longer
utilizes the IEEE clearance provisions. The standard now requires minimum clearance
distances derived from the Gallet Equation. There were four potential methods
considered for use in the standard to derive flash-over distances for various voltages and
altitudes. While each of the methods are expected to provide similar results, 10 the Gallet
method was selected because Gallet method information to support the development of
the standard was readily available in an industry recognized reference. This method
7
Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶
31,242 (2007), order on reh’g Order No. 693-A, 120 FERC ¶ 61,053 (2007)(“Order No. 693”) at PP 731
and 732.
8
Id.
9
Id.
10
EPRI, at its Lenox facility, is currently growing trees on a high voltage right-of-way test plot that will be
ready for testing by the summer of 2013. These will be the first known field tests of energized high voltage
conductor flash-over to vegetation. The results of those tests may be useful to the industry for future
reviews of this NERC Standard.
5
allows clearance distance values for a given voltage to be derived for wet conditions at
various altitudes. The distances derived using the Gallet Equation result in the probability
of flashover in the range of 10-6. This approach was used to design of some of the first
500 kV and 765 kV lines in North America. 11
Additionally, this standard continues to provide the Transmission Owner with
flexibility when determining the appropriate degree of vegetation removal. Similar to
FAC-003-1, in which the Transmission Owner was given the authority to “determine and
document appropriate clearance distances to be achieved at the time of transmission
vegetation management work based upon local conditions and the expected time frame in
which the Transmission Owner plans to return for future vegetation management work,”
FAC-003-2 provides the Transmission Owner the necessary discretion to determine how
to manage vegetation. FAC-003-2 continues to allow Transmission Owners the ability to
exercise their full legal rights without mandating any specific strategy or incorporating an
arbitrary margin into the requirements of the standard absent specific knowledge of the
actual conditions in the field.
Despite this flexibility, FAC-003-2 is actually more stringent than FAC-003-1.
Essentially, with the new Requirements R1 and R2, FAC-003-2 presents a “zerotolerance” approach to vegetation management, explicitly treating any encroachment into
the MVCD (without contact, with a flashover, with a momentary outage, or with a
sustained outage) as a violation of the standard. The standard also requires annual
inspections (which go beyond what is required in FAC-003-1) and is much more explicit
regarding what actions must be taken to support vegetation management and reliability.
11
Andrew Hileman, Insulation Coordination for Power System, Marcel Dekker, New York, NY 1999.
6
FAC-003-2 is also one of the first standards developed using NERC’s new
“results- based” approach and format. Each requirement meets one or more specific
approaches (performance-based, risk-based, or competency-based) to achieving results,
and the measures associated with each requirement have been developed to ensure that
compliance with the standard can be verified. In addition to focusing on completing
objectives, achieving goals, and meeting needs (three of the hallmarks of a results-based
standard), FAC-003-2 identifies clear and objective measures for compliance, so that it
can be enforced in a consistent and non-preferential manner. The standard also includes
detailed background information and supporting documentation, making the requirements
easier to comprehend and providing the rationale used by the drafting team for
establishing the requirements.
As a results-based standard, there are some noticeable changes in the manner in
which the requirements for the standard are structured. One of the most obvious is the
replacement of Requirement R1 from FAC-003-1 with several new requirements in FAC003-2. Requirement R1 from FAC-003-1 requires the Transmission Owner to have a
formal Transmission Vegetation Management Plan (“TVMP”) that includes several
specific items. In FAC-003-2, the majority of the specific items have been extracted
from the pages of the TVMP and made into explicit, actionable requirements. The
requirement for the TVMP itself has been removed from the standard.
The TVMP required by FAC-003-1 was a good vehicle for ensuring that all key
elements of vegetation management were considered as part of a Transmission Owner’s
overall vegetation management strategy. However, the drafting team that developed
FAC-003-2 determined there were equally (or, in some cases more,) effective ways to
7
ensure key vegetation management issues are addressed. Accordingly, the drafting team
developed FAC-003-2 using results-based approaches that focused on what actions
needed to be taken, as opposed to how documentation supporting vegetation management
should be assembled. This resulted in a standard that ensures requirements are
measureable and enforceable while providing significantly more flexibility than the
previous standard. A detailed discussion of how the requirements in version one of the
standard have been transitioned to version two of the standard is included below.
NERC believes FAC-003-2 will continue to provide the means by which the
industry can demonstrate its commitment to reliability and vegetation management
excellence. Moreover, by allowing more diverse approaches through the flexibility
inherent in the new results-based requirements, FAC-003-2 correctly focuses on
providing the industry the latitude it needs to meet the performance objectives important
to reliability. The industry as a whole recognizes the importance of vegetation
management. Like the previous version of the standard, FAC-003-2 is a channel through
which the industry can measurably demonstrate that recognition. As such, NERC
expects the current industry performance of vegetation management to continue or
improve under FAC-003-2.
Additionally, there are more improvements that have been incorporated into
proposed FAC-003-2 standard that are further detailed in the later sections of this
petition.
III.
NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the
following:
8
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability
Corporation
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326-1001
David N. Cook*
Senior Vice President and General Counsel
North American Electric Reliability
Corporation
1120 G Street N.W., Suite 990
Washington, D.C. 20005-3801
[email protected]
Holly A. Hawkins*
Assistant General Counsel for Standards
and Critical Infrastructure Protection
Andrew M. Dressel*
Attorney
North American Electric Reliability
Corporation
1120 G Street, N.W., Suite 990
Washington, D.C. 20005-3801
(202) 393-3998
(202) 393-3955 – facsimile
[email protected]
[email protected]
*Persons to be included on FERC’s service list are
indicated with an asterisk. NERC requests waiver of
FERC’s rules and regulations to permit the inclusion of
more than two people on the service list.
IV.
BACKGROUND
a. Regulatory Framework
By enacting the Energy Policy Act of 2005, 12 Congress entrusted FERC with the
duties of approving and enforcing rules to ensure the reliability of the Nation’s bulk
power system, and with the duties of certifying an electric reliability organization ((ERO)
that would be charged with developing and enforcing mandatory Reliability Standards,
subject to FERC approval. Section 215 of the FPA states that all users, owners, and
operators of the bulk power system in the United States will be subject to FERCapproved Reliability Standards.
Section 215(d)(5) of the FPA authorizes FERC to order the ERO to submit a new
or modified Reliability Standard. However, it does not negate the requirements in
12
16 U.S.C. § 824o (2011).
9
Section 215(c)(2)(D) the ERO must use to develop that standard—that is, “a process that
provides for reasonable notice and opportunity for public comment, due process,
openness, and balance of interests.” Pursuant to Section 215(d)(2) of the FPA and
Section 39.5(c) of FERC’s regulations, FERC will give due weight to the technical
expertise of the ERO with respect to the content of a Reliability Standard. In Order No.
693, FERC noted that it would defer to the “technical expertise” of the ERO with respect
to the content of a Reliability Standard and explained that, through the use of directives,
it provides guidance but does not dictate an outcome. Rather, it will consider an
equivalent alternative approach provided that the ERO demonstrates that the alternative
will address FERC’s underlying concern or goal as efficiently and effectively as FERC’s
proposal, example, or directive. 13
b. Basis for Approval of Proposed Reliability Standards
13
See, e.g., the following paragraphs from Order No. 693: P 31. We emphasize that we are not, at this
time, mandating a particular outcome by way of these directives, but we do expect the ERO to respond with
an equivalent alternative and adequate support that fully explains how the alternative produces a result that
is as effective as or more effective that FERC’s example or directive. . .; P 186. Thus, in some instances,
while we provide specific details regarding the Commission’s expectations, we intend by doing so to
provide useful guidance to assist in the Reliability Standards development process, not to impede it.[] We
find that this is consistent with statutory language that authorizes FERC to order the ERO to submit a
modification “that addresses a specific matter” if FERC considers it appropriate to carry out Section 215 of
the FPA.[] In the Final Rule, we have considered commenters’ concerns and, where a directive for
modification appears to be determinative of the outcome, FERC provides flexibility by directing the ERO
to address the underlying issue through the Reliability Standards development process without mandating a
specific change to the Reliability Standard. Further, FERC clarifies that, where the Final Rule identifies a
concern and offers a specific approach to address the concern, we will consider an equivalent alternative
approach provided that the ERO demonstrates that the alternative will address FERC’s underlying concern
or goal as efficiently and effectively as FERC’s proposal; P 187. Consistent with Section 215 of the FPA
and our regulations, any modification to a Reliability Standard, including a modification that addresses a
Commission directive, must be developed and fully vetted through NERC’s Reliability Standards
Development Process. FERC’s directives are not intended to usurp or supplant the Reliability Standard
development procedure. Further, this allows the ERO to take into consideration the international nature of
Reliability Standards and incorporate any modifications requested by our counterparts in Canada and
Mexico. Until the Commission approves NERC’s proposed modification to a Reliability Standard, the
preexisting Reliability Standard will remain in effect.
10
Section 39.5(a) of FERC’s regulations requires the ERO to file with FERC for its
approval each Reliability Standard that the ERO proposes to become mandatory and
enforceable in the United States, and each modification to a Reliability Standard that the
ERO proposes to be made effective. FERC has the regulatory responsibility to approve
standards that protect the reliability of the bulk power system. In discharging its
responsibility to review, approve, and enforce mandatory Reliability Standards, FERC is
authorized to approve those proposed Reliability Standards that meet the criteria detailed
by Congress:
[FERC] may approve, by rule or order, a proposed reliability standard or
modification to a reliability standard if it determines that the standard is just,
reasonable, not unduly discriminatory or preferential, and in the public interest.
Order No. 672 provides guidance on the factors FERC will consider when
determining whether proposed Reliability Standards meet the statutory criteria. Each of
those factors is addressed below in Section V.a.
c. Reliability Standards Development Procedure
NERC develops Reliability Standards in accordance with Section 300 (Reliability
Standards Development) of its Rules of Procedure and the NERC Standard Processes
Manual. 14 In its ERO Certification Order, FERC found that NERC’s proposed rules
provide for reasonable notice and opportunity for public comment, due process,
openness, and a balance of interests in developing Reliability Standards and thus satisfies
certain of the criteria for approving Reliability Standards. The development process is
open to any person or entity with a legitimate interest in the reliability of the bulk power
14
FERC approved the new Standard Processes Manual on September 3, 2010 (FERC Docket No. RR1012-000), which replaces the Reliability Standards Development Procedure Version 7 in its entirety. Both
the Reliability Standards Development Procedure Version 7 and, when it was approved, the Standard
Processes Manual, were used to develop the proposed FAC-003-2 Reliability Standard.
11
system. NERC considers the comments of all stakeholders, and a vote of stakeholders
and the NERC Board of Trustees is required to approve a Reliability Standard before the
Reliability Standard is submitted to FERC for approval. FAC-003-2 was approved by the
NERC Board of Trustees on November 3, 2011.
V.
JUSTIFICATION FOR APPROVAL OF THE PROPOSED RELIABILITY
STANDARD
This section summarizes the development of the proposed FAC-003-2 Reliability
Standard, describes the reliability objectives to be achieved by the standard, explains the
development history of the standard, and documents how the standard meets the criteria
for approval set by FERC. NERC, in its analysis of the proposed standard, determined
that it is just, reasonable, not unduly discriminatory or preferential, and in the public
interest.
The final discussion in this section provides the stakeholder ballot results and
explains how other key issues were considered and addressed by the Standard Drafting
Team.
a. Basis and Purpose of Reliability Standard FAC-003-2 —
Transmission Vegetation Management
The primary purpose of the proposed FAC-003-2 standard is to maintain a reliable
electric transmission system by using a defense-in-depth strategy to manage vegetation
located within a transmission ROW and minimize encroachments from vegetation not
located on a ROW, thus reducing the risk of vegetation-related outages that could lead to
Cascading, uncontrolled separation, or instability. Major outages and operational
problems have resulted from contact between vegetation and transmission lines located
on many types of lands and reflecting many ownership situations. FAC-003-2 is
12
primarily applicable to overhead transmission lines operated at 200 kV or higher,
overhead transmission lines operated below 200 kV identified by the Planning
Coordinator as an element of an Interconnection Reliability Operating Limit (“IROL”)
under NERC Reliability Standard FAC-014, and overhead transmission lines operated
below 200 kV identified as a Major Western Electricity Coordinating Council (“WECC”)
Transfer Path in the Bulk Electric System by WECC to prevent those vegetation-related
outages that could lead to Cascading. Because vegetation growth is continual and always
present, unmanaged vegetation poses an increasing outage risk over time. If vegetation is
not properly managed to avoid encroachments, a contact will eventually occur that could
result in a sustained outage.
The proposed FAC-003-2 standard includes seven requirements. The
requirements are summarized below.
Requirement R1 requires that the Transmission Owner must manage vegetation
to prevent encroachments into the MVCD for all lines associated with IROLs and
Major WECC Transfer Paths. It provides specific types of encroachments that
must be avoided.
Requirement R2 requires that the Transmission Owner must manage vegetation
to prevent encroachments into the MVCD for all other transmission lines that are
applicable under this standard. It also provides specific types of encroachments
that must be avoided.
Requirement R3 requires the Transmission Owner to have documentation
describing its chosen approach(es) for managing vegetation. The approach must
consider the movement of the conductor, as well as growth rate, control method,
and inspection frequency.
Requirement R4 mandates that when a Transmission Owner has observed a
vegetation condition that is likely to produce a Fault, it must notify the control
center with switching authority for that transmission line of the condition.
Requirement R5 specifies that a Transmission Owner constrained from
performing vegetation management work must take corrective actions to prevent
encroachments that would put the line at risk.
13
Requirement R6 states that the Transmission Owner must inspect 100% of its
applicable lines at least once per calendar year, with no more than 18 months
between inspections.
Requirement R7 requires that the Transmission Owner must complete 100% of
its annual vegetation work plan for applicable lines. It provides for documented
modifications to the plan (some of which are listed as examples in the
requirement), provided that such modifications do not allow encroachment of
vegetation into the MVCD.
The proposed standard presents a comprehensive approach to vegetation
management by using three types of requirements to provide a defense-in-depth structure
to reduce the likelihood of vegetation-related outages that could lead to Cascading:
•
Performance-based requirements, which define a particular reliability objective
or outcome to be achieved. Requirements R1 and R2 are performance-based
requirements.
•
Risk-based requirements, which are preventive requirements to reduce the risks
of failure to acceptable tolerance levels. Requirements R4, R5, R6, and R7 are
risk-based requirements.
•
Competency-based requirements, which define a minimum set of capabilities
an entity needs to have to demonstrate it is able to perform its designated
reliability functions. Requirement R3 is a competency-based requirement.
The defense-in-depth strategy for reliability standards development recognizes
that each requirement in a reliability standard has a role in reducing the risk of system
failures, and that these roles are complementary and reinforcing. This standard uses a
defense-in-depth approach to maintain the reliability of the electric transmission system
by:
•
Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash-over clearance (MVCD) (Requirements R1 and R2);
•
Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over
conditions including consideration of 1) conductor movement , and 2) the
14
interrelationships between vegetation growth rates, control methods and the
inspection frequency (Requirement R3);
•
Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash-over at any moment (Requirement R4);
•
Requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains such as legal injunctions (Requirement R5);
•
Requiring inspections of vegetation conditions to be performed annually
(Requirement R6); and
•
Requiring that the annual work needed to prevent flash-over is completed
(Requirement R7).
Requirement R3 serves as the first line of defense in maintaining the reliability of
the electric transmission system by ensuring that entities understand the problem they are
trying to manage and have fully developed strategies and plans to manage the problem.
Requirements R1, R2, and R7 serve as the second line of defense by requiring that
entities carry out their plans and manage vegetation. Requirement R6, which requires
inspections, is both a part of the first line of defense (as input into the strategies and
plans) or as a third line of defense (as a check of the first and second lines of defense).
Requirement R4 serves as the final line of defense, as it addresses cases in which all the
other lines of defense have failed.
b. Improvements to FAC-003 in this Revision
The currently-effective FAC-003-1 Reliability Standard includes four
requirements. As discussed above, the proposed FAC-003-2 standard includes seven
requirements, which together present a comprehensive approach to vegetation
management using a defense-in-depth strategy. The following paragraphs explain the
changes made and how the new standard improves reliability when compared to the
15
existing standard. A summary of the following paragraphs is contained in the FAC-003-1
Mapping to Proposed NERC Reliability Standard FAC-003-2 document provided in
Exhibit D.
FAC-003-1, Requirement R1
Requirement R1 of the currently-effective FAC-003-1 reads as follows:
R1 The Transmission Owner shall prepare, and keep current, a formal
transmission vegetation management program (TVMP). The TVMP shall include
the Transmission Owner’s objectives, practices, approved procedures, and work
specifications.
This requirement has been replaced by requirement R3 in the proposed FAC-0032 standard, which reads:
R3 Each Transmission Owner shall have documented maintenance strategies or
procedures or processes or specifications it uses to prevent the encroachment of
vegetation into the MVCD of its applicable lines that include(s) the following:
Requirement R3 of FAC-003-2 is functionally equivalent to Requirement R1 of
FAC-003-1, but offers several improvements.
Requirement R1 of FAC-003-1 mandates the preparation and maintenance of a
TVMP. However, the Measure for Requirement R1 refers to having a “documented
TVMP,” which is not consistent with the requirement itself (with the exception of R1.2,
which does require the creation of documentation). The sub-requirements of R1 (which
are discussed further in later paragraphs) also refer in some cases to having
documentation but in other cases as characteristics.
Requirement R3 of FAC-003-2 corrects these inconsistencies by requiring each
Transmission Owner to have documented records indicating the way the entity prevents
the encroachment of vegetation into the MVCD of its applicable lines. The proposed
requirement is clear and unambiguous. The measure is consistent with the requirement,
16
and clearly indicates that documents are required to demonstrate compliance, and that the
documents must be sufficiently clear and complete to show that the entity can meet its
obligations when considering the factors specified in the sub-requirements (discussed
further in later paragraphs).
Additionally, the new requirement is written in a manner that provides additional
flexibility. While the version one requirement mandates the inclusion of “objectives,
practices, approved procedures, and work specifications,” the new standard requires
“documented maintenance strategies or procedures or processes or specifications.” This
new wording using the coordinating conjunction “or” ensures that Transmission Owners
are not required to convert their existing approaches into any particular format simply for
the sake of meeting a requirement. Rather, the Transmission Owner is given the
discretion to determine how best to prevent the encroachment of vegetation into the
MVCD. This could be through the use of a specification (e.g., values analogous to the
version one concept of “Clearance 1”), or through any of the other approaches (such as an
overall strategy to remove all vegetation from within the Right of Way). This
modification allows for the use of valid approaches that might have been considered
unacceptable under the previous, more prescriptive language in version one of the
standard.
FAC-003-1, Sub-requirement R1.1
Sub-requirement R1.1 of the currently-effective FAC-003-1 reads as follows:
R1.1 The TVMP shall define a schedule for and the type (aerial, ground) of ROW
vegetation inspections. This schedule should be flexible enough to adjust for
changing conditions. The inspection schedule shall be based on the anticipated
growth of vegetation and any other environmental or operational factors that
could impact the relationship of vegetation to the Transmission Owner’s
transmission lines.
17
This sub-requirement has been replaced by Requirement R6 in the proposed FAC003-2, which reads:
R6. Each Transmission Owner shall perform a Vegetation Inspection of 100% of
its applicable transmission lines (measured in units of choice - circuit, pole line,
line miles or kilometers, etc.) at least once per calendar year and with no more
than 18 calendar months between inspections on the same ROW.
Requirement R6 of FAC-003-2 is similar to sub-requirement R1.1 of FAC-003-1,
but offers several improvements.
Sub-requirement R1.1 of FAC-003-1 requires the creation of an inspection
schedule, and specifies criteria against which a schedule can be judged for completeness.
However, it does not mandate that entities implement the schedule and perform the
inspections. The measure for R1.1 indicates that the entity must have performed the
inspections.
As an improvement to the standard that reduces risks, Requirement R6 of FAC003-2 specifically requires the Transmission Owner to inspect 100% of its applicable
lines at least once per calendar year. The proposed Requirement R6 is clear and
unambiguous. The measure is consistent with the requirement, and clearly indicates that
evidence of performance is required to demonstrate compliance. Examples of acceptable
evidence are provided, such as completed and dated work orders, dated invoices, or dated
inspection records.
FAC-003-1, Sub-requirements R1.2 and R 1.2.1
Sub-requirements R1.2 and R1.2.1 of the currently-effective FAC-003-1 standard
reads as follows:
R1.2. The Transmission Owner, in the TVMP, shall identify and document
clearances between vegetation and any overhead, ungrounded supply conductors,
18
taking into consideration transmission line voltage, the effects of ambient
temperature on conductor sag under maximum design loading, and the effects of
wind velocities on conductor sway. Specifically, the Transmission Owner shall
establish clearances to be achieved at the time of vegetation management work
identified herein as Clearance 1, and shall also establish and maintain a set of
clearances identified herein as Clearance 2 to prevent flashover between
vegetation and overhead ungrounded supply conductors.
R1.2.1. Clearance 1 — The Transmission Owner shall determine and
document appropriate clearance distances to be achieved at the time of
transmission vegetation management work based upon local conditions
and the expected time frame in which the Transmission Owner plans to
return for future vegetation management work. Local conditions may
include, but are not limited to: operating voltage, appropriate vegetation
management techniques, fire risk, reasonably anticipated tree and
conductor movement, species types and growth rates, species failure
characteristics, local climate and rainfall patterns, line terrain and
elevation, location of the vegetation within the span, and worker approach
distance requirements. Clearance 1 distances shall be greater than those
defined by Clearance 2 below.
Sub-requirements R1.2 and R 1.2.1 of FAC-003-1 have been replaced by
Requirement R3, parts 3.1 and 3.2, in FAC-003-2, which reads:
R3 Each Transmission Owner shall have documented maintenance strategies or
procedures or processes or specifications it uses to prevent the encroachment of
vegetation into the MVCD of its applicable lines that accounts for the following
R3.1 Movement of applicable line conductors under their Rating and all
Rated Electrical Operating Conditions;
R3.2 Inter-relationships between vegetation growth rates, vegetation
control methods, and inspection frequency.
The proposed Requirement R3 and parts 3.1 and 3.2 are functionally equivalent to
the Version 1 Sub-requirement R1.2 and R1.2.1.
In summary, FAC-003-1, sub –requirements R1.2 and 1.2.1 establish a variable
clearance distance (Clearance 1) to which the Transmission Owner must manage in order
to avoid encroachments that might occur due to local conditions or time between
vegetation management actions. The standard does not mandate an explicit value or
19
mathematical calculation to determine Clearance 1, relying on the judgment of the
Transmission Owner to determine this value, with the only criterion for acceptance being
that Clearance 1 must be some undefined amount larger than the minimum flashover
distance.
Requirement 3, parts 3.1 and 3.2 of FAC-003-2 provide the same flexibility as the
currently-effective standard. While the proposed standard does not explicitly identify a
“Clearance 1,” it continues to give the Transmission Owner the responsibility for
avoiding encroachments by requiring the Transmission Owner to consider, among other
things, conductor movement, vegetation growth rates, vegetation control methods, and
inspection frequency in their documented maintenance strategies, procedures, processes,
or specifications to prevent the encroachment of vegetation into the MVCD. In effect,
the standard still retains the same obligations defined by “Clearance 1,” but does not
require the documentation of a specific numerical value. Instead, it offers alternative
ways to specify how the reliability objective of this requirement will be met. The
standard allows for entities (if they so choose) to retain the concept of a “Clearance 1” as
part of the specifications they use to manage vegetation; however, it does not require it.
Instead, entities can define their methods for meeting the reliability objective through
process, procedures, specifications, or strategy documents (or any combination of those
elements).
FAC-003-1, Sub-requirements R1.2.2, R1.2.2.1, and R.1.2.2.2
Sub-requirements R1.2.2, R1.2.2.1, and R.1.2.2.2 of FAC-003-1 read as follows:
R1.2.2. Clearance 2 — The Transmission Owner shall determine and document
specific radial clearances to be maintained between vegetation and conductors
20
under all rated electrical operating conditions. These minimum clearance
distances are necessary to prevent flashover between vegetation and conductors
and will vary due to such factors as altitude and operating voltage.
These Transmission Owner-specific minimum clearance distances shall be no less
than those set forth in the Institute of Electrical and Electronics Engineers (IEEE)
Standard 516-2003 (Guide for Maintenance Methods on Energized Power Lines)
and as specified in its Section 4.2.2.3, Minimum Air Insulation Distances without
Tools in the Air Gap.
R1.2.2.1 Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 516-2003, phaseto-ground distances, with appropriate altitude correction factors applied.
R1.2.2.2 Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 516-2003, phaseto-phase voltages, with appropriate altitude correction factors applied.
Sub-requirements R1.2.2, R1.2.2.1, and R.1.2.2.2 of FAC-003-1 have been
replaced by Requirements R1 and R2 of FAC-003-2, which read:
R1. Each Transmission Owner shall manage vegetation to prevent
encroachments into the MVCD of its applicable line(s) which are either an
element of an IROL, or an element of a Major WECC Transfer Path; operating
within its Rating and all Rated Electrical Operating Conditions of the types
shown below [Violation Risk Factor: High] [Time Horizon: Real-time]:
1.
An encroachment into the MVCD as shown in FAC-003-Table 2,
observed in Real-time, absent a Sustained Outage
R2. Each Transmission Owner shall manage vegetation to prevent encroachments
into the MVCD of its applicable line(s) which are not either an element of an
IROL, or an element of a Major WECC Transfer Path; operating within its Rating
and all Rated Electrical Operating Conditions of the types shown below
[Violation Risk Factor: Medium] [Time Horizon: Real-time]:
1.
An encroachment into the MVCD as shown in FAC-003-Table 2,
observed in Real-time, absent a Sustained Outage,
Requirements R1 and R2 of FAC-003-2 are similar to sub-requirements R1.2.2,
R1.2.2.1, and R.1.2.2.2 of FAC-003-1, but offer several improvements.
21
Sub-requirements R1.2.2, R1.2.2.1, and R1.2.2.2 of FAC-003-1 direct the
specification of a “Clearance 2,” but do not require entities to ensure that vegetation does
not encroach within that clearance, or take any action related to actually manage
vegetation, other than specifying the value. The measure for R1.2 is consistent with the
requirement in that it only measures whether the entity documented the establishment of
“Clearance 2.” Therefore, the requirement and the measure provide limited value to
reliability, as they are primarily designed only to ensure that the entity knows the
flashover distance, not take action related to it.
Requirements R1 and R2 of FAC-003-2 significantly expand sub-requirements
R1.2.2, R1.2.2.1, and R.1.2.2.2 of FAC-003-1 by requiring Transmission Owners to
manage vegetation to prevent encroachments, with a violation occurring upon the
observation of an encroachment into the MVCD. This effectively duplicates the concept
of “Clearance 2,” but requires actual vegetation management rather than documentation
of the clearance. Additionally, the standard replaces the use of IEEE Standard 516-2003
(identified by the Commission in Order No. 693 as not appropriate for reliability
purposes) with the use of the Gallet Equation to determine the MVCD. The Gallet
Equation is an established method for calculating the flashover distance for various
voltages, altitudes, and atmospheric conditions. This provides calculated flashover
distances between transmission conductors and vegetation that better represent the
conditions that occur on the transmission corridor.
Finally, in order to eliminate commingling of higher risk reliability objectives and
lesser risk reliability objectives (as discussed in the FERC May 18, 2007 Order on
22
Violation Risk Factors 15) the proposed standard separates the concept and objective
selected in the “Clearance 2” value into two distinct requirements – those that are related
to lines that are either an element of an IROL or an element of a Major WECC Transfer
Path (Requirement R1), and those that are not (Requirement R2). This expands the
coverage of the standard to those facilities essential to the reliable operation of the bulk
electric system and helps ensure that entities properly manage the risk to reliability
associated with specific actions.
It is important to note that there are conditions or scenarios that may lead to
encroachments outside the Transmission Owner's control. Accordingly, the requirements
include a footnote that clarifies such conditions or scenarios. This footnote does not
exempt the Transmission Owner from responsibility for encroachments caused by
activities performed by their own employees or contractors, but it does exempt them from
responsibility when other human activities, animal activities, or other environmental
conditions outside their control lead to an encroachment that otherwise would not have
occurred.
FAC-003-1, Sub-requirement R1.3
Sub-requirement R1.3 of FAC-003-1 reads as follows:
R1.3 All personnel directly involved in the design and implementation of the
TVMP shall hold appropriate qualifications and training, as defined by the
Transmission Owner, to perform their duties.
The concepts from this sub-requirement have been eliminated from the proposed
standard because it is unclear what “appropriate” qualifications are or how an entity
15
North American Electric Reliability Corporation, Order on Violation Risk Factors, 119 FERC ¶ 61,145
(2007).
23
would determine them to be “appropriate.” More importantly, as the definition of
“appropriate” is established entirely by the entity that is subject to compliance with the
standards, the requirement is effectively meaningless – a conceptually equivalent
translation of the requirement is “the entity shall do what the entity decides to do.” Given
the shortcomings in the current language, and the difficulty in establishing objective but
non-prescriptive criteria relative to training for this particular requirement, the concepts
were not carried forward to the proposed standard. This elimination has no impact on the
level of reliability under the proposed standard relative to the current standard.
FAC-003-1, Sub-requirement R1.4
Sub-requirement R1.4 of FAC-003-1 reads as follows:
R1.4 Each Transmission Owner shall develop mitigation measures to achieve
sufficient clearances for the protection of the transmission facilities when it
identifies locations on the ROW where the Transmission Owner is restricted from
attaining the clearances specified in Requirement 1.2.1.
Sub-requirement R1.4 of FAC-003-1 has been replaced by Requirement R5 of
FAC-003-2, which reads:
R5. When a Transmission Owner is constrained from performing vegetation work
on applicable transmission lines operating within their Rating and all Rated
Electrical Operating Conditions, and the constraint may lead to a vegetation
encroachment into the MVCD prior to the implementation of the next annual work
plan, then the Transmission Owner shall take corrective action to ensure
continued vegetation management to prevent encroachments
Requirement R5 of FAC-003-2 is similar to the sub-requirement R1.4 of FAC003-1, but offers several improvements.
Sub-requirement R1.4 of FAC-003-1 requires the creation of mitigation measures
to address locations on the Right-of-Way where the Transmission Owner is restricted
from attaining the specified clearances. However, it does not mandate that entities
24
implement mitigation measures. The measure for R1.4 indicates that the entity must have
documented the locations identified on the Right-of-Way where the Transmission Owner
was restricted from attaining the specified clearances. The measure also requires the
documentation of the mitigation measures taken, which is inconsistent with the
requirement.
Requirement R5 of FAC-003-2 specifically requires corrective action to be taken
in cases where a Transmission Owner is constrained from performing vegetation work
such that the constraint may lead to a vegetation encroachment into the MVCD prior to
the implementation of the next annual work plan. The proposed requirement is clear and
unambiguous. The measure is consistent with the requirement, and clearly indicates that
evidence of performance is required to demonstrate compliance. Examples of acceptable
evidence are provided, such as initially-planned work orders, documentation of
constraints from landowners, court orders, inspection records of increased monitoring,
documentation of the de-rating of lines, revised work orders, invoices, or evidence that
the line was de-energized.
FAC-003-1, Sub-requirement R1.5
Sub-requirement R1.5 of FAC-003-1 reads as follows:
R1.5. Each Transmission Owner shall establish and document a process for the
immediate communication of vegetation conditions that present an imminent
threat of a transmission line outage. This is so that action (temporary reduction in
line rating, switching line out of service, etc.) may be taken until the threat is
relieved.
Sub-requirement R1.5 of FAC-003-1 has been replaced by requirement R4 of
FAC-003-2, which reads:
R4. Each Transmission Owner, without any intentional time delay, shall notify the
control center holding switching authority for the associated applicable line when
25
the Transmission Owner has confirmed the existence of a vegetation condition
that is likely to cause a Fault at any moment.
Requirement R4 of FAC-003-2 is similar to sub-requirement R1.5 of FAC-003-1,
but offers several improvements.
Sub-requirement R1.5 of FAC-003-1 requires the creation of a process for
communicating imminent threats where vegetation conditions could lead to a
transmission line outage. However, it does not mandate that entities implement the
process and communicate the threat. The measure for R1.5 indicates that the entity must
have documentation of their process. This is consistent with the requirement; however,
the requirement and the measure only provide limited value to reliability, as they are
primarily designed only to ensure that the entity has a process, not take action related to
the process.
Requirement R4 of FAC-003-2 requires Transmission Owners, without any
intentional time delay, to notify the control center holding switching authority for the
associated applicable line when the Transmission Owner has confirmed the existence of a
vegetation condition that is likely to cause a Fault at any moment. The proposed
requirement is clear and unambiguous. The measure is consistent with the requirement,
and clearly indicates that evidence of performance is required to demonstrate compliance.
Examples of acceptable evidence are provided, such as control center logs, voice
recordings, switching orders, clearance orders, and subsequent work orders.
The proposed requirement is clear and unambiguous. The proposed standard
replaces the term “immediate,” which is impractical at best, with the phrase “without any
intentional time delay.” The use of “without any intentional time delay” still requires
timely notification, but addresses situations where “immediate” communication is
26
impossible or impractical (for example, when an observer is in a remote area without cell
phone service). The new language correctly focuses on the desire to communicate in a
timely fashion, without attempting to draw any arbitrary deadlines or include impractical
absolutes.
FAC-003-1, Requirement R2
Requirement R2 of FAC-003-1 reads as follows:
R2. The Transmission Owner shall create and implement an annual plan for
vegetation management work to ensure the reliability of the system. The plan
shall describe the methods used, such as manual clearing, mechanical clearing,
herbicide treatment, or other actions. The plan should be flexible enough to adjust
to changing conditions, taking into consideration anticipated growth of vegetation
and all other environmental factors that may have an impact on the reliability of
the transmission systems. Adjustments to the plan shall be documented as they
occur. The plan should take into consideration the time required to obtain
permissions or permits from landowners or regulatory authorities. Each
Transmission Owner shall have systems and procedures for documenting and
tracking the planned vegetation management work and ensuring that the
vegetation management work was completed according to work specifications.
Requirement R2 of FAC-003-1 has been replaced by requirement R7 of FAC003-2, which reads:
R7. Each Transmission Owner shall complete 100% of its annual vegetation work
plan of applicable lines to ensure no vegetation encroachments occur within the
MVCD. Modifications to the work plan in response to changing conditions or to
findings from vegetation inspections may be made (provided they do not allow
encroachment of vegetation into the MVCD) and must be documented. The
percent completed calculation is based on the number of units actually completed
divided by the number of units in the final amended plan (measured in units of
choice - circuit, pole line, line miles or kilometers, etc.) Examples of reasons for
modification to annual plan may include
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of a Transmission Owner
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
27
•
•
Land ownership changes/Change in land use by the landowner
Emerging technologies
Requirement R7 of FAC-003-2 is similar to Requirement R2 of FAC-003-1.
Requirement R2 of the existing FAC-003-1 standard requires the creation and
implementation of an annual vegetation management plan and a process for documenting
and tracking the execution of the plan. However, it does not mandate that entities plan to
prevent encroachments into the MVCD, but simply that they implement whatever is
included in the plan. The measure is focused on demonstrating that the plan has been
executed.
Requirement R7 of the new FAC-003-2 requires the plan be executed such that no
vegetations encroachments occur within the MVCD. There are practical exceptions,
however (for example, where land ownership changes may have resulted in the utility not
possessing the property rights needed). In these cases, the entity may modify its plan;
however, at no point can it modify its plan such that it would allow encroachment of
vegetation into the MVCD. This new requirement raises the required level of
performance by requiring 100% of the plan be completed, and provides an explicit
method for determining the percentage that was completed. The proposed requirement is
clear and unambiguous. The measure is consistent with the requirement, and clearly
indicates that evidence of performance is required to demonstrate compliance. Examples
of acceptable evidence are provided, such as a copy of the completed annual work plan
(as finally modified), dated work orders, dated invoices, or dated inspection records.
FAC-003-1, Requirements R3, R4, and associated sub-requirements
Requirements R3, R4, and associated sub-requirements of FAC-003-1 read as
follows:
28
R3. The Transmission Owner shall report quarterly to its RRO, or the RRO’s
designee, sustained transmission line outages determined by the Transmission
Owner to have been caused by vegetation.
R3.1. Multiple sustained outages on an individual line, if caused by the
same vegetation, shall be reported as one outage regardless of the actual
number of outages within a 24-hour period.
R3.2. The Transmission Owner is not required to report to the RRO, or the
RRO’s designee, certain sustained transmission line outages caused by
vegetation: (1) Vegetation related outages that result from vegetation
falling into lines from outside the ROW that result from natural disasters
shall not be considered reportable (examples of disasters that could create
non-reportable outages include, but are not limited to, earthquakes, fires,
tornados, hurricanes, landslides, wind shear, major storms as defined
either by the Transmission Owner or an applicable regulatory body, ice
storms, and floods), and (2) Vegetation-related outages due to human or
animal activity shall not be considered reportable (examples of human or
animal activity that could cause a non-reportable outage include, but are
not limited to, logging, animal severing tree, vehicle contact with tree,
arboricultural activities or horticultural or agricultural activities, or
removal or digging of vegetation).
R3.3. The outage information provided by the Transmission Owner to the
RRO, or the RRO’s designee, shall include at a minimum: the name of the
circuit(s) outaged, the date, time and duration of the outage; a description
of the cause of the outage; other pertinent comments; and any
countermeasures taken by the Transmission Owner.
R3.4. An outage shall be categorized as one of the following:
R3.4.1. Category 1 — Grow-ins: Outages caused by vegetation
growing into lines from vegetation inside and/or outside of the
ROW;
R3.4.2. Category 2 — Fall-ins: Outages caused by vegetation
falling into lines from inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages caused by vegetation
falling into lines from outside the ROW.
R4. The RRO shall report the outage information provided to it by Transmission
Owner’s, as required by Requirement 3, quarterly to NERC, as well as any
actions taken by the RRO as a result of any of the reported outages.
29
Requirements R3, R4, and associated sub-requirements of FAC-003-1 are
associated with monitoring and compliance. Accordingly, they have been moved to the
compliance section of the proposed standard:
Periodic Data Submittal: The Transmission Owner will submit a quarterly report
to its Regional Entity, or the Regional Entity’s designee, identifying all Sustained
Outages of applicable lines operated within their Rating and all Rated Electrical
Operating Conditions as determined by the Transmission Owner to have been
caused by vegetation, except as excluded in footnote 2, and including as a
minimum the following:
•
The name of the circuit(s), the date, time and duration of the outage; the
voltage of the circuit; a description of the cause of the outage; the category
associated with the Sustained Outage; other pertinent comments; and any
countermeasures taken by the Transmission Owner.
A Sustained Outage is to be categorized as one of the following:
•
Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, that are identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or outside
of the ROW;
•
Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or outside
of the ROW;
•
Category 2A — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines that are identified as an element of an IROL or
Major WECC Transfer Path, from within the ROW;
•
Category 2B — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, from within the ROW;
•
Category 3 — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines from outside the ROW;
•
Category 4A — Blowing together: Sustained Outages caused by
vegetation and applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, blowing together from within the
ROW.
30
•
Category 4B — Blowing together: Sustained Outages caused by
vegetation and applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, blowing together from within the
ROW.
The Regional Entity will report the outage information provided by Transmission
Owners, as per the above, quarterly to NERC, as well as any actions taken by the
Regional Entity as a result of any of the reported Sustained Outages.
This transfer of a reporting requirement to the Compliance portion of the
standards remains enforceable under NERC’s Rules of Procedure. NERC’s
authority to require such data is described in Section 400.3 of the Rules of
Procedure:
Data Access — All bulk power system owners, operators, and users shall
provide to NERC and the applicable regional entity such information as is
necessary to monitor compliance with the reliability standards. NERC and
the applicable regional entity will define the data retention and reporting
requirements in the reliability standards and compliance reporting
procedures.
An entity that is not in compliance with this rule must take specific actions, and
NERC has certain courses of action it may undertake as necessary to ensure the entity
complies with the Rules, as specified in Section 100 of the NERC Rule of Procedure:
Any entity that is unable to comply or that is not in compliance with a NERC rule
of procedure shall immediately notify NERC in writing, stating the rule of
concern and the reason for not being able to comply with the rule.
NERC shall evaluate each case and inform the entity of the results of the
evaluation. If NERC determines that a rule has been violated, or cannot
practically be complied with, NERC shall notify the applicable governmental
authorities and take such other actions as NERC deems appropriate to address
the situation.
Accordingly, NERC believes it has sufficient authority and recourse to ensure
such data continues to be submitted. Additionally, if necessary, NERC can compel
31
entities to provide such data separately as part of a Section 1600 data request, pursuant to
Section 1600 of the NERC Rules of Procedure, which has similar provisions.
Additional Requirements
In addition to the disposition and transfer of requirements from the previous
standard as described above, Requirements R1 and R2 of FAC-003-2 are additional
requirements that were added to the standard:
R1. Each Transmission Owner shall manage vegetation to prevent
encroachments into the MVCD of its applicable line(s) which are either an
element of an IROL, or an element of a Major WECC Transfer Path; operating
within their Rating and all Rated Electrical Operating Conditions of the types
shown below:
1.
An encroachment into the MVCD as shown in FAC-003-Table 2,
observed -time, absent a Sustained Outage ,
2.
An encroachment due to a fall-in from inside the ROW that caused
a vegetation-related Sustained Outage,
3.
An encroachment due to the blowing together of applicable lines
and vegetation located inside the ROW that caused a vegetationrelated Sustained Outage,
4.
An encroachment due to vegetation growth into the MVCD that
caused a vegetation-related Sustained Outage.
R2.
Each Transmission Owner shall manage vegetation to prevent
encroachments into the MVCD of its applicable line(s) which are not either an
element of an IROL, or an element of a Major WECC Transfer Path; operating
within its Rating and all Rated Electrical Operating Conditions of the types
shown below:
1.
2.
3.
4.
An encroachment into the MVCD, observed in Real-time, absent a
Sustained Outage,
An encroachment due to a fall-in from inside the ROW that caused
a vegetation-related Sustained Outage,
An encroachment due to blowing together of applicable lines and
vegetation located inside the ROW that caused a vegetationrelated Sustained Outage,
An encroachment due to vegetation growth into the MVCD that
caused a vegetation-related Sustained Outage
32
Requirements R1 and R2 of FAC-003-2 are significant improvements not
included in FAC-003-1. These requirements are focused on the results of managing
vegetation and ensuring that 1) encroachments do not occur, and 2) sustained outages do
not occur. The proposed requirements are clear and unambiguous. The measure is
consistent with the requirement, and clearly indicates that evidence of performance is
required to demonstrate compliance. Examples of acceptable evidence are provided.
These include completed and dated work orders, dated invoices, or dated inspection
records.
As discussed previously with regard to “Clearance 2,” these new requirements
provide that the Transmission Owner must manage vegetation to prevent encroachments,
rather than simply document the clearance. The standard replaces the use of IEEE
Standard 516-2003 with the use of the Gallet Equation to determine the MVCD.
Additionally, in order to eliminate commingling of higher-risk reliability objectives and
lesser-risk reliability objectives, the standard has separated the concept of “Clearance 2”
into two distinct requirements – those that are related to line(s) that are either an element
of an IROL or an element of a Major WECC Transfer Path, and those that are not. This
helps ensure that entities properly understand the risk to reliability associated with
specific actions, and aligns the standard and associated VRFs with Commission
guidelines.
c. Enforceability of the Proposed FAC-003-2 Reliability Standard
The proposed Reliability Standard contains measures that support each standard
requirement by clearly identifying what is required and how the requirement will be
enforced. The VSLs also provide further guidance on the way that NERC will enforce
33
the requirements of the standard. A component of enforceability of this proposed
standard is the use of appropriate compliance monitoring tools and the discovery methods
as laid out in the Compliance Monitoring and Enforcement Program (“CMEP”).
Requirements R1 and R2 require the Transmission Owner manage vegetation to
prevent encroachments into the MVCD. The measures for these requirements are
identical:
Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in (the requirement). Examples of
acceptable forms of evidence may include dated attestations, dated reports
containing no Sustained Outages associated with encroachment types 2 through 4
above, or records confirming no Real-time observations of any MVCD
encroachments.
In other words, the burden of proof to show records indicating the requirements
were not violated is held by the Transmission Owner. The VSLs recommended for
Requirements R1 and R2 are “pass or fail” evaluations; if an entity does not manage
vegetation to prevent encroachments, then it fails the requirement (R1 or R2, as
applicable to the given scenario). Such failures would be identified using NERC’s
normal Compliance Monitoring and Enforcement processes – primarily through periodic
data submittals, self-certification and self-reporting, but also through audits, spotchecking, compliance violation investigations, and complaints as appropriate.
Requirements R1 and R2 include a general footnote that describes some cases
where an entity might not be held to the standard (for example, during natural disasters).
However, these limitations only apply to those circumstances that are beyond the control
of the Transmission Owner or the other duly delegated registered entities, affiliates or
contractors that fulfill reliability responsibilities on behalf of the Transmission Owner.
Transmission Owners have options as to how to appropriately delegate reliability tasks to
34
ensure accountability with other registered entities. For example, the use of Joint
Registration Organization, Coordinated Functional Registration agreements, or other duly
executed legal agreements clearly delineate reliability task responsibility. Transmission
Owners are further responsible for any contract work associated with maintaining their
system and facilities.
Requirement R3 requires the Transmission Owner to have documentation
describing its chosen approach(es) for managing vegetation. The approach must consider
the movement of the conductor, as well as growth rate, control method, and inspection
frequency. The measure for this requirement is as follows:
The maintenance strategies or procedures or processes or specifications provided
demonstrate that the Transmission Owner can prevent encroachment into the
MVCD considering the factors identified in the requirement.
In this case, the Transmission Owner is obligated to show documentation, and that
documentation must be sufficient to satisfy the auditor that the information contained in
that documentation is sufficient that the Transmission Owner can use it to prevent
encroachment into the MVCD. The difference in sizes of applicable entities, the nature
of vegetation, and the number of techniques available to applicable entities to manage it
require that the measure allow for sufficient flexibility in approach. For example,
vegetation management in Arizona is likely to be much different from that in West
Virginia. Similarly, the approach used to manage a small system may be described in a
few short sentences, while the approach used on a much larger system might require
several volumes to describe. Auditors will have to use judgment to evaluate the
appropriateness of the documentation provided given the particular circumstances of the
entity being audited. To guide them in this, the Violation Severity Levels provided for
35
Requirement R3 gradate the severity of a violation based on the completeness of the
information provided. In this case, failures of the requirement would likely be identified
during review of the document(s) as submitted in response to a data request to support an
audit, spot-check, or a self-certification. The document(s) the requirement describes can
generally be understood to encompass the broad strategy, direction and goals supported
by analysis and information peculiar to the geographical area of the Transmission Owner
and the characteristics of its system. This document generally should be the foundation
for the detail and supporting evidence required in requirements 4 through 7. As a
competency based requirement, this is the cornerstone of the Transmission Owner’s
program to ensure vegetation management is implemented to ensure no encroachment.
Requirement R4 states that when a Transmission Owner observes a vegetation
condition that is likely to produce a fault, it must notify the control center with switching
authority for that transmission line of the condition. The measure for this requirement is:
Each Transmission Owner that has a confirmed vegetation condition likely to
cause a Fault at any moment will have evidence that it notified the control center
holding switching authority for the associated transmission line without any
intentional time delay. Examples of evidence may include control center logs,
voice recordings, switching orders, clearance orders and subsequent work orders.
As with R1 and R2, the burden of proof to show records indicating the
requirement was not violated is held by the Transmission Owner. The VSLs provided for
Requirement R4 gradate the severity of a violation based on whether or not any delay in
communicating the information was intentional or not. Auditors will have to use
judgment to evaluate the manner in which the requirement was met given the particular
circumstances of the entity being audited, but it is expected that an entity that does not
make this reporting a top priority would be in violation of the standard. Generally
36
speaking the requirement to notify without intentional delay can be understood to include
an immediate (within 1 hour of the observation) communication notwithstanding a safety
issue to the personnel, other immediate priority maintenance functions to ensure
reliability or system stability, or communications equipment failure that precludes
immediate communication. Such violations would be identified using NERC’s normal
Compliance Monitoring and Enforcement processes – primarily through self-certification
and self-reporting, but also through audits, compliance violation investigations, and
complaints as appropriate.
Requirement R5 states that a Transmission Owner prevented from performing
vegetation management work must take corrective actions to prevent encroachments that
would put the line at risk. The measure for this requirement is
Each Transmission Owner has evidence of the corrective action taken for each
constraint where an applicable transmission line was put at potential risk.
Examples of acceptable forms of evidence may include initially-planned work
orders, documentation of constraints from landowners, court orders, inspection
records of increased monitoring, documentation of the de-rating of lines, revised
work orders, invoices, or evidence that the line was de-energized.
In this case, the Transmission Owner must show proof that it took corrective
action when necessary. In the event that a Transmission Owner is unable, for whatever
reason, to prevent or clear encroachments in the MVCD, it must de-energize or de-rate
the line to reduce the MVCD to preclude an encroachment, or will be found in violation
of this requirement as well as requirement #1 or #2 as applicable. The VSL
recommended for Requirement R5 is a “pass or fail” evaluation; if an entity does not take
corrective action, then it fails the requirement. Such failures would be identified using
NERC’s normal Compliance Monitoring and Enforcement processes – primarily through
37
self-certification and self-reporting, but also through audits, spot-checking, and
compliance violation investigations and complaints as appropriate.
Requirement R6 mandates the Transmission Owner to inspect 100% of its
applicable lines at least once per calendar year, with no more that 18 months between
inspections. The measure for this requirement is
Each Transmission Owner has evidence that it conducted Vegetation Inspections
of the transmission line ROW for all applicable lines at least once per calendar
year but with no more than 18 calendar months between inspections on the same
ROW. Examples of acceptable forms of evidence may include completed and
dated work orders, dated invoices, or dated inspection records.
In this case, the Transmission Owner must show proof it inspected all of its lines
within the calendar year as described. This requirement can be understood to require a
document to account for the inspection of the lines over the period of the time specified
and status reports to demonstrate the progress of work performed to meet the
requirement. The VSLs recommended for Requirement R6 are gradated based on the
percentage of lines not inspected. Such failures would be identified using NERC’s
normal Compliance Monitoring and Enforcement processes – primarily through selfcertification and self-reporting, but also through audits, spot-checking, compliance
violation investigations, and complaints as appropriate.
Requirement R7 states the Transmission Owner must complete 100% of its
annual vegetation work plan for applicable lines, and provides for modifications to the
plan for a number of reasons (some of which are listed as examples in the requirement),
but indicates that such modifications must not allow encroachment of vegetation into the
MVCD. The requirement essentially allows a Transmission Owner to have a dynamic
vegetation work plan, as long as the Transmission Owner meets the obligations in its plan
38
and the plan serves its primary function of avoiding encroachments. The measure for this
requirement is
Each Transmission Owner has evidence that it completed its annual vegetation
work plan for its applicable lines. Examples of acceptable forms of evidence may
include a copy of the completed annual work plan (as finally modified), dated
work orders, dated invoices, or dated inspection records.
In this case, the Transmission Owner must show proof that it completed its plan.
An entity unable to produce a plan will be unable to demonstrate compliance with the
standard, resulting in a violation of the requirement. Although the standard does not
explicitly require the creation of a plan, entities will not be able to comply with the
requirement without having a documented plan. It should be noted that the documented
plan is not necessarily a single binder that includes all aspect of vegetation management;
it may be a collection of documents. Entities may meet this requirement through several
methods including on-line manuals, paper documents, handbooks, guidelines, work
orders, or pieces of information, provided the information clearly demonstrates the
requirement has been met.
Because of the dynamic nature of vegetation, the plan must also be dynamic.
While in theory this might allow an entity to modify its plan to avoid compliance risk,
such modification would not eliminate the obligation that the modified plan be executed
to avoid encroachment of vegetation into the MVCD. Any such encroachment would be
a violation of R1 or R2, and any changes to the plan that resulted in such encroachment
would be a violation of R7. The VSLs recommended for Requirement R7 are gradated
based on the percentage of the final plan not completed. Such failures would be
identified using NERC’s normal Compliance Monitoring and Enforcement processes –
primarily through self-certification and self-reporting, but also through audits, spot39
checking, compliance violation investigations, and complaints as appropriate. In order
for auditors to make appropriate judgments as to the completed plan and any
modifications, the initial work plan may be requested via a self certification or data
submittal prior to its initiation and then compared to the completed plan at the end of the
time period.
As discussed above, the measures and VSLs provide clarity regarding how the
requirements will be enforced, and ensure that the requirements will be enforced in a
clear, consistent, and non-preferential manner and without prejudice to any party.
Appropriate use of compliance monitoring tools will be utilized and specified in the
Annual Compliance Monitoring and Enforcement Program Implementation Plan and
Actively Monitored List.
d. FERC Directives Addressed in the Proposed FAC-003-2 Standard
The drafting team responsible for the development of FAC-003-2 addressed seven
directives issued by the Commission in Order No. 693 16 as part of NERC Project 200707 Vegetation Management. These directives are presented below with the resolutions
proposed by the drafting team. The text of the complete proposed standard FAC-003-2 is
included in Exhibit A.
Paragraph 706 of Order 693, sentences 1, 2 and 3 (directive reference number
10098 17 ) - We will not direct NERC to submit a modification to the general
limitation on applicability as proposed in the NOPR. However, we will require
the ERO to address the proposed modification through its Reliability Standards
development process. As explained in the NOPR, the Commission is concerned
16
See, Order No. 693 at PP 706 to 735.
The “directive reference number” refers to the number assigned to a particular regulatory directive in the
NERC Standards Issues Database. The reference number is identified in the summary section for each
regulatory directive. Each reference number is unique and provides an easy reference for each regulatory
directive.
17
40
that the bright-line applicability threshold of 200 kV will exclude a significant
number of transmission lines that could impact Bulk-Power System reliability.
Proposed FAC-003-2, and the resolution of the issue of applicability in particular,
was developed through the Reliability Standards development process. The first draft of
the standard proposed to assign the selection of sub-200kV lines to the Reliability
Coordinator (rather than the Regional Reliability Organization, as was specified in
version 1 of the standard). With the third draft, specific criteria based on the importance
of sub-200kV lines were proposed to replace the discretion of the Reliability Coordinator,
effectively creating a “bright line” for those facilities operated below 200kV. In the final
proposed standard submitted with this petition, these proposed bright-line criteria are
substantively unchanged from the third draft. Industry was asked to comment on these
proposals through the standard development process, and balloting indicates support for
this approach.
NERC believes this to be a superior approach to the previous standard, as it has
eliminated the previous “fill-in-the-blank” discretion of the Regional Reliability
Organization and now focuses instead on specific criteria to determine the applicability to
sub-200kV facilities.
Paragraph 706 of Order 693, sentences 7 and 8 (directive reference number
10099) – We support the suggestions by Progress Energy, SERC and MISO to
limit applicability to lower voltage lines associated with IROL and these
suggestions should be part of the input to the Reliability Standards development
process. Similarly, the ERO should evaluate the suggestions proposed by LPPC,
APPA and Avista.
FAC-003-2 adopts the suggestions of Progress Energy, SERC, and MISO, and
extends the applicability to address issues specific to the Western Interconnection. The
applicability of lines operated below 200kV has been limited to specific cases where lines
41
are critical to reliability by virtue of their being elements included in the determination of
an Interconnection Reliability Operating Limit (“IROL”) or a part of a Major WECC
Transfer Path. In response to the concerns expressed by Avista, the standard does not
create a new minimum bright-line threshold of 100kV. By virtue of relying on IROL and
Major WECC Transfer Path identification as a proxy for reliability importance, the
proposed standard uses an impact-based approach for determining applicability as
suggested by LPPC. The suggestion made by APPA and Avista to grant authority to the
Regional Entity to determine applicability was considered, conceptually implemented in
the first draft of the standard through delegation to the Reliability Coordinator), then
ultimately rejected in favor of the use of the IROL and Major WECC Transfer Path
identification criteria.
Paragraph 708 of Order 693, sentence 3 (directive reference number 10102) - We
recognize that many commenters would like a more precise definition for the
applicability of this Reliability Standard, and we direct the ERO to develop an
acceptable definition that covers facilities that impact reliability but balances
extending the applicability of this standard against unreasonably increasing the
burden on transmission owners.
Proposed FAC-003-2 includes a detailed and specific description of the
applicability relative to facilities. Criteria used in the applicability focus on the criticality
of lines to reliability by virtue of their being elements included in the determination of an
IROL or a part of a Major WECC Transfer Path.
Paragraph 709 of Order 693, sentences 1 and 2 (directive reference number
10103) - FirstEnergy and Xcel suggest that if the applicability of this Reliability
Standard is expanded, the Commission should allow flexibility in complying with
this Reliability Standard for lower-voltage facilities, or allow lower-voltage
facilities one year before the Reliability Standard is implemented. The ERO
should consider these comments when determining when it would request that the
modification of this Reliability Standard to go into effect.
42
The Implementation Plan for the proposed standard adopts the suggestion of First
Energy and Xcel. The standard becomes effective on the first calendar day of the first
calendar quarter one year after the date of the order approving the standard.
Paragraph 721 of Order 693, sentences 1 and 2 (directive reference number Ref
10104) - The Commission continues to be concerned with leaving complete
discretion to the transmission owners in determining inspection cycles, which
limits the effectiveness of the Reliability Standard. Accordingly, the Commission
directs the ERO to develop compliance audit procedures, using relevant industry
experts, which would identify appropriate inspection cycles based on local
factors.
Proposed FAC-003-2 now requires the Transmission Owner to perform a
Vegetation Inspection of 100% of its applicable transmission lines (measured in units of
choice - circuit, pole line, line miles or kilometers, etc.) at least once per calendar year,
with no more than 18 calendar months between inspections. Transmission Owners may
inspect more frequently should they need to do so in order to meet the other requirements
in the standard, but they may not inspect less frequently.
Paragraph 732 of Order 693, sentence 1 (directive reference number 10100) Accordingly, the Commission directs the ERO to develop a Reliability Standard
that defines the minimum clearance needed to avoid sustained vegetation-related
outages that would apply to transmission lines crossing both federal land and
non-federal land.
As directed, proposed FAC-003-2 applies to facilities that meet specific criteria,
including (but not limited to) those that cross lands owned by federal, state, provincial,
public, private, or tribal entities, and specifies the minimum clearance needed to avoid
sustained vegetation-related outages. The proposed standard defines MVCD based on the
Gallet Equation, a well-known method for specifically calculating the flashover distance
for proper insulation coordination. This calculation accounts for wet conditions at
various altitudes.
43
Paragraph 734 of Order 693, sentences 1 and 3 (directive reference number
10105) - FirstEnergy suggests that rights-of-way be defined to encompass the
required clearance areas instead of the corresponding legal rights, and that the
standards should not require clearing the entire right-of-way when the required
clearance for an existing line does not take up the entire right-ofway.…Accordingly, the Commission directs the ERO to address this suggestion in
the Reliability Standards development process.
Proposed FAC-003-2 includes a modified definition of “Right-of-Way” to include
the statement “[t]he ROW width in no case exceeds the Transmission Owner’s legal
rights but may be less based on the aforementioned criteria.” Similar to FAC-003-1,
FAC-003-2 does not require clearing the entire legal limits for a particular parcel of land
to ensure reliability. Rather, the standard requires vegetation maintenance to adequately
prevent outages from vegetation and requires the Transmission Owner to prevent
encroachment within the MVCD in the operational corridor established under the
modified ROW definition. This provides the Transmission Owner with flexibility in
determining its approach to vegetation management and gives owners the authority to act
in the best interest of reliability without mandating any specific strategy (such as clearing
the entire width of the ROW).
e. Demonstration that the proposed Reliability Standard is just,
reasonable, not unduly discriminatory or preferential and in the
public interest
In Order No. 672, FERC identified a number of criteria it will use to analyze
Reliability Standards proposed for approval to ensure they are just, reasonable, not
unduly discriminatory or preferential, and in the public interest. The discussion below
identifies these factors and explains how the proposed Reliability Standard has met or
exceeded the criteria:
1. Proposed Reliability Standards must be designed to achieve a specified
reliability goal and must contain a technically sound method to achieve that goal.
44
Order No. 672 at P 321. The proposed Reliability Standard must address a reliability
concern that falls within the requirements of section 215 of the FPA. That is, it must
provide for the reliable operation of Bulk-Power System facilities. It may not extend
beyond reliable operation of such facilities or apply to other facilities. Such facilities
include all those necessary for operating an interconnected electric energy
transmission network, or any portion of that network, including control systems. The
proposed Reliability Standard may apply to any design of planned additions or
modifications of such facilities that is necessary to provide for reliable operation. It
may also apply to Cyber security protection.
Order No. 672 at P 324. The proposed Reliability Standard must be designed to
achieve a specified reliability goal and must contain a technically sound means to
achieve this goal. Although any person may propose a topic for a Reliability
Standard to the ERO, in the ERO’s process, the specific proposed Reliability
Standard should be developed initially by persons within the electric power industry
and community with a high level of technical expertise and be based on sound
technical and engineering criteria. It should be based on actual data and lessons
learned from past operating incidents, where appropriate. The process for ERO
approval of a proposed Reliability Standard should be fair and open to all interested
persons.
The proposed FAC-003-2 standard achieves the specific reliability goal of
maintaining a reliable electric transmission system by using a defense-in-depth strategy
to manage vegetation located on transmission ROW and minimize encroachments from
vegetation located adjacent to the ROW, thus preventing the risk of those vegetationrelated outages that could lead to Cascading.
The proposed Reliability Standard contains a technically sound method to achieve
that goal by:
•
requiring that vegetation be managed to prevent vegetation encroaching
into the flash-over distance;
•
requiring consideration of conductor movement, vegetation growth rates,
vegetation control methods, and inspection frequency when establishing
strategies for vegetation management;
•
requiring intervention when risks of vegetation contact are identified;
45
•
requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains (such as legal injunctions);
•
requiring annual inspections of vegetation conditions to be performed
annually; and
•
requiring completion of the annual work needed to prevent
encroachments.
2. Proposed Reliability Standards must be applicable only to users, owners and
operators of the bulk power system, and must be clear and unambiguous as to
what is required and who is required to comply.
Order No. 672 at P 322. The proposed Reliability Standard may impose a
requirement on any user, owner, or operator of such facilities, but not on others.
Order No. 672 at P 325. The proposed Reliability Standard should be clear and
unambiguous regarding what is required and who is required to comply. Users,
owners, and operators of the Bulk-Power System must know what they are required
to do to maintain reliability.
The proposed Reliability Standard is applicable only to users, owners and
operators of the North American bulk-power system, and not others. As identified in the
applicability section of the proposed standard, the requirements apply only to
Transmission Owners. No other registered entities are required to comply.
3. A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation.
Order No. 672 at P 326. The possible consequences, including range of possible
penalties, for violating a proposed Reliability Standard should be clear and
understandable by those who must comply.
The proposed Reliability Standard includes a VRF and VSL for each main
requirement, which is explained in more detail in Section IV. c, below. Upon approval
by FERC, the range of penalties for violations will be based on the applicable VRF and
VSL and will be administered based on the sanctions table and supporting penalty
46
determination process described in FERC-approved NERC Sanction Guidelines,
Appendix 4B in NERC’s Rules of Procedure. Therefore, responsible entities understand
the potential impacts of non-compliance with the proposed requirements.
4. A proposed Reliability Standard must identify clear and objective criterion
or measure for compliance, so that it can be enforced in a consistent and nonpreferential manner.
Order No. 672 at P 327. There should be a clear criterion or measure of whether an
entity is in compliance with a proposed Reliability Standard. It should contain or be
accompanied by an objective measure of compliance so that it can be enforced and so
that enforcement can be applied in a consistent and non-preferential manner.
The proposed Reliability Standard contains measures that support each
requirement by clearly identifying what is required and how the requirement will be
enforced. These measures, included below, help provide clarity regarding how the
requirements will be enforced, and ensure that the requirements will be enforced in a
clear, consistent, and non-preferential manner and without prejudice to any party.
M1. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-time observations of any MVCD encroachments. (R1)
M2. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R2. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-time observations of any MVCD encroachments. (R2)
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the Transmission Owner can prevent encroachment into the MVCD
considering the factors identified in the requirement. (R3)
M4. Each Transmission Owner that has a confirmed vegetation condition likely to
cause a Fault at any moment will have evidence that it notified the control center
holding switching authority for the associated transmission line without any
intentional time delay. Examples of evidence may include control center logs, voice
recordings, switching orders, clearance orders and subsequent work orders. (R4)
M5. Each Transmission Owner has evidence of the corrective action taken for each
constraint where an applicable transmission line was put at potential risk. Examples
of acceptable forms of evidence may include initially-planned work orders,
47
documentation of constraints from landowners, court orders, inspection records of
increased monitoring, documentation of the de-rating of lines, revised work orders,
invoices, or evidence that the line was de-energized. (R5)
M6. Each Transmission Owner has evidence that it conducted Vegetation Inspections
of the transmission line ROW for all applicable lines at least once per calendar year
but with no more than 18 calendar months between inspections on the same ROW.
Examples of acceptable forms of evidence may include completed and dated work
orders, dated invoices, or dated inspection records. (R6)
M7. Each Transmission Owner has evidence that it completed its annual vegetation
work plan for its applicable lines. Examples of acceptable forms of evidence may
include a copy of the completed annual work plan (as finally modified), dated work
orders, dated invoices, or dated inspection records. (R7)
5. Proposed Reliability Standards should achieve a reliability goal effectively
and efficiently — but do not necessarily have to reflect “best practices” without
regard to implementation cost.
Order No. 672 at P 328. The proposed Reliability Standard does not necessarily have
to reflect the optimal method, or “best practice,” for achieving its reliability goal
without regard to implementation cost or historical regional infrastructure design. It
should however achieve its reliability goal effectively and efficiently.
The proposed Reliability Standard achieves its reliability goal effectively and
efficiently. Crafting the requirements to address the societal need for reliable service and
meet the overall reliability goal for the standard was carefully undertaken using NERC’s
results-based standards development techniques, and the proposed standard was
structured to identify specific objectives to achieve the goal without unduly burdening
applicable entities. The standard avoids mandates for specific practices, and instead
focuses on the “what” as opposed to the “how.” For example, this standard provides the
Transmission Owner significant discretion in determining how to manage vegetation,
focusing on results rather than process. This approach allows for diverse approaches to
vegetation management, through which lessons learned and best practices can be
identified and implemented, and overall reliability is buttressed and enhanced.
6. Proposed Reliability Standards cannot be “lowest common denominator,”
i.e., cannot reflect a compromise that does not adequately protect bulk power
48
system reliability. Proposed Reliability Standards can consider costs to
implement for smaller entities, but not at consequences of less than excellence in
operating system reliability.
Order No. 672 at P 329. The proposed Reliability Standard must not simply reflect a
compromise in the ERO’s Reliability Standard development process based on the
least effective North American practice — the so-called “lowest common
denominator” — if such practice does not adequately protect Bulk-Power System
reliability. Although FERC will give due weight to the technical expertise of the
ERO, we will not hesitate to remand a proposed Reliability Standard if we are
convinced it is not adequate to protect reliability.
Order No. 672 at P 330. A proposed Reliability Standard may take into account the
size of the entity that must comply with the Reliability Standard and the cost to those
entities of implementing the proposed Reliability Standard. However, the ERO
should not propose a “lowest common denominator” Reliability Standard that would
achieve less than excellence in operating system reliability solely to protect against
reasonable expenses for supporting this vital national infrastructure. For example, a
small owner or operator of the Bulk-Power System must bear the cost of complying
with each Reliability Standard that applies to it.
The proposed Reliability Standard does not reflect a “lowest common
denominator” approach. To the contrary, the proposed standard represents a significant
improvement over the previous version as described herein. The Standard Drafting Team
took measured steps to ensure that the reliability objective of developing and
implementing technically sound Transmission Vegetation Management was met and that
each requirement provides detail of what is necessary to be addressed in the applicable
documentation or methodology.
Additionally, the proposed Reliability Standard was not developed or adopted to
protect against the imposition of reasonable expenses. The drafting team considered and
evaluated the effect this standard would impose on the impacted entities and determined
that no entities would be unduly burdened by the cost to implement its requirements. No
special accommodation was made for smaller entities, and the proposed standard will
apply equally to all applicable entities in a consistent manner.
49
7. Proposed Reliability Standards must be designed to apply throughout North
America to the maximum extent achievable with a single Reliability Standard
while not favoring one area or approach.
Order No. 672 at P 331. A proposed Reliability Standard should be designed to apply
throughout the interconnected North American Bulk-Power System, to the maximum
extent this is achievable with a single Reliability Standard. The proposed Reliability
Standard should not be based on a single geographic or regional model but should
take into account geographic variations in grid characteristics, terrain, weather, and
other such factors; it should also take into account regional variations in the
organizational and corporate structures of transmission owners and operators,
variations in generation fuel type and ownership patterns, and regional variations in
market design if these affect the proposed Reliability Standard.
The proposed Reliability Standard applies throughout North America and does
not favor one area or approach.
8. Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid.
Order No. 672 at P 332. As directed by section 215 of the FPA, FERC itself will give
special attention to the effect of a proposed Reliability Standard on competition. The
ERO should attempt to develop a proposed Reliability Standard that has no undue
negative effect on competition. Among other possible considerations, a proposed
Reliability Standard should not unreasonably restrict available transmission capability
on the Bulk-Power System beyond any restriction necessary for reliability and should
not limit use of the Bulk-Power System in an unduly preferential manner. It should
not create an undue advantage for one competitor over another.
The proposed Reliability Standard does not restrict the available transmission
capability or limit use of the bulk-power system in a preferential manner.
9. The implementation time for the proposed Reliability Standards must be
reasonable.
Order No. 672 at P 333. In considering whether a proposed Reliability Standard is
just and reasonable, FERC will consider also the timetable for implementation of the
new requirements, including how the proposal balances any urgency in the need to
implement it against the reasonableness of the time allowed for those who must
comply to develop the necessary procedures, software, facilities, staffing or other
relevant capability.
The proposed effective date for the FAC-003-2 is the first day of the first calendar
quarter that occurs twelve months following the effective date of a Final Rule in this
50
docket. This will allow applicable entities adequate time to ensure compliance with the
requirements. Additionally, the proposed standard provides several transition cases and
associated timelines to address situations where line classification or asset ownership
changes. These transition cases are explained in the proposed Implementation Plan,
attached as Exhibit B.
10. The Reliability Standard development process must be open and fair.
Order No. 672 at P 334. Further, in considering whether a proposed Reliability
Standard meets the legal standard of review, we will entertain comments about
whether the ERO implemented its Commission-approved Reliability Standard
development process for the development of the particular proposed Reliability
Standard in a proper manner, especially whether the process was open and fair.
However, we caution that we will not be sympathetic to arguments by interested
parties that choose, for whatever reason, not to participate in the ERO’s Reliability
Standard development process if it is conducted in good faith in accordance with the
procedures approved by FERC.
The proposed Reliability Standard was developed in accordance with NERC’s
FERC-approved, ANSI- accredited processes for developing and approving Reliability
Standards. Section V, Summary of the Reliability Standard Development Proceedings,
below, details the processes followed to develop the FAC-003-2 standard (for a more
thorough review, please see the complete development history included as Exhibit G).
These processes included, among other things, multiple comment periods, preballot review periods, and balloting periods. Additionally, all drafting team meetings
were properly noticed and open to the public. The initial and recirculation ballots both
achieved a quorum and exceeded the required ballot pool approval levels.
11. Proposed Reliability Standards must balance with other vital public
interests.
Order No. 672 at P 335. Finally, we understand that at times development of a
proposed Reliability Standard may require that a particular reliability goal must be
balanced against other vital public interests, such as environmental, social and other
goals. We expect the ERO to explain any such balancing in its application for
approval of a proposed Reliability Standard.
51
NERC has identified no competing public interests regarding the request for
approval of this proposed Reliability Standard. No comments were received that
indicated the proposed standard conflicts with other vital public interests.
12. Proposed Reliability Standards must consider any other relevant factors.
Order No. 672 at P 323. In considering whether a proposed Reliability Standard is
just and reasonable, we will consider the following general factors, as well as other
factors that are appropriate for the particular Reliability Standard proposed.
No other negative factors relevant to whether the proposed Reliability Standard is
just and reasonable were identified.
f. Violation Risk Factors and Violation Severity Levels
The VRFs and VSLs for the proposed standard comport with NERC and FERC
guidelines related to their assignment. Discussion of each of these items is included
below. For a detailed review of the VRFs, the VSLs, and the analysis of how the VRFs
and VSLs were determined using these guidelines, please see Attachment F.
The following discussion summarizes the manner in which the VRFs align with
FERC’s VRF Guidelines 2 through 5. The standard does not address Guideline 1 directly
because of an apparent conflict between Guidelines 1 and 4. Whereas Guideline 1
identifies a list of topics that encompass nearly all topics within NERC’s Reliability
Standards and implies that these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to
the reliability of the system. NERC believes that Guideline 4 is reflective of the intent of
VRFs in the first instance and therefore concentrated its attention on the reliability impact
of the requirements.
52
Requirement R1 of the standard was assigned a VRF of High. The Requirement
states Transmission Owners must manage vegetation for lines that represent a significant
risk of cascading, instability, or separation. The VRF is only applied at the Requirement
level and each Requirement Part is treated equally. The requirement mandates
measurable performance with regard to vegetation management to ensure that the risk of
cascading, separation, and instability is minimized. Other requirements with similar
performance based outcomes that could lead to cascading carry a High VRF. IROLs and
Major WECC Transfer Paths by definition have an increased potential for leading to
cascading, separation, or instability. Therefore this requirement was assigned a High
VRF. The requirement contains only one objective (which is to manage vegetation of
lines that carry increased risk of instability, cascading, or separation) and only one VRF
was assigned.
Requirement R2 of the standard was assigned a VRF of Medium. The
Requirement states Transmission Owners must manage vegetation for lines that do not
represent a significant risk of cascading, instability, or separation. The VRF is only
applied at the Requirement level, and each Requirement Part is treated equally. The
requirement mandates measurable performance with regard to vegetation management to
ensure the risk of equipment damage is minimized. Other requirements with similar
performance based outcomes that could lead to equipment damage carry a Medium VRF.
Lines that are not IROLs and are not Major WECC Transfer Paths by definition have less
potential for leading to cascading, separation, or instability. Therefore this requirement
was assigned a Medium VRF. The requirement contains only one objective (which is to
manage vegetation of lines that carry minimal risk instability, cascading, or separation)
53
and only one VRF was assigned. While this assignment is lower than the current VRF
assigned to R1 of FAC-003-1, NERC believes this to be appropriate, as it aligns with the
Commission-approved definitions for VRFs and complies with FERC’s guidelines
regarding the establishment of these values. Additionally, in order to eliminate
commingling of higher risk reliability objectives and lesser risk reliability objectives, this
requirement and its associated VRF has been split from Requirement R1. While R1
addresses those violations related to line(s) that are either an element of an IROL or an
element of a Major WECC Transfer Path, R2 addresses those that are not. This
separation helps ensure entities properly understand the risk to reliability associated with
specific actions, as well as aligns the standard and associated VRFs with Commission
guidelines.
Requirement R3 of the standard was assigned a VRF of Lower. The Requirement
mandates the Transmission Owner to have documented strategies, procedures, processes,
or specifications. The VRF is only applied at the Requirement level and each
Requirement Part is treated equally. This requirement calls for an entity to have
documented strategies, procedures, processes, or specifications. This requirement is
administrative in nature, and is consistent with other standards requiring documentation.
Failure to have a document is not likely to directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control the
bulk electric system. Development of documents is a requirement that is administrative
in nature and is in a planning time-frame that, if violated, would not, under emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to
adversely affect the electrical state or capability of the bulk electric system, or the ability
54
to effectively monitor, control, or restore the bulk electric system. Therefore this
requirement was assigned a Lower VRF. R3 contains only one objective (which is to
have documents), and only one VRF was assigned. While this assignment is lower than
the current VRF assigned to R1 of FAC-003-1, NERC believes this to be appropriate, as
it aligns with the Commission-approved definitions for VRFs and complies with FERC’s
guidelines regarding the establishment of these values.
Requirement R4 of the standard was assigned a VRF of Medium. The
Requirement specifies that transmission owners must report vegetation conditions that are
likely to cause a Fault to the control center holding switching authority for the associated
line. The VRFs are only applied at the Requirement level and there are no Requirement
Parts for separate consideration. The requirement mandates notifications that could
hinder the ability to effectively monitor and control the bulk electric system. Other
requirements with similar outcomes are also assigned Medium VRFs. Failure to report
vegetation conditions may affect the ability to effectively monitor and control the Bulk
Electric System. Therefore this requirement was assigned a Medium VRF. The
requirement contains only one objective (which is to report), and only one VRF was
assigned. While this assignment is lower than the current VRF assigned to R1 of FAC003-1, NERC believes this to be appropriate, as it aligns with the Commission-approved
definitions for VRFs and complies with FERC’s guidelines regarding the establishment
of these values.
Requirement R5 of the standard was assigned a VRF of Medium. The
Requirement mandates that a Transmission Owner, when constrained from performing
vegetation work that may lead to a vegetation encroachment into the MVCD prior to the
55
implementation of the next annual work plan, must take corrective action to ensure
continued vegetation management to prevent encroachments. The VRF is only applied at
the Requirement level and there are no Requirement Parts for separate consideration.
The requirement mandates corrective action that, if not taken, could directly affect the
electrical state or the capability of the bulk electric system. Other requirements with
similar outcomes are also assigned Medium VRFs. Failure to take corrective action
could directly affect the electrical state or the capability of the Bulk Electric System, or
the ability to effectively monitor and control the Bulk Electric System. Therefore this
requirement was assigned a Medium VRF. The requirement contains only one objective
(which is to take corrective action), and only one VRF was assigned. While this
assignment is lower than the current VRF assigned to R1 of FAC-003-1, NERC believes
this to be appropriate, as it aligns with the Commission-approved definitions for VRFs
and complies with FERC’s guidelines regarding the establishment of these values.
Requirement R6 of the standard was assigned a VRF of Medium. The
Requirement specifies that the Transmission Owner must perform a Vegetation
Inspection of 100% of its lines at least once per calendar year. The VRFs are only
applied at the Requirement level and there are no Requirement Parts for separate
consideration. The requirement mandates inspections that, if not performed, could affect
the ability to effectively monitor and control the Bulk Electric System. Other
requirements with similar outcomes are also assigned Medium VRFs. Failure to perform
an inspection could affect the ability to effectively monitor and control the Bulk Electric
System. Therefore this requirement was assigned a Medium VRF. The requirement
contains only one objective (which is to perform a vegetation inspection), and only one
56
VRF was assigned. While this assignment is lower than the current VRF assigned to R1
of FAC-003-1, NERC believes this to be appropriate, as it aligns with the Commissionapproved definitions for VRFs and complies with FERC’s guidelines regarding the
establishment of these values.
Requirement R7 of the standard was assigned a VRF of Medium. The
Requirement specifies that the Transmission Owner must complete 100% of its annual
vegetation work plan. The VRFs are only applied at the Requirement level and there are
no Requirement Parts for separate consideration. The requirement mandates completion
of work that, if not completed, could affect the electrical state or the capability of the bulk
electric system. Other requirements with similar outcomes are also assigned Medium
VRFs. Failure to complete the annual vegetation work plan could affect the electrical
state or the capability of the bulk electric system. Therefore this requirement was
assigned a Medium VRF. The Requirement contains only one objective (which is to
complete 100% of the annual vegetation work plan), and only one VRF was assigned.
While this assignment is lower than the current VRF assigned to R2 of FAC-003-1,
NERC believes this to be appropriate, as it aligns with the Commission-approved
definitions for VRFs and complies with FERC’s guidelines regarding the establishment
of these values.
Regarding the VSLs, they have been developed based on the situations an auditor
may find during a typical compliance audit. The following discussions summarize the
manner in which the VSLs meet both NERC and FERC guidelines for VSLs.
For Requirement R1, there is an incremental aspect to the violation, and the VSLs
follow the guidelines for incremental violations. The standard incorporates a High VSL
57
for failure to prevent encroachment into the MVCD that does not lead to a sustained
outage and a Severe VSL for failure to manage vegetation that leads to any of the
identified vegetation-related sustained outages. This is a new requirement, and
accordingly, it cannot lower the current level of compliance. The proposed VSL does not
use any ambiguous terminology, thereby supporting uniformity and consistency in the
determination of similar penalties for similar violations. Consistent with the requirement,
the proposed VSL uses the same terminology as used in the associated requirement and is
based on a single violation and not cumulative violations.
For Requirement R2, there is an incremental aspect to the violation, and the VSLs
follow the guidelines for incremental violations. The standard incorporates a High VSL
for failure to prevent encroachment into the MVCD that does not lead to a sustained
outage and a Severe VSL for failure to manage vegetation that leads to any of the
identified vegetation-related sustained outages. This is a new requirement, and
accordingly, it cannot lower the current level of compliance. The proposed VSL does not
use any ambiguous terminology, thereby supporting uniformity and consistency in the
determination of similar penalties for similar violations. Consistent with the requirement,
the proposed VSL uses the same terminology as used in the associated requirement and is
based on a single violation and not cumulative violations.
For Requirement R3, there is an incremental aspect to the violation, and the VSLs
follow the guidelines for incremental violations. The previous standard graded the VSLs
based on the completeness of the TVMP. The new VSL is structured similarly, but has
omitted the “Low” level - effectively raising the minimum level of compliance. The
proposed VSLs do not use any ambiguous terminology, thereby supporting uniformity
58
and consistency in the determination of similar penalties for similar violations.
Consistent with the requirement, the proposed VSL uses the same terminology as used in
the associated requirement, and is based on a single violation and not cumulative
violations.
For Requirement R4, there is an incremental aspect to the violation, and the VSLs
follow the guidelines for incremental violations. The previous standard does not require
actual communication, while the new standard does. Accordingly, this should be treated
as a new requirement, and therefore cannot lower the current level of compliance. The
proposed VSLs do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
Consistent with the requirement, the proposed VSL uses the same terminology as used in
the associated requirement and is based on a single violation and not cumulative
violations.
For Requirement R5, the VSL is “binary” (pass/fail). If a Transmission Owner
did not take corrective action when it was constrained from performing planned
vegetation work where an applicable line was put at potential risk, then a violation had
occurred. The only VSL is Severe, and therefore, the VSL cannot result in a lower level
of compliance. The proposed VSLs do not use any ambiguous terminology, thereby
supporting uniformity and consistency in the determination of similar penalties for
similar violations. Consistent with the requirement, the proposed VSL uses the same
terminology as used in the associated requirement and is based on a single violation and
not cumulative violations.
59
For Requirement R6, there is an incremental aspect to the violation, and the VSLs
follow the guidelines for incremental violations. The previous standard does not require
actual inspections, while the new standard does. Accordingly, this should be treated as a
new requirement, and therefore cannot lower the current level of compliance. The
proposed VSLs do not use any ambiguous terminology, thereby supporting uniformity
and consistency in the determination of similar penalties for similar violations.
Consistent with the requirement, the proposed VSL uses the same terminology as used in
the associated requirement and is based on a single violation and not cumulative
violations.
For Requirement R7, there is an incremental aspect to the violation, and the VSLs
follow the guidelines for incremental violations. The VSLs in the previous standard were
focused on completeness of the document with the “Severe” VSL only reserved for
entities that did not have or implement their plan. The proposed VSLs are graded based
on the amount of the plan completed, giving a clear indication that partial completion is
still a violation. This provides a level of compliance in excess of what was established by
the previous version of the standard. The proposed VSLs do not use any ambiguous
terminology, thereby supporting uniformity and consistency in the determination of
similar penalties for similar violations. Consistent with the requirement, the proposed
VSL uses the same terminology as used in the associated requirement and is based on a
single violation and not cumulative violations.
VI.
SUMMARY OF THE RELIABILITY STANDARD DEVELOPMENT
PROCEEDINGS
a. Development History
60
The development record for FAC-003-2 is summarized below. Exhibit E
contains the Consideration of Comments Reports created during the development FAC003-2. Exhibit G contains the complete record of development for FAC-003-2.
i.
SAR Development
Project 2007-07 Vegetation Management was initiated on January 9, 2007 for the
purpose of reviewing and modifying FAC-003-1. The first draft of the Standards
Authorization Request (“SAR”) was posted for industry comment from January 15, 2007
to February 14, 2007. Commenters suggested additional enhancements to the SAR,
including a request for a reference document to aid in the implementation of the standard.
An updated SAR was posted from April 10, 2007 to May 9, 2007. Following minor
corrections, the SAR was finalized and posted, a drafting team was assembled, and
development of the standard commenced.
ii.
Overview of the Standard Drafting Team
When evaluating proposed Reliability Standard, the Commission is expected to
give “due weight” to the technical expertise of the ERO. 18 The technical expertise of the
ERO is derived from the SDT. For this project, the SDT consisted of 17 industry experts
with over 500 years collective experience. The SDT included experts in vegetation
management, several registered professional engineers, and industry thought leaders that
generously lent their expertise to NERC and other professional organizations such as the
Institute of Electrical and Electronics Engineers (“IEEE”). Each individual is considered
to be an expert in his field. Members of this standard drafting team provided a diversity
of vegetation management experience, ranging across North America, including both the
18
Section 215(d)(2) of the Federal Power Act; 16 U.S.C. § 824o(d)(2) (2011).
61
continental United States and Canada. A detailed set of biographical information for
each of the team members is included along with the SDT roster in Exhibit H.
iii.
The First Posting
The first draft of FAC-003-2 was posted for formal comment from October 27,
2008 to November 25, 2008. A mapping document was provided to industry to assist in
the review of the standard. Sixty sets of comments were received, representing each of
the 10 Industry Segments within NERC’s stakeholder structure. Based on the comments
received, modifications were made to the standard, including:
•
Replacing the Critical Clearance Zone concept found in R4 with a practical field
measurement to address commenter’s concerns.
•
Eliminating the Critical Clearance Zone as the trigger of imminent threat in R2 to
address commenter’s concerns.
•
Adding a sub part to the Transmission Vegetation Management Plan requirement
(1.6) in order to address commenter’s concerns regarding the elimination of
Clearance 1. This change required that the TO account for anticipated conductor
movement.
•
Creating a second grow-in outage requirement to allow for different VRF levels
based on the actual criticality of the line.
There were 3 strong minority views not resolved:
•
Some commenters disagreed with the “zero tolerance” nature in the previous
version of the standard
•
Some commenters disagreed with the proposed minimum Vegetation Inspection
frequency of one year.
62
•
Some commenters wanted to retain Clearance 1 from the previous version of the
standard.
iv.
The Second Posting
The second draft of FAC-003-2 was posted for formal comment from September
10, 2009, to October 24, 2009. A mapping document was again provided to industry to
assist in the review of the standard, as well as a new technical reference document.
Violation Risk Factors and Violation Severity levels were added to the standard, as well
as several other improvements and modifications. Sixty-six sets of comments were
received, representing each of the 10 Industry Segments within NERC’s stakeholder
structure.
v.
Transition to Results Based Format
On January 14, 2010, the NERC Standards Committee endorsed the use of Project
2007-07 Vegetation Management as the prototype for the proof-of-concept for using the
results-based criteria for developing a Reliability Standard. The results-based initiative is
intended to focus the collective effort of NERC and industry participants on improving
the clarity and quality of NERC Reliability Standards by developing performance, risk
and competency-based requirements that accomplish a reliability objective through a
defense-in-depth strategy, while eliminating documentation-driven requirements that do
not have an impact on bulk-power system reliability.
The Standards Committee directed the Vegetation Management SDT to stop work
refining its second draft of the Vegetation Management standard. Instead, it asked them
to inform stakeholders how the team used stakeholder comments to refine the technical
requirements carried into the results-based draft of the standard. In response, the drafting
63
team did not develop individual responses to the comments submitted by stakeholders on
the second draft of FAC-003-2. Instead, the drafting team produced a summary report
that showed all the questions asked and provided a summary indicating how the drafting
team used stakeholder comments submitted in response to that question.
vi.
The Third Posting
The third draft of FAC-003-2 was posted for informal comment from March 1,
2010 to March 31, 2010. Once again, a mapping document was provided to industry to
assist in the review of the standard, as well as a technical reference document. The new
standard included an implementation plan, and had been redrafted using the new resultsbased format. Fifty-five sets of comments were received, representing 8 of the 10
Industry Segments within NERC’s stakeholder structure. Based on the comments
received, modifications were made to the standard, including:
•
Dividing requirement R1 into separate requirements, with separate VRFs
•
Removing the phrase “Bulk Power System” from the standard
•
Requirement R3 was modified to more explicitly indicate what information
needed to be included to be considered a valid procedure, process, or
specification.
•
Modifying VRFs to align with NERC guidelines.
Some commenters expressed concern regarding the standards use of the Gallet
Equation. The drafting team provided an extensive response, explaining its technical
justification for the choice. For a detailed discussion of the Gallet Equation and its use,
64
please see Appendix 1 of the Transmission Vegetation Management – FAC-003-2
Technical Reference Document included as Exhibit I.
Additionally, a large number of comments were received and considered
regarding the new “results-based” format of the standard at this time.
vii.
The Fourth Posting and Initial Ballot
A fourth draft of FAC-003-2 was posted for formal comment from June 17, 2010
to July 17, 2010. A mapping document and a technical reference document were
provided to industry to assist in the review of the standard. Forty-five sets of comments
were received, representing 7 of the 10 Industry Segments within NERC’s stakeholder
structure. An initial ballot of the standard was conducted from July 9, 2010 to July 19,
2010. The ballot achieved a quorum of 86.18%, and an approval of 65.93%. Based on
the comments received, modifications were made to the standard, including:
•
Redefining the Glossary term for ROW to address Paragraph 734 of FERC Order
693 and the width of ROW to be maintained;
•
Redefining the Glossary term for Vegetation Inspection to include identifying
hazards to the line inside the ROW;
•
Removing Section 4.4 and footnote 2 addressing “force majeure” and addressing
the issue in new footnotes 2, 3 and 4;
•
Changing “qualified personnel” to “Transmission Owner” in R4;
•
Adding the phrase “but no more than 18 months between inspections” in R6;
•
Deleting Table 3 from the Guidelines and Technical Basis section.
65
Additional changes to the standard were made based on recommendations from members
of the standard’s “Quality Review” team. Quality Review teams are ad-hoc teams that
provide focused compliance and legal feedback on standards and associated documents
related to wording, enforceability, structure, grammar, and similar subject areas.
viii.
The Fifth Posting and Successive Ballot
The fifth draft of FAC-003-2 was posted for formal comment from January 27,
2011 to February 28, 2011. A mapping document and a technical reference document
were provided to industry to assist in the review of the standard. Forty-one sets of
comments were received, representing 9 of the 10 Industry Segments within NERC’s
stakeholder structure. A successive ballot of the standard was conducted from February
18, 2011 to February 28, 2011. The ballot achieved a quorum of 79.28%, and an
approval of 79.34%. A non-binding poll was conducted for the VRFs and VSLs. Of
those who registered to participate, 77% provided an opinion; and 79% of those who
provided an opinion indicated support for the VRFs and VSLs that were proposed.
Around the time of the fifth posting and successive ballot, the Standards
Committee approved the 2011-2013 Reliability Standards Development Plan, which
lowered the priority of this project relative to other work and moved this project into
informal development. With this move, NERC resources supporting this project were
reassigned to higher-priority projects. The standards drafting team worked independently
to respond to comments and finalize the standard. Based on comments received during
66
the comment and ballot, the definition of MVCD was added. A number of clarifications
to the standard language were also undertaken during this time.
Additionally, during this period, the chair of the Standards Committee identified
some potential concerns with the standard and requested that the team answer several
focused questions. The team developed responses to these questions (included in the
Project 2007-07 Vegetation Management Consideration of Issues and Directives
document included in the Complete Development History attached as Exhibit G), as well
as several other supporting documents used during the recirculation ballot.
ix.
The Sixth Posting and Recirculation Ballot
The sixth and final draft of FAC-003-2 was posted for recirculation ballot from
October 4, 2011, to October 13, 2011. An updated mapping document and technical
reference document were provided to industry to assist in the review of the standard.
Other supporting documents were prepared to further assist in the review, including a
document demonstrating the manner in which FERC directives (as well as other issues)
were addressed, an analysis of how the VSLs and VRFs complied with NERC and FERC
guidelines, an updated implementation plan, and responses to the questions asked by the
Chair of the Standards Committee. The ballot achieved a quorum of 87.17%, and an
approval of 86.25%.
x.
Board of Trustees Approval
The final draft of FAC-003 was presented to NERC’s Board of Trustees for
approval on November 3, 2011. NERC staff provided a summary of the improvements
made to the standard, as well as a summary of minority issues and associated drafting
team responses. NERC staff also proposed an alternative set of VSLs for requirements
67
R1 and R2, because they believed the VSLs proposed by the drafting team did not meet
NERC guidelines. The Board of Trustees approved the standard, and the NERC staff
recommended VSLs for Requirements R1 and R2 and directed that it be filed with
applicable regulatory authorities.
VII.
CONCLUSION
Accordingly, the proposed FAC-003-2 Reliability Standard should be approved
because it serves the important reliability goal of ensuring that each applicable entity will
manage vegetation in accordance with the standard. Additionally, the proposed standard
presents three important themes that all help to improve reliability. First, reliability will
be improved with implementation of the new standard. Second, enforceability of FAC003-2, as compared to FAC-003-1, will be improved and cleaner for NERC and the
Regional Entities. And third, NERC registered entities will have greater flexibility to
address local vegetation management conditions.
For the reasons set forth above, NERC respectfully requests that the
Commission:
•
approve FAC-003-2 and the associated Violation Risk Factors and Violation
Severity Levels included in Exhibit A, effective the first day of the first
calendar quarter that is twelve months following the effective date of a Final
Rule in this docket;
•
approve the implementation plan for FAC-003-2 included in Exhibit B;
•
approve the three definitions included in Exhibit C to be added to the NERC
Glossary of Terms Used in NERC Reliability Standards effective the first day
of the first calendar quarter that is twelve months following the effective date
of a Final Rule in this docket:
o Right-of-Way (ROW)
68
o Vegetation Inspection
o Minimum Vegetation Clearance Distance (MVCD)
•
approve the retirement of FAC-003-1 and the currently effective definitions of
“Right-of-Way” and “Vegetation Inspection” effective midnight immediately
prior to the first day of the first calendar quarter that is twelve months
following the effective date of a Final Rule in this docket.
Respectfully submitted,
Gerald W. Cauley
President and Chief Executive Officer
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326-1001
David N. Cook
Senior Vice President and General Counsel
North American Electric Reliability
Corporation
1120 G Street N.W., Suite 990
Washington, D.C. 20005-3801
[email protected]
Holly A. Hawkins
Assistant General Counsel for Standards and
Critical Infrastructure Protection
Andrew M. Dressel
Attorney
North American Electric Reliability
Corporation
1120 G Street, N.W., Suite 990
Washington, D.C. 20005-3801
(202) 393-3998
(202) 393-3955 – facsimile
[email protected]
[email protected]
69
CERTIFICATE OF SERVICE
I hereby certify that I have served a copy of the foregoing document upon all
parties listed on the official service list compiled by the Secretary in this proceeding.
Dated at Washington, D.C. this 21st day of December, 2011.
/s/ Holly A. Hawkins
Holly A. Hawkins
Assistant General Counsel for North
American Electric Reliability
Corporation
Exhibit A
Reliability Standard FAC-003-2 — Transmission Vegetation Management submitted
for Approval
FAC-003-2 — Transmission Vegetation Management
Effective Dates
This standard becomes effective on the first calendar day of the first calendar quarter one year after the date of the order approving
the standard from applicable regulatory authorities where such explicit approval is required. Where no regulatory approval is
required, the standard becomes effective on the first calendar day of the first calendar quarter one year after Board of Trustees
adoption.
Requirement
R1 – R7
Jurisdiction
Alberta
British
Columbia
Manitoba
New
Brunswick
Newfoundland
Nova
Scotia
Ontario
Quebec
Saskatchewan
USA
TBD
TBD
TBD
TBD
TBD
TBD
TBD
TBD
TBD
TBD
(All Req.)
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of an Interconnection Reliability
Operating Limit (IROL) or designated by the Western Electricity Coordinating Council (WECC) as an element of a Major WECC
Transfer Path, becomes subject to this standard the latter of: 1) 12 months after the date the Planning Coordinator or WECC
initially designates the line as being an element of an IROL or an element of a Major WECC Transfer Path, or 2) January 1 of
the planning year when the line is forecast to become an element of an IROL or an element of a Major WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element of an IROL or a Major WECC Transfer
Path which has a specified date for the removal of such designation will no longer be subject to this standard effective on
that specified date.
Adopted by the Board of Trustees: November 3, 2011
1
FAC-003-2 — Transmission Vegetation Management
3. A line operated at 200 kV or above, currently subject to this standard which is a designated element of an IROL or a Major
WECC Transfer Path and which has a specified date for the removal of such designation will be subject to Requirement R2
and no longer be subject to Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an asset owner and which was not
previously subject to this standard becomes subject to this standard 12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset owner and which was not previously
subject to this standard becomes subject to this standard 12 months after the acquisition date of the line if at the time of
acquisition the line is designated by the Planning Coordinator as an element of an IROL or by WECC as an element of a Major
WECC Transfer Path.
Adopted by the Board of Trustees: November 3, 2011
2
FAC-003-2 — Transmission Vegetation Management
A. Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-2
3. Purpose:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of
way (ROW) and minimize encroachments from vegetation located
adjacent to the ROW, thus preventing the risk of those vegetation-related
outages that could lead to Cascading.
4. Applicability
4.1.
Functional Entities:
4.1.1 Transmission Owners
4.2.
Facilities: Defined below (referred to as “applicable lines”), including but not
limited to those that cross lands owned by federal 1, state, provincial, public,
private, or tribal entities:
4.2.1. Each overhead transmission line operated at 200kV or higher.
4.2.2. Each overhead transmission line operated below 200kV identified as an
element of an IROL under NERC Standard FAC-014 by the Planning
Coordinator.
4.2.3. Each overhead transmission line operated below 200 kV identified as an
element of a Major WECC Transfer Path in the Bulk Electric System by
WECC.
4.2.4. Each overhead transmission line identified above (4.2.1 through 4.2.3)
located outside the fenced area of the switchyard, station or substation
and any portion of the span of the transmission line that is crossing the
substation fence.
5. Background:
This standard uses three types of requirements to provide layers of protection to
prevent vegetation related outages that could lead to Cascading:
a)
Performance-based defines a particular reliability objective or outcome to be
achieved. In its simplest form, a results-based requirement has four
1
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
Adopted by the Board of Trustees: November 3, 2011
3
FAC-003-2 — Transmission Vegetation Management
components: who, under what conditions (if any), shall perform what action, to
achieve what particular bulk power system performance result or outcome?
b)
Risk-based preventive requirements to reduce the risks of failure to acceptable
tolerance levels. A risk-based reliability requirement should be framed as: who,
under what conditions (if any), shall perform what action, to achieve what
particular result or outcome that reduces a stated risk to the reliability of the bulk
power system?
c)
Competency-based defines a minimum set of capabilities an entity needs to
have to demonstrate it is able to perform its designated reliability functions. A
competency-based reliability requirement should be framed as: who, under what
conditions (if any), shall have what capability, to achieve what particular result or
outcome to perform an action to achieve a result or outcome or to reduce a risk
to the reliability of the bulk power system?
The defense-in-depth strategy for reliability standards development recognizes that
each requirement in a NERC reliability standard has a role in preventing system failures,
and that these roles are complementary and reinforcing. Reliability standards should
not be viewed as a body of unrelated requirements, but rather should be viewed as
part of a portfolio of requirements designed to achieve an overall defense-in-depth
strategy and comport with the quality objectives of a reliability standard.
This standard uses a defense-in-depth approach to improve the reliability of the
electric Transmission system by:
• Requiring that vegetation be managed to prevent vegetation encroachment
inside the flash-over clearance (R1 and R2);
• Requiring documentation of the maintenance strategies, procedures, processes
and specifications used to manage vegetation to prevent potential flash-over
conditions including consideration of 1) conductor dynamics and 2) the
interrelationships between vegetation growth rates, control methods and the
inspection frequency (R3);
• Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash-over at any moment (R4);
• Requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains such as legal injunctions (R5);
• Requiring inspections of vegetation conditions to be performed annually (R6);
and
• Requiring that the annual work needed to prevent flash-over is completed (R7).
For this standard, the requirements have been developed as follows:
•
Performance-based: Requirements 1 and 2
•
Competency-based: Requirement 3
Adopted by the Board of Trustees: November 3, 2011
4
FAC-003-2 — Transmission Vegetation Management
•
Risk-based: Requirements 4, 5, 6 and 7
R3 serves as the first line of defense by ensuring that entities understand the problem
they are trying to manage and have fully developed strategies and plans to manage the
problem. R1, R2, and R7 serve as the second line of defense by requiring that entities
carry out their plans and manage vegetation. R6, which requires inspections, may be
either a part of the first line of defense (as input into the strategies and plans) or as a
third line of defense (as a check of the first and second lines of defense). R4 serves as
the final line of defense, as it addresses cases in which all the other lines of defense
have failed.
Major outages and operational problems have resulted from interference between
overgrown vegetation and transmission lines located on many types of lands and
ownership situations. Adherence to the standard requirements for applicable lines on
any kind of land or easement, whether they are Federal Lands, state or provincial lands,
public or private lands, franchises, easements or lands owned in fee, will reduce and
manage this risk. For the purpose of the standard the term “public lands” includes
municipal lands, village lands, city lands, and a host of other governmental entities.
This standard addresses vegetation management along applicable overhead lines and
does not apply to underground lines, submarine lines or to line sections inside an
electric station boundary.
This standard focuses on transmission lines to prevent those vegetation related outages
that could lead to Cascading. It is not intended to prevent customer outages due to tree
contact with lower voltage distribution system lines. For example, localized customer
service might be disrupted if vegetation were to make contact with a 69kV transmission
line supplying power to a 12kV distribution station. However, this standard is not
written to address such isolated situations which have little impact on the overall
electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses
an increased outage risk, especially when numerous transmission lines are operating at
or near their Rating. This can present a significant risk of consecutive line failures when
lines are experiencing large sags thereby leading to Cascading. Once the first line fails
the shift of the current to the other lines and/or the increasing system loads will lead to
the second and subsequent line failures as contact to the vegetation under those lines
occurs. Conversely, most other outage causes (such as trees falling into lines, lightning,
animals, motor vehicles, etc.) are not an interrelated function of the shift of currents or
the increasing system loading. These events are not any more likely to occur during
heavy system loads than any other time. There is no cause-effect relationship which
creates the probability of simultaneous occurrence of other such events. Therefore
these types of events are highly unlikely to cause large-scale grid failures. Thus, this
standard places the highest priority on the management of vegetation to prevent
vegetation grow-ins.
Adopted by the Board of Trustees: November 3, 2011
5
FAC-003-2 — Transmission Vegetation Management
B. Requirements and Measures
R1. Each Transmission Owner shall manage vegetation to prevent encroachments into the
MVCD of its applicable line(s) which are either an element of an IROL, or an element of
a Major WECC Transfer Path; operating within their Rating and all Rated Electrical
Operating Conditions of the types shown below 2 [Violation Risk Factor: High] [Time
Horizon: Real-time]:
1. An encroachment into the MVCD as shown in FAC-003-Table 2, observed in Realtime, absent a Sustained Outage, 3
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage, 4
3. An encroachment due to the blowing together of applicable lines and vegetation
located inside the ROW that caused a vegetation-related Sustained Outage,4
4. An encroachment due to vegetation growth into the MVCD that caused a
vegetation-related Sustained Outage.4
M1. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-time observations of any MVCD encroachments. (R1)
R2. Each Transmission Owner shall manage vegetation to prevent encroachments into the
MVCD of its applicable line(s) which are not either an element of an IROL, or an
element of a Major WECC Transfer Path; operating within its Rating and all Rated
Electrical Operating Conditions of the types shown below2 [Violation Risk Factor:
Medium] [Time Horizon: Real-time]:
1. An encroachment into the MVCD, observed in Real-time, absent a Sustained
Outage,3
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage,4
3. An encroachment due to blowing together of applicable lines and vegetation
located inside the ROW that caused a vegetation-related Sustained Outage,4
2
This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to this
reliability standard, including natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh
gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice storms, and floods;
human or animal activity such as logging, animal severing tree, vehicle contact with tree, or installation, removal, or digging of
vegetation. Nothing in this footnote should be construed to limit the Transmission Owner’s right to exercise its full legal rights
on the ROW.
3
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation encroachment within the MVCD has
occurred from vegetation within the ROW, this shall be considered the equivalent of a Real-time observation.
4
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage regardless
of the actual number of outages within a 24-hour period.
Adopted by the Board of Trustees: November 3, 2011
6
FAC-003-2 — Transmission Vegetation Management
4. An encroachment due to vegetation growth into the line MVCD that caused a
vegetation-related Sustained Outage4
M2. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R2. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-time observations of any MVCD encroachments. (R2)
R3. Each Transmission Owner shall have documented maintenance
strategies or procedures or processes or specifications it uses to
prevent the encroachment of vegetation into the MVCD of its
applicable lines that accounts for the following:
3.1 Movement of applicable line conductors under their Rating and
all Rated Electrical Operating Conditions;
3.2 Inter-relationships between vegetation growth rates,
vegetation control methods, and inspection frequency.
[Violation Risk Factor: Lower] [Time Horizon: Long Term Planning]:
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the Transmission Owner can prevent encroachment into the MVCD
considering the factors identified in the requirement. (R3)
R4. Each Transmission Owner, without any intentional time delay, shall notify the control
center holding switching authority for the associated applicable line when the
Transmission Owner has confirmed the existence of a vegetation condition that is
likely to cause a Fault at any moment [Violation Risk Factor: Medium] [Time Horizon:
Real-time].
M4. Each Transmission Owner that has a confirmed vegetation condition likely to cause a
Fault at any moment will have evidence that it notified the control center holding
switching authority for the associated transmission line without any intentional time
delay. Examples of evidence may include control center logs, voice recordings,
switching orders, clearance orders and subsequent work orders. (R4)
R5. When a Transmission Owner is constrained from performing vegetation work on an
applicable line operating within its Rating and all Rated Electrical Operating
Conditions, and the constraint may lead to a vegetation encroachment into the MVCD
prior to the implementation of the next annual work plan, then the Transmission
Owner shall take corrective action to ensure continued vegetation management to
prevent encroachments [Violation Risk Factor: Medium] [Time Horizon: Operations
Planning].
Adopted by the Board of Trustees: November 3, 2011
7
FAC-003-2 — Transmission Vegetation Management
M5. Each Transmission Owner has evidence of the corrective action taken for each
constraint where an applicable transmission line was put at potential risk. Examples
of acceptable forms of evidence may include initially-planned work orders,
documentation of constraints from landowners, court orders, inspection records of
increased monitoring, documentation of the de-rating of lines, revised work orders,
invoices, or evidence that the line was de-energized. (R5)
R6. Each Transmission Owner shall perform a Vegetation Inspection of 100% of its
applicable transmission lines (measured in units of choice - circuit, pole line, line miles
or kilometers, etc.) at least once per calendar year and with no more than 18 calendar
months between inspections on the same ROW 5 [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning].
M6. Each Transmission Owner has evidence that it conducted Vegetation Inspections of
the transmission line ROW for all applicable lines at least once per calendar year but
with no more than 18 calendar months between inspections on the same ROW.
Examples of acceptable forms of evidence may include completed and dated work
orders, dated invoices, or dated inspection records. (R6)
R7. Each Transmission Owner shall complete 100% of its annual vegetation work plan of
applicable lines to ensure no vegetation encroachments occur within the MVCD.
Modifications to the work plan in response to changing conditions or to findings from
vegetation inspections may be made (provided they do not allow encroachment of
vegetation into the MVCD) and must be documented. The percent completed
calculation is based on the number of units actually completed divided by the number
of units in the final amended plan (measured in units of choice - circuit, pole line, line
miles or kilometers, etc.) Examples of reasons for modification to annual plan may
include [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]:
• Change in expected growth rate/ environmental factors
• Circumstances that are beyond the control of a Transmission Owner 6
• Rescheduling work between growing seasons
• Crew or contractor availability/ Mutual assistance agreements
• Identified unanticipated high priority work
• Weather conditions/Accessibility
• Permitting delays
• Land ownership changes/Change in land use by the landowner
• Emerging technologies
5
When the Transmission Owner is prevented from performing a Vegetation Inspection within the timeframe in R6 due to a
natural disaster, the TO is granted a time extension that is equivalent to the duration of the time the TO was prevented from
performing the Vegetation Inspection.
6
Circumstances that are beyond the control of a Transmission Owner include but are not limited to natural disasters such as
earthquakes, fires, tornados, hurricanes, landslides, ice storms, floods, or major storms as defined either by the TO or an
applicable regulatory body.
Adopted by the Board of Trustees: November 3, 2011
8
FAC-003-2 — Transmission Vegetation Management
M7. Each Transmission Owner has evidence that it completed its annual vegetation work
plan for its applicable lines. Examples of acceptable forms of evidence may include a
copy of the completed annual work plan (as finally modified), dated work orders,
dated invoices, or dated inspection records. (R7)
C. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
1.2 Regional Entity Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period
since the last audit.
The Transmission Owner retains data or evidence to show compliance with
Requirements R1, R2, R3, R5, R6 and R7, Measures M1, M2, M3, M5, M6 and M7
for three calendar years unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
The Transmission Owner retains data or evidence to show compliance with
Requirement R4, Measure M4 for most recent 12 months of operator logs or
most recent 3 months of voice recordings or transcripts of voice recordings,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If a Transmission Owner is found non-compliant, it shall keep information related
to the non-compliance until found compliant or for the time period specified
above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3 Compliance Monitoring and Enforcement Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Adopted by the Board of Trustees: November 3, 2011
9
FAC-003-2 — Transmission Vegetation Management
Complaint
Periodic Data Submittal
1.4 Additional Compliance Information
Periodic Data Submittal: The Transmission Owner will submit a quarterly report
to its Regional Entity, or the Regional Entity’s designee, identifying all Sustained
Outages of applicable lines operated within their Rating and all Rated Electrical
Operating Conditions as determined by the Transmission Owner to have been
caused by vegetation, except as excluded in footnote 2, and including as a
minimum the following:
o The name of the circuit(s), the date, time and duration of the outage;
the voltage of the circuit; a description of the cause of the outage; the
category associated with the Sustained Outage; other pertinent
comments; and any countermeasures taken by the Transmission
Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, that are identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, but are not identified as an element of
an IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by
vegetation and applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, blowing together from within the
ROW.
o Category 4B — Blowing together: Sustained Outages caused by
vegetation and applicable lines, but are not identified as an element
Adopted by the Board of Trustees: November 3, 2011
10
FAC-003-2 — Transmission Vegetation Management
of an IROL or Major WECC Transfer Path, blowing together from
within the ROW.
The Regional Entity will report the outage information provided by Transmission
Owners, as per the above, quarterly to NERC, as well as any actions taken by the
Regional Entity as a result of any of the reported Sustained Outages.
Adopted by the Board of Trustees: November 3, 2011
11
FAC-003-2 — Transmission Vegetation Management
Table of Compliance Elements
R#
Time
Horizon
VRF
Violation Severity Level
Lower
N/A
R1
Real-time
Moderate
N/A
High
High
Severe
The Transmission Owner failed
to manage vegetation to
prevent encroachment into the
MVCD of a line identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
The Transmission Owner failed
to manage vegetation to
prevent encroachment into the
MVCD of a line identified as an
element of an IROL or Major
WECC transfer path and a
vegetation-related Sustained
Outage was caused by one of
the following:
•
•
•
N/A
R2
Real-time
Medium
Adopted by the Board of Trustees: November 3, 2011
N/A
The Transmission Owner failed
to manage vegetation to
prevent encroachment into the
MVCD of a line not identified
as an element of an IROL or
Major WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
12
A fall-in from inside the
active transmission line
ROW
Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
A grow-in
The Transmission Owner failed
to manage vegetation to
prevent encroachment into the
MVCD of a line not identified
as an element of an IROL or
Major WECC transfer path and
a vegetation-related Sustained
Outage was caused by one of
the following:
•
A fall-in from inside the
FAC-003-2 — Transmission Vegetation Management
•
•
R3
R4
R5
Long-Term
Planning
Real-time
Operations
Planning
active transmission line
ROW
Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
A grow-in
N/A
The Transmission Owner has
maintenance strategies or
documented procedures or
processes or specifications
but has not accounted for the
inter-relationships between
vegetation growth rates,
vegetation control methods,
and inspection frequency, for
the Transmission Owner’s
applicable lines.
(Requirement R3, Part 3.2)
The Transmission Owner has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
movement of transmission line
conductors under their Rating
and all Rated Electrical
Operating Conditions, for the
Transmission Owner’s
applicable lines. Requirement
R3, Part 3.1)
The Transmission Owner does
not have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent
the encroachment of
vegetation into the MVCD, for
the Transmission Owner’s
applicable lines.
N/A
N/A
The Transmission Owner
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
applicable line, but there was
intentional delay in that
notification.
The Transmission Owner
experienced a confirmed
vegetation threat and did not
notify the control center
holding switching authority for
that applicable line.
N/A
N/A
N/A
The Transmission Owner did
not take corrective action
when it was constrained from
performing planned vegetation
work where an applicable line
Lower
Medium
Medium
Adopted by the Board of Trustees: November 3, 2011
13
FAC-003-2 — Transmission Vegetation Management
was put at potential risk.
R6
R7
Operations
Planning
Operations
Planning
Medium
The Transmission Owner
failed to inspect 5% or less
of its applicable lines
(measured in units of
choice - circuit, pole line,
line miles or kilometers,
etc.)
The Transmission Owner
failed to inspect more than
5% up to and including 10% of
its applicable lines (measured
in units of choice - circuit,
pole line, line miles or
kilometers, etc.).
The Transmission Owner failed
to inspect more than 10% up
to and including 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The Transmission Owner failed
to inspect more than 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
Medium
The Transmission Owner
failed to complete 5% or
less of its annual
vegetation work plan for
its applicable lines (as
finally modified).
The Transmission Owner
failed to complete more than
5% and up to and including
10% of its annual vegetation
work plan for its applicable
lines (as finally modified).
The Transmission Owner failed
to complete more than 10%
and up to and including 15% of
its annual vegetation work
plan for its applicable lines (as
finally modified).
The Transmission Owner failed
to complete more than 15% of
its annual vegetation work plan
for its applicable lines (as
finally modified).
D. Regional Differences
None.
E. Interpretations
None.
F. Associated Documents
Guideline and Technical Basis (attached).
Adopted by the Board of Trustees: November 3, 2011
14
FAC-003-2 — Transmission Vegetation Management
Guideline and Technical Basis
Enforcement:
The Requirements within a Reliability Standard govern and will be enforced. The Requirements within a Reliability Standard define
what an entity must do to be compliant and binds an entity to certain obligations of performance under Section 215 of the Federal
Power Act. Compliance will in all cases be measured by determining whether a party met or failed to meet the Reliability Standard
Requirement given the specific facts and circumstances of its use, ownership or operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are the evidence that could be
presented to demonstrate compliance with a Reliability Standard Requirement and are not intended to contain the quantitative
metrics for determining satisfactory performance nor to limit how an entity may demonstrate compliance if valid alternatives to
demonstrating compliance are available in a specific case. A Reliability Standard may be enforced in the absence of specified
Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative Procedure that sets forth, among
other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with “Examples” and “Rationale” are provided
for informational purposes. They are designed to convey guidance from NERC’s various activities. The “Guideline and Technical
Basis” section and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements under NERC’s
Reliability Standards or to modify the Requirements in any existing NERC Reliability Standard. Implementation of the “Guideline and
Technical Basis” section, the Background section and text boxes with “Examples” and “Rationale” is not a substitute for compliance
with Requirements in NERC’s Reliability Standards.”
Effective dates:
The first two sentences of the Effective Dates section is standard language used in most NERC standards to cover the general
effective date and is sufficient to cover the vast majority of situations. Five special cases are needed to cover effective dates for
individual lines which undergo transitions after the general effective date. These special cases cover the effective dates for those
Adopted by the Board of Trustees: November 3, 2011
15
FAC-003-2 — Transmission Vegetation Management
lines which are initially becoming subject to the standard, those lines which are changing their applicability within the standard, and
those lines which are changing in a manner that removes their applicability to the standard.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to become elements of an IROL or Major
WECC Transfer Path in a future Planning Year (PY). For example, studies by the Planning Coordinator in 2011 may identify a line to
have that designation beginning in PY 2021, ten years after the planning study is performed. It is not intended for the Standard to
be immediately applicable to, or in effect for, that line until that future PY begins. The effective date provision for such lines ensures
that the line will become subject to the standard on January 1 of the PY specified with an allowance of at least 12 months for the
Transmission Owner to make the necessary preparations to achieve compliance on that line. The table below has some explanatory
examples of the application.
Date that
Planning Study is
completed
05/15/2011
05/15/2011
05/15/2011
05/15/2011
PY the line
will become
an IROL
element
2012
2013
2014
2021
Date 1
05/15/2012
05/15/2012
05/15/2012
05/15/2012
Date 2
01/01/2012
01/01/2013
01/01/2014
01/01/2021
Effective Date
The latter of Date 1
or Date 2
05/15/2012
01/01/2013
01/01/2014
01/01/2021
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or Major WECC Transfer Path may be
removed from that designation due to system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network.
Case 3 is needed because a line operating at 200 kV or above that once was designated as an element of an IROL or Major WECC
Transfer Path may be removed from that designation due to system improvements, changes in generation, changes in loads or
changes in studies and analysis of the network. Such changes result in the need to apply R1 to that line until that date is reached
and then to apply R2 to that line thereafter.
Adopted by the Board of Trustees: November 3, 2011
16
FAC-003-2 — Transmission Vegetation Management
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be acquired by a Transmission Owner from a
third party such as a Distribution Provider or other end-user who was using the line solely for local distribution purposes, but the
Transmission Owner, upon acquisition, is incorporating the line into the interconnected electrical energy transmission network
which will thereafter make the line subject to the standard.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by a Transmission Owner from a third party
such as a Distribution Provider or other end-user who was using the line solely for local distribution purposes, but the Transmission
owner, upon acquisition, is incorporating the line into the interconnected electrical energy transmission network. In this special case
the line upon acquisition was designated as an element of an Interconnection Reliability Operating Limit (IROL) or an element of a
Major WECC Transfer Path.
Defined Terms:
Explanation for revising the definition of ROW:
The current NERC glossary definition of Right of Way has been modified to address the matter set forth in Paragraph 734 of FERC
Order 693. The Order pointed out that Transmission Owners may in some cases own more property or rights than are needed to
reliably operate transmission lines. This modified definition represents a slight but significant departure from the strict legal definition
of “right of way” in that this definition is based on engineering and construction considerations that establish the width of a corridor
from a technical basis. The pre-2007 maintenance records are included in the revised definition to allow the use of such vegetation
widths if there were no engineering or construction standards that referenced the width of right of way to be maintained for
vegetation on a particular line but the evidence exists in maintenance records for a width that was in fact maintained prior to this
standard becoming mandatory. Such widths may be the only information available for lines that had limited or no vegetation
easement rights and were typically maintained primarily to ensure public safety. This standard does not require additional easement
rights to be purchased to satisfy a minimum right of way width that did not exist prior to this standard becoming mandatory.
Explanation for revising the definition of Vegetation Inspections:
The current glossary definition of this NERC term is being modified to allow both maintenance inspections and vegetation inspections
to be performed concurrently. This allows potential efficiencies, especially for those lines with minimal vegetation and/or slow
vegetation growth rates.
Explanation of the definition of the MVCD:
Adopted by the Board of Trustees: November 3, 2011
17
FAC-003-2 — Transmission Vegetation Management
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a method of calculating a flash over
distance that has been used in the design of high voltage transmission lines. Keeping vegetation away from high voltage conductors
by this distance will prevent voltage flash-over to the vegetation. See the explanatory text below for Requirement R3 and associated
Figure 1. Table 2 below provides MVCD values for various voltages and altitudes. Details of the equations and an example calculation
are provided in Appendix 1 of the Technical Reference Document.
Guidelines:
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be achieved is the management of vegetation
such that there are no vegetation encroachments within a minimum distance of transmission lines. Content-wise, R1 and R2 are the
same requirements; however, they apply to different Facilities. Both R1 and R2 require each Transmission Owner to manage
vegetation to prevent encroachment within the MVCD of transmission lines. R1 is applicable to lines that are identified as an element
of an IROL or Major WECC Transfer Path. R2 is applicable to all other lines that are not elements of IROLs, and not elements of Major
WECC Transfer Paths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation management for an applicable line that is
an element of an IROL or a Major WECC Transfer Path is a greater risk to the interconnected electric transmission system than
applicable lines that are not elements of IROLs or Major WECC Transfer Paths. Applicable lines that are not elements of IROLs or
Major WECC Transfer Paths do require effective vegetation management, but these lines are comparatively less operationally
significant. As a reflection of this difference in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and Medium
for R2.
Requirements R1 and R2 state that if inadequate vegetation management allows vegetation to encroach within the MVCD distance
as shown in Table 2, it is a violation of the standard. Table 2 distances are the minimum clearances that will prevent spark-over
based on the Gallet equations as described more fully in the Technical Reference document.
These requirements assume that transmission lines and their conductors are operating within their Rating. If a line conductor is
intentionally or inadvertently operated beyond its Rating and Rated Electrical Operating Condition (potentially in violation of other
standards), the occurrence of a clearance encroachment may occur solely due to that condition. For example, emergency actions
taken by a Transmission Operator or Reliability Coordinator to protect an Interconnection may cause excessive sagging and an
outage. Another example would be ice loading beyond the line’s Rating and Rated Electrical Operating Condition. Such vegetationrelated encroachments and outages are not violations of this standard.
Adopted by the Board of Trustees: November 3, 2011
18
FAC-003-2 — Transmission Vegetation Management
Evidence of failures to adequately manage vegetation include real-time observation of a vegetation encroachment into the MVCD
(absent a Sustained Outage), or a vegetation-related encroachment resulting in a Sustained Outage due to a fall-in from inside the
ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to the blowing together of the lines and vegetation
located inside the ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to a grow-in. Faults which do not
cause a Sustained outage and which are confirmed to have been caused by vegetation encroachment within the MVCD are
considered the equivalent of a Real-time observation for violation severity levels.
With this approach, the VSLs for R1 and R2 are structured such that they directly correlate to the severity of a failure of a
Transmission Owner to manage vegetation and to the corresponding performance level of the Transmission Owner’s vegetation
program’s ability to meet the objective of “preventing the risk of those vegetation related outages that could lead to Cascading.”
Thus violation severity increases with a Transmission Owner’s inability to meet this goal and its potential of leading to a Cascading
event. The additional benefits of such a combination are that it simplifies the standard and clearly defines performance for
compliance. A performance-based requirement of this nature will promote high quality, cost effective vegetation management
programs that will deliver the overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For example initial investigations and
corrective actions may not identify and remove the actual outage cause then another outage occurs after the line is re-energized
and previous high conductor temperatures return. Such events are considered to be a single vegetation-related Sustained Outage
under the standard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for various altitudes and operating
voltages that is used in the design of Transmission Facilities. Keeping vegetation from entering this space will prevent transmission
outages.
If the Transmission Owner has applicable lines operated at nominal voltage levels not listed in Table 2, then the TO should use the
next largest clearance distance based on the next highest nominal voltage in the table to determine an acceptable distance.
Requirement R3:
R3 is a competency based requirement concerned with the maintenance strategies, procedures, processes, or specifications, a
Transmission Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the Transmission Owner uses to plan
and perform vegetation work to prevent transmission Sustained Outages and minimize risk to the transmission system. The
approach provides the basis for evaluating the intent, allocation of appropriate resources, and the competency of the Transmission
Adopted by the Board of Trustees: November 3, 2011
19
FAC-003-2 — Transmission Vegetation Management
Owner in managing vegetation. There are many acceptable approaches to manage vegetation and avoid Sustained Outages.
However, the Transmission Owner must be able to show the documentation of its approach and how it conducts work to maintain
clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7. However, regardless of the approach a
utility uses to manage vegetation, any approach a Transmission Owner chooses to use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or maximum vegetation height) to
ensure that MVCD clearances are never violated.
2. the work methods that the Transmission Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing in reaction to a number of different loading variables.
Changes in vertical and horizontal conductor positioning are the result of thermal and physical loads applied to the line. Thermal
loading is a function of line current and the combination of numerous variables influencing ambient heat dissipation including wind
velocity/direction, ambient air temperature and precipitation. Physical loading applied to the conductor affects sag and sway by
combining physical factors such as ice and wind loading. The movement of the transmission line conductor and the MVCD is
illustrated in Figure 1 below. In the Technical Reference document more figures and explanations of conductor dynamics are
provided.
Adopted by the Board of Trustees: November 3, 2011
20
FAC-003-2 — Transmission Vegetation Management
Figure 1
A cross-section view of a single conductor at a given point along the span is shown with six possible conductor
positions due to movement resulting from thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the Transmission Owner for the mitigation of Fault
risk when a vegetation threat is confirmed. R4 involves the notification of potentially threatening vegetation conditions, without any
intentional delay, to the control center holding switching authority for that specific transmission line. Examples of acceptable
unintentional delays may include communication system problems (for example, cellular service or two-way radio disabled), crews
located in remote field locations with no communication access, delays due to severe weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in the form of a Transmission Owner’s
employee who personally identifies such a threat in the field. Confirmation could also be made by sending out an employee to
evaluate a situation reported by a landowner.
Adopted by the Board of Trustees: November 3, 2011
21
FAC-003-2 — Transmission Vegetation Management
Vegetation-related conditions that warrant a response include vegetation that is near or encroaching into the MVCD (a grow-in
issue) or vegetation that could fall into the transmission conductor (a fall-in issue). A knowledgeable verification of the risk would
include an assessment of the possible sag or movement of the conductor while operating between no-load conditions and its rating.
The Transmission Owner has the responsibility to ensure the proper communication between field personnel and the control center
to allow the control center to take the appropriate action until or as the vegetation threat is relieved. Appropriate actions may
include a temporary reduction in the line loading, switching the line out of service, or other preparatory actions in recognition of the
increased risk of outage on that circuit. The notification of the threat should be communicated in terms of minutes or hours as
opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at any moment. For example, some
Transmission Owners may have a danger tree identification program that identifies trees for removal with the potential to fall near
the line. These trees would not require notification to the control center unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the Transmission Owner for the mitigation of
Sustained Outage risk when temporarily constrained from performing vegetation maintenance. The intent of this requirement is to
deal with situations that prevent the Transmission Owner from performing planned vegetation management work and, as a result,
have the potential to put the transmission line at risk. Constraints to performing vegetation maintenance work as planned could
result from legal injunctions filed by property owners, the discovery of easement stipulations which limit the Transmission Owner’s
rights, or other circumstances.
This requirement is not intended to address situations where the transmission line is not at potential risk and the work event can be
rescheduled or re-planned using an alternate work methodology. For example, a land owner may prevent the planned use of
chemicals on non-threatening, low growth vegetation but agree to the use of mechanical clearing. In this case the Transmission
Owner is not under any immediate time constraint for achieving the management objective, can easily reschedule work using an
alternate approach, and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint, the Transmission Owner is required
to take an interim corrective action to mitigate the potential risk to the transmission line. A wide range of actions can be taken to
address various situations. General considerations include:
Adopted by the Board of Trustees: November 3, 2011
22
FAC-003-2 — Transmission Vegetation Management
•
Identifying locations where the Transmission Owner is constrained from performing planned vegetation maintenance
work which potentially leaves the transmission line at risk.
•
Developing the specific action to mitigate any potential risk associated with not performing the vegetation maintenance
work as planned.
•
Documenting and tracking the specific action taken for the location.
•
In developing the specific action to mitigate the potential risk to the transmission line the Transmission Owner could
consider location specific measures such as modifying the inspection and/or maintenance intervals. Where a legal
constraint would not allow any vegetation work, the interim corrective action could include limiting the loading on the
transmission line.
•
The Transmission Owner should document and track the specific corrective action taken at each location. This location
may be indicated as one span, one tree or a combination of spans on one property where the constraint is considered to
be temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing Vegetation Inspections. The provision
that Vegetation Inspections can be performed in conjunction with general line inspections facilitates a Transmission Owner’s ability
to meet this requirement. However, the Transmission Owner may determine that more frequent vegetation specific inspections are
needed to maintain reliability levels, based on factors such as anticipated growth rates of the local vegetation, length of the local
growing season, limited ROW width, and local rainfall. Therefore it is expected that some transmission lines may be designated with
a higher frequency of inspections.
The VSLs for Requirement R6 have levels ranked by the failure to inspect a percentage of the applicable lines to be inspected. To
calculate the appropriate VSL the Transmission Owner may choose units such as: circuit, pole line, line miles or kilometers, etc.
For example, when a Transmission Owner operates 2,000 miles of applicable transmission lines this Transmission Owner will be
responsible for inspecting all the 2,000 miles of lines at least once during the calendar year. If one of the included lines was 100
miles long, and if it was not inspected during the year, then the amount failed to inspect would be 100/2000 = 0.05 or 5%. The “Low
VSL” for R6 would apply in this example.
Adopted by the Board of Trustees: November 3, 2011
23
FAC-003-2 — Transmission Vegetation Management
Requirement R7:
R7 is a risk-based requirement. The Transmission Owner is required to complete its an annual work plan for vegetation
management to accomplish the purpose of this standard. Modifications to the work plan in response to changing conditions or to
findings from vegetation inspections may be made and documented provided they do not put the transmission system at risk. The
annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a “line-by-line” detailed description
of all work to be performed. It is only intended to require that the Transmission Owner provide evidence of annual planning and
execution of a vegetation management maintenance approach which successfully prevents encroachment of vegetation into the
MVCD.
For example, when a Transmission Owner identifies 1,000 miles of applicable transmission lines to be completed in the Transmission
Owner’s annual plan, the Transmission Owner will be responsible completing those identified miles. If a Transmission Owner makes
a modification to the annual plan that does not put the transmission system at risk of an encroachment the annual plan may be
modified. If 100 miles of the annual plan is deferred until next year the calculation to determine what percentage was completed
for the current year would be: 1000 – 100 (deferred miles) = 900 modified annual plan, or 900 / 900 = 100% completed annual miles.
If a Transmission Owner only completed 875 of the total 1000 miles with no acceptable documentation for modification of the
annual plan the calculation for failure to complete the annual plan would be: 1000 – 875 = 125 miles failed to complete then, 125
miles (not completed) / 1000 total annual plan miles = 12.5% failed to complete.
The ability to modify the work plan allows the Transmission Owner to change priorities or treatment methodologies during the year
as conditions or situations dictate. For example recent line inspections may identify unanticipated high priority work, weather
conditions (drought) could make herbicide application ineffective during the plan year, or a major storm could require redirecting
local resources away from planned maintenance. This situation may also include complying with mutual assistance agreements by
moving resources off the Transmission Owner’s system to work on another system. Any of these examples could result in
acceptable deferrals or additions to the annual work plan provided that they do not put the transmission system at risk of a
vegetation encroachment.
In general, the vegetation management maintenance approach should use the full extent of the Transmission Owner’s easement,
fee simple and other legal rights allowed. A comprehensive approach that exercises the full extent of legal rights on the ROW is
superior to incremental management because in the long term it reduces the overall potential for encroachments, and it ensures
that future planned work and future planned inspection cycles are sufficient.
Adopted by the Board of Trustees: November 3, 2011
24
FAC-003-2 — Transmission Vegetation Management
When developing the annual work plan the Transmission Owner should allow time for procedural requirements to obtain permits to
work on federal, state, provincial, public, tribal lands. In some cases the lead time for obtaining permits may necessitate preparing
work plans more than a year prior to work start dates. Transmission Owners may also need to consider those special landowner
requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be completed as planned. Therefore,
deferrals or relevant changes to the annual plan shall be documented. Depending on the planning and documentation format used
by the Transmission Owner, evidence of successful annual work plan execution could consist of signed-off work orders, signed
contracts, printouts from work management systems, spreadsheets of planned versus completed work, timesheets, work inspection
reports, or paid invoices. Other evidence may include photographs, and walk-through reports.
Adopted by the Board of Trustees: November 3, 2011
25
FAC-003-2 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 7
For Alternating Current Voltages (feet)
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
(kV) 8
MVCD
(feet)
MVCD
(feet)
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
Over sea
level up
to 500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over
2000 ft
up to
3000 ft
Over
3000 ft
up to
4000 ft
Over
4000 ft
up to
5000 ft
Over
5000 ft
up to
6000 ft
Over
6000 ft
up to
7000 ft
Over
7000 ft
up to
8000 ft
Over
8000 ft
up to
9000 ft
Over
9000 ft
up to
10000 ft
Over
10000 ft
up to
11000 ft
765
800
8.2ft
8.33ft
8.61ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
500
550
5.15ft
5.25ft
5.45ft
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
345
362
3.19ft
3.26ft
3.39ft
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
287
302
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
230
242
3.03ft
3.09ft
3.22ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
161*
169
2.05ft
2.09ft
2.19ft
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
138*
145
1.74ft
1.78ft
1.86ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
115*
121
1.44ft
1.47ft
1.54ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
88*
100
1.18ft
1.21ft
1.26ft
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
72
0.84ft
0.86ft
0.90ft
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
69*
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)
7
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances
will be achieved at time of vegetation maintenance.
8
Where applicable lines are operated at nominal voltages other than those listed, The Transmission Owner should use the maximum system voltage to determine the
appropriate clearance for that line.
Adopted by the Board of Trustees: November 3, 2011
26
FAC-003-2 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level up
to 152.4
m
Over
152.4 m up
to 304.8 m
Over 304.8
m up to
609.6m
Over
609.6m up
to 914.4m
Over
914.4m up
to
1219.2m
Over
1219.2m
up to
1524m
Over 1524 m
up to 1828.8
m
Over
1828.8m
up to
2133.6m
Over
2133.6m
up to
2438.4m
Over
2438.4m up
to 2743.2m
Over
2743.2m up
to 3048m
Over
3048m up
to
3352.8m
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
69*
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
Adopted by the Board of Trustees: November 3, 2011
27
FAC-003-2 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
±750
±600
±500
±400
±250
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
Over sea
level up to
500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over
152.4 m
up to
304.8 m
(Over
304.8 m
up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to
1219.2m
(Over
1219.2m
up to
1524m
(Over
1524 m up
to 1828.8
m)
(Over
1828.8m
up to
2133.6m)
(Over
2133.6m
up to
2438.4m)
(Over
2438.4m
up to
2743.2m)
(Over
2743.2m
up to
3048m)
(Over
3048m up
to
3352.8m)
14.12ft
(4.30m)
10.23ft
(3.12m)
8.03ft
(2.45m)
6.07ft
(1.85m)
3.50ft
(1.07m)
14.31ft
(4.36m)
10.39ft
(3.17m)
8.16ft
(2.49m)
6.18ft
(1.88m)
3.57ft
(1.09m)
14.70ft
(4.48m)
10.74ft
(3.26m)
8.44ft
(2.57m)
6.41ft
(1.95m)
3.72ft
(1.13m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
6.63ft
(2.02m)
3.87ft
(1.18m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
6.86ft
(2.09m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
7.09ft
(2.16m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
7.33ft
(2.23m)
4.34ft
(1.32m)
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
7.56ft
(2.30m)
4.5ft
(1.37m)
16.91ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
7.80ft
(2.38m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
8.03ft
(2.45m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
8.27ft
(2.52m)
5.00ft
(1.52m)
17.97ft
(5.48m)
13.54ft
(4.13m)
10.92ft
(3.33m)
8.51ft
(2.59m)
5.17ft
(1.58m)
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a misapplication. The SDT consulted specialists who
advised that the Gallet Equation would be a technically justified method. The explanation of why the Gallet approach is more
appropriate is explained in the paragraphs below.
Adopted by the Board of Trustees: November 3, 2011
28
FAC-003-2 — Transmission Vegetation Management
The drafting team sought a method of establishing minimum clearance distances that uses realistic weather conditions and realistic
maximum transient over-voltages factors for in-service transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to conductor distances in FAC-003-1:
• avoid the problem associated with referring to tables in another standard (IEEE-516-2003)
• transmission lines operate in non-laboratory environments (wet conditions)
• transient over-voltage factors are lower for in-service transmission lines than for inadvertently re-energized transmission
lines with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in IEEE 516-2003 to determine the
minimum distance between a transmission line conductor and vegetation. The equations and methods provided in IEEE 516 were
developed by an IEEE Task Force in 1968 from test data provided by thirteen independent laboratories. The distances provided in
IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap, or in other words, dry laboratory conditions.
Consequently, the validity of using these distances in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the minimum clearance distances. Table 7
could be used if the Transmission Owner knew the maximum transient over-voltage factor for its system. Otherwise, Table 5 would
have to be used. Table 5 represented minimum air insulation distances under the worst possible case for transient over-voltage
factors. These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 550 kV phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for
concern in this particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is inadvertently re-energized immediately after
the line is de-energized and a trapped charge is still present. The intent of FAC-003 is to keep a transmission line that is in service
from becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst case
transient overvoltage assumptions are not appropriate for this application. Rather, the appropriate over voltage values are those
that occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are
negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 per unit. This value is a conservative estimate of the transient over-
Adopted by the Board of Trustees: November 3, 2011
29
FAC-003-2 — Transmission Vegetation Management
voltage that is created at the point of application (e.g. a substation) by switching a capacitor bank without pre-insertion devices (e.g.
closing resistors). At voltage levels where capacitor banks are not very common (e.g. Maximum System Voltage of 362 kV), the
maximum transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines and shunt reactor bank
switching. These transient voltages are usually 1.5 per unit or less.
Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in
order to be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum
transient over-voltage factor of 2.0 per unit for transmission lines operated at 302 kV and below is considered to be a realistic
maximum in this application. Likewise, for ac transmission lines operated at Maximum System Voltages of 362 kV and above a
transient over-voltage factor of 1.4 per unit is considered a realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These equations are used for computing
the required strike distances for proper transmission line insulation coordination. They were developed for both wet and dry
applications and can be used with any value of transient over-voltage factor. The Gallet Equation also can take into account various
air gap geometries. This approach was used to design the first 500 kV and 765 kV lines in North America.
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical spark-over distances
computed using the Gallet wet equations, for each of the nominal voltage classes and identical transient over-voltage factors, the
Gallet equations yield a more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are not vastly different when the same
transient overvoltage factors are used; the “wet” equations will consistently produce slightly larger distances than the IEEE 516
equations when the same transient overvoltage is used. While the IEEE 516 equations were only developed for dry conditions the
Gallet equations have provisions to calculate spark-over distances for both wet and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live vegetation, there are no spark-over formulas
currently derived expressly for vegetation to conductor minimum distances. Therefore the SDT chose a proven method that has
been used in other EHV applications. The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage
Factor that is consistent with the absence of trapped charges on an in-service transmission line make this methodology a better
choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the Gallet equations.
Adopted by the Board of Trustees: November 3, 2011
30
FAC-003-2 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations vs.
IEEE 516-2003 MAID distances
Table 7
(Table D.5 for feet)
( AC )
( AC )
Nom System
Max System
Transient
Over-voltage
Clearance (ft.)
Voltage (kV)
Voltage (kV)
Factor (T)
765
800
2.0
14.36
13.95
500
550
2.4
11.0
10.07
345
362
3.0
8.55
7.47
230
115
242
121
3.0
3.0
5.28
2.46
4.2
2.1
Gallet (wet)
@ Alt. 3000 feet
IEEE 516-2003
MAID (ft)
@ Alt. 3000 feet
Rationale:
During development of this standard, text boxes were embedded within the standard to explain the rationale for various parts of the
standard. Upon BOT approval, the text from the rationale text boxes was moved to this section.
Rationale for Applicability (section 4.2.4):
The areas excluded in 4.2.4 were excluded based on comments from industry for reasons summarized as follows: 1) There is a very
low risk from vegetation in this area. Based on an informal survey, no TOs reported such an event. 2) Substations, switchyards, and
stations have many inspection and maintenance activities that are necessary for reliability. Those existing process manage the
threat. As such, the formal steps in this standard are not well suited for this environment. 3) NERC has a project in place to address
at a later date the applicability of this standard to Generation Owners. 4) Specifically addressing the areas where the standard does
and does not apply makes the standard clearer.
Adopted by the Board of Trustees: November 3, 2011
31
FAC-003-2 — Transmission Vegetation Management
Rationale for R1 and R2:
Lines with the highest significance to reliability are covered in R1; all other lines are covered in R2.
Rationale for the types of failure to manage vegetation which are listed in order of increasing degrees of severity in noncompliant performance as it relates to a failure of a Transmission Owner's vegetation maintenance program:
1. This management failure is found by routine inspection or Fault event investigation, and is normally symptomatic of unusual
conditions in an otherwise sound program.
2. This management failure occurs when the height and location of a side tree within the ROW is not adequately addressed by the
program.
3. This management failure occurs when side growth is not adequately addressed and may be indicative of an unsound program.
4. This management failure is usually indicative of a program that is not addressing the most fundamental dynamic of vegetation
management, (i.e. a grow-in under the line). If this type of failure is pervasive on multiple lines, it provides a mechanism for a
Cascade.
Rationale for R3:
The documentation provides a basis for evaluating the competency of the Transmission Owner’s vegetation program. There may be
many acceptable approaches to maintain clearances. Any approach must demonstrate that the Transmission Owner avoids
vegetation-to-wire conflicts under all Ratings and all Rated Electrical Operating Conditions. See Figure 1 for an illustration of possible
conductor locations.
Rationale for R4:
This is to ensure expeditious communication between the Transmission Owner and the control center when a critical situation is
confirmed.
Rationale for R5:
Legal actions and other events may occur which result in constraints that prevent the Transmission Owner from performing planned
vegetation maintenance work.
Adopted by the Board of Trustees: November 3, 2011
32
FAC-003-2 — Transmission Vegetation Management
In cases where the transmission line is put at potential risk due to constraints, the intent is for the Transmission Owner to put
interim measures in place, rather than do nothing.
The corrective action process is not intended to address situations where a planned work methodology cannot be performed but an
alternate work methodology can be used.
Rationale for R6:
Inspections are used by Transmission Owners to assess the condition of the entire ROW. The information from the assessment can
be used to determine risk, determine future work and evaluate recently-completed work. This requirement sets a minimum
Vegetation Inspection frequency of once per calendar year but with no more than 18 months between inspections on the same
ROW. Based upon average growth rates across North America and on common utility practice, this minimum frequency is
reasonable. Transmission Owners should consider local and environmental factors that could warrant more frequent inspections.
Rationale for R7:
This requirement sets the expectation that the work identified in the annual work plan will be completed as planned. It allows
modifications to the planned work for changing conditions, taking into consideration anticipated growth of vegetation and all other
environmental factors, provided that those modifications do not put the transmission system at risk of a vegetation encroachment.
Adopted by the Board of Trustees: November 3, 2011
33
FAC-003-2 — Transmission Vegetation Management
Version History
Version
1
Date
TBA
Action
1. Added “Standard Development
Roadmap.”
Change Tracking
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date:
April 7, 2006” to footer.
4. Added “Draft 3: November 17,
2005” to footer.
1
2
April 4, 2007
November 3,
2011
Regulatory Approval - Effective Date
Adopted by the NERC Board of Trustees
Adopted by the Board of Trustees: November 3, 2011
New
34
Exhibit B
Implementation Plan for Reliability Standard FAC-003-2 — Transmission Vegetation
Management submitted for Approval
Implementation Plan
FAC-003-2
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
FAC-003-2 – Vegetation Management
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. There are two
revised definitions in the proposed standard. FAC-003-1 will be retired when FAC-003-2 becomes
effective.
Compliance with Standard
The standard applies to Transmission Owners.
Effective Date
The effective date is the date entities are expected to meet the performance identified in this
standard. The effective date allows entities time to make revisions to their existing transmission
vegetation management programs to comply with the new requirements.
This standard becomes effective on the first calendar day of the first calendar quarter one year after
the date of the order approving the standard from applicable regulatory authorities where such explicit
approval is required. Where no regulatory approval is required, the standard becomes effective on the
first calendar day of the first calendar quarter one year after Board of Trustees adoption.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of an
Interconnection Reliability Operating Limit (IROL) or designated by the Western Electricity
Coordinating Council (WECC) as an element of a Major WECC transfer Path, becomes subject to
this standard the latter of: 1) 12 months after the date the Planning Coordinator or WECC
initially designates the line as being an element of an IROL or an element of a Major WECC
transfer Path, or 2) January 1 of the planning year when the line is forecast to become an
element of an IROL or an element of a Major WECC transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element of an
IROL or a Major WECC Transfer Path which has a specified date for the removal of such
designation will no longer be subject to this standard effective on that specified date.
Implementation Plan – FAC-003-2
1
3. A line operated at 200 kV or above, currently subject to this standard which is a designated
element of an IROL or a Major WECC Transfer Path and which has a specified date for the
removal of such designation will be subject to Requirement R2 and no longer be subject to
Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an asset
owner and which was not previously subject to this standard, becomes subject to this standard
12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset owner
and which was not previously subject to this standard becomes subject to this standard 12
months after the acquisition date of the line if at the time of acquisition the line is designated
by the Planning Coordinator as an element of an IROL or by WECC as an element of a Major
WECC Transfer Path.
Implementation Plan – FAC-003-2
2
Exhibit C
Proposed Terms to be Added to the NERC Glossary of Terms Used in NERC
Reliability Standards
FAC-003-2 — Transmission Vegetation Management
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Right-of-Way (ROW)
The corridor of land under a transmission line(s) needed to operate the line(s). The width of the
corridor is established by engineering or construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout
standard in effect when the line was built. The ROW width in no case exceeds the Transmission
Owner’s legal rights but may be less based on the aforementioned criteria.
The current glossary definition of this NERC term is modified to address the issues set
forth in Paragraph 734 of FERC Order 693.
Vegetation Inspection
The systematic examination of vegetation conditions on a Right-of-Way and those vegetation
conditions under the Transmission Owner’s control that are likely to pose a hazard to the line(s)
prior to the next planned maintenance or inspection. This may be combined with a general line
inspection.
The current glossary definition of this NERC term is modified to allow both maintenance
inspections and vegetation inspections to be performed concurrently.
Current definition of Vegetation Inspection: The systematic examination of a
transmission corridor to document vegetation conditions.
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
Exhibit D
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Standard FAC-003-1
Definitions of Terms
Proposed Standard FAC-003-2 RBS Draft 4
Definitions of Terms Used in Standard
Right of Way
A corridor of land on which
electric lines may be located.
The Transmission Owner may
own the land in fee, own an
easement, or have certain
franchise, prescription, or
license rights to construct and
maintain lines.
Right-of-Way (ROW)
The corridor of land under a transmission line(s) needed to
operate the line(s). The width of the corridor is established
by engineering or construction standards as documented
in either construction documents, pre-2007 vegetation
maintenance records, or by the blowout standard in effect
when the line was built. The ROW width in no case exceeds
the Transmission Owner’s legal rights but may be less
based on the aforementioned criteria.
Observations
This definition is intended to more clearly
recognize the establishment of the Right
of Way thought documentation.
The current glossary definition of this NERC
term is modified to address the issues set forth
in Paragraph 734 of FERC Order 693.
Vegetation Inspection
The systematic examination of a
transmission corridor to
document vegetation conditions.
Vegetation Inspection
The systematic examination of vegetation conditions on a Rightof-Way and those vegetation conditions under the Transmission
Owner’s control that are likely to pose a hazard to the line(s)
prior to the next planned maintenance or inspection. This may
be combined with a general line inspection.
1
This definition is intended to explain the
reason for Vegetation Inspections, and to
make clear that entities may perform other
inspections at the same time as the
Vegetation Inspection.
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Standard FAC-003-1
Proposed Standard FAC-003-2 RBS Draft 4
Observations
The current glossary definition of this NERC term is
modified to allow both maintenance inspections and
vegetation inspections to be performed concurrently.
Current definition of Vegetation Inspection: The
systematic examination of a transmission corridor to
document vegetation conditions.
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to
prevent flash-over between conductors and vegetation, for
various altitudes and operating voltages.
3. Purpose: To improve the
reliability of the electric
transmission systems by
preventing
outages from vegetation located
on transmission rights-of-way
(ROW) and minimizing outages
from vegetation located adjacent
to ROW, maintaining clearances
between transmission lines and
vegetation on and along
transmission ROW, and
3. Purpose: To maintain a reliable electric transmission system
by using a defense-in-depth strategy to manage vegetation
located on transmission rights of way (ROW) and minimize
encroachments from vegetation located adjacent to the ROW,
thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
This definition was added to ensure a
consistent understanding of the phrase.
Results based purpose, driven by Needs and
Goals.
NEED: To maintain a reliable electric
transmission system , preventing the risk of
those vegetation-related outages that could
lead to Cascading.
GOAL: To manage vegetation located on
transmission rights of way (ROW) and
minimize encroachments from vegetation
located adjacent to the ROW
2
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Standard FAC-003-1
reporting vegetation related
outages of the transmission
systems to the respective
Regional Reliability
Organizations (RRO) and the
North American Electric
Reliability Council (NERC).
4. Applicability:
4.1. Transmission Owner
4.2. Regional Reliability
Organization
4.3. This Standard shall
apply to all
transmission lines
operated at 200 kV
and above and to any
lower voltage lines
designated by the
RRO as critical to the
reliability of the
electric system in the
region.
Proposed Standard FAC-003-2 RBS Draft 4
4.1.
Functional Entities:
Observations
4.1.1 replaces 4.1.
4.1.1 Transmission Owners
4.2.
Facilities: Defined below (referred to as “applicable
lines”), including but not limited to those that cross lands owned
by federal , state, provincial, public, private, or tribal entities:
4.2.1. Each overhead transmission line operated at 200kV or
higher.
4.2.2. Each overhead transmission line operated below 200kV
identified as an element of an IROL under NERC Standard FAC014 by the Planning Coordinator.
4.2.3. Each overhead transmission line operated below 200 kV
identified as an element of a Major WECC Transfer Path in the
Bulk Electric System by WECC.
4.2.4. Each overhead transmission line identified above (4.2.1
through 4.2.3) located outside the fenced area of the
switchyard, station or substation and any portion of the span
of the transmission line that is crossing the substation fence.
3
4.2 has been removed, as the requirements
related to the RRO have been addressed in the
compliance section of the standard.
4.2 replaces 4.3. This is superior, as it raises
the bar on what lines need to be included
within the applicability of this standard.
To the extent the areas not covered in 4.2.4
need to be addressed, they should do so
under another project and possibly in a
separate standard, as the requirements for
vegetation management performed in these
areas by the GO and DP may be somewhat
different than those performed by a
Transmission Owner.
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Standard FAC-003-1
Proposed Standard FAC-003-2 RBS Draft 4
Rationale
The areas excluded in 4.2.4 were excluded based on
comments from industry for reasons summarized as
follows: 1) There is a very low risk from vegetation
in this area. Based on an informal survey, no TOs
reported such an event. 2) Substations, switchyards,
and stations have many inspection and
maintenance activities that are necessary for
reliability. Those existing process manage the
threat. As such, the formal steps in this standard are
not well suited for this environment. 3) NERC has a
project in place to address at a later date the
applicability of this standard to Generation Owners.
4) Specifically addressing the areas where the
standard does and does not apply makes the
standard clearer.
4
Observations
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
R1. The Transmission Owner shall prepare,
and keep current, a formal transmission
vegetation management program (TVMP).
The TVMP shall include the Transmission
Owner’s objectives, practices, approved
procedures, and work specifications1.
R3. Each Transmission Owner shall have
documented maintenance strategies or
procedures or processes or specifications it
uses to prevent the encroachment of
vegetation into the MVCD of its applicable
lines that include(s) the following:
R3 replaces R1.
Rationale
The documentation provides a basis for
evaluating the competency of the
Transmission Owner’s vegetation program.
There may be many acceptable
approaches to maintain clearances. Any
approach must demonstrate that the
Transmission Owner avoids vegetation-towire conflicts under all Ratings and all
Rated Electrical Operating Conditions. See
Figure 1 for an illustration of possible
conductor locations.
R1.1. The TVMP shall define a schedule for R6.
and the type (aerial, ground) of ROW
vegetation inspections. This schedule should
be flexible enough to adjust for changing
conditions. The inspection schedule shall be
based on the anticipated growth of vegetation
Each Transmission Owner shall perform a
Vegetation Inspection of 100% of its
applicable transmission lines (measured in
units of choice - circuit, pole line, line miles
or kilometers, etc.) at least once per
calendar year and with no more than 18
5
R6 replaces R1.1. R6 is superior because it
requires entities to take action (perform the
inspection), rather than just create a schedule.
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
and any other environmental or operational
factors that could impact the relationship of
vegetation to the Transmission Owner’s
transmission lines.
calendar months between inspections on
the same ROW.1
Rationale
Inspections are used by Transmission
Owners to assess the condition of the entire
ROW. The information from the assessment
can be used to determine risk, determine
future work and evaluate recentlycompleted work. This requirement sets a
minimum Vegetation Inspection frequency
of once per calendar year but with no more
than 18 months between inspections on the
same ROW. Based upon average growth
rates across North America and on common
utility practice, this minimum frequency is
reasonable. Transmission Owners should
consider local and environmental factors
that could warrant more frequent
inspections.
R1.2. The Transmission Owner, in the
TVMP, shall identify and document
clearances between vegetation and any
overhead, ungrounded supply conductors,
taking into consideration transmission line
voltage, the effects of ambient temperature
on conductor sag under maximum design
R3. Each Transmission Owner shall have
documented maintenance strategies
or procedures or processes or
specifications it uses to prevent the
encroachment of vegetation into the
MVCD of its applicable lines that
include(s)accounts for the following
1
Requirement R3 and Parts 3.1 and 3.2 replace
the concept of “Clearance 1,” as discussed in
R1.2 and R1.2.1.
When the Transmission Owner is prevented from performing a Vegetation Inspection within the timeframe in R6 due to a natural disaster, the TO is granted a time extension
that is equivalent to the duration of the time the TO was prevented from performing the Vegetation Inspection.
6
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
loading, and the effects of wind velocities on
conductor sway. Specifically, the
Transmission Owner shall establish
clearances to be achieved at the time of
vegetation management work identified
herein as Clearance 1, and shall also
establish and maintain a set of clearances
identified herein as Clearance 2 to prevent
flashover between vegetation and overhead
ungrounded supply conductors.
R1.2.1. Clearance 1 — The Transmission
Owner shall determine and document
appropriate clearance distances to be
achieved at the time of transmission
vegetation management work based upon
local conditions and the expected time frame
in which the Transmission Owner plans to
return for future vegetation management
work. Local conditions may include, but are
not
limited to: operating voltage, appropriate
vegetation management techniques,
fire risk, reasonably anticipated tree and
conductor movement, species types
and growth rates, species failure
characteristics, local climate and rainfall
patterns, line terrain and elevation, location
of the vegetation within the span,
and worker approach distance requirements.
Clearance 1 distances shall be
greater than those defined by Clearance 2
below.
3.1 Movement of applicable line
conductors under their Rating and all
Rated Electrical Operating Conditions;
3.2 Inter-relationships between
vegetation growth rates, vegetation
control methods, and inspection
frequency.
7
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
R1.2.2. Clearance 2 — The Transmission
Owner shall determine and document
specific radial clearances to be maintained
between vegetation and conductors
under all rated electrical operating
conditions. These minimum clearance
distances are necessary to prevent flashover
between vegetation and conductors and will
vary due to such factors as altitude and
operating voltage.
These Transmission Owner-specific
minimum clearance distances shall be no less
than those set forth in the Institute of
Electrical and Electronics Engineers (IEEE)
Standard 516-2003 (Guide for Maintenance
Methods on Energized Power Lines) and as
specified in its Section 4.2.2.3, Minimum Air
Insulation
Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system
transient overvoltage factors are not
known, clearances shall be derived from
Table 5, IEEE 516-2003, phase-to-ground
distances, with appropriate altitude
correction
factors applied.
R1.2.2.2 Where transmission system
R1 item 1 and R2 item 2 replace Clearance 2
with the Gallet Equations. These are
performance based, and superior to the existing
standard, as they require the entities to perform
an action (manage vegetation) rather than
creating a document.
R1. Each Transmission Owner shall manage
vegetation to prevent encroachments into
the MVCD of its applicable line(s) which are
either an element of an IROL, or an
element of a Major WECC Transfer Path;
operating within its Rating and all Rated
Electrical Operating Conditions of the types
shown below 2 [Violation Risk Factor: High]
[Time Horizon: Real-time]:
1. An encroachment into the MVCD as shown
in FAC-003-Table 2, observed in Real-time,
absent a Sustained Outage
R2. Each Transmission Owner shall manage
vegetation to prevent encroachments into
the MVCD of its applicable line(s) which are
not either an element of an IROL, or an
element of a Major WECC Transfer Path;
operating within its Rating and all Rated
Electrical Operating Conditions of the types
shown below2 [Violation Risk Factor:
2
This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to this reliability standard, including natural disasters such as
earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice
storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree, or installation, removal, or digging of vegetation. Nothing in this
footnote should be construed to limit the Transmission Owner’s right to exercise its full legal rights on the ROW.
3
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this
shall be considered the equivalent of a Real-time observation.
8
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Medium] [Time Horizon: Real-time]:
1. An encroachment into the MVCD as
shown in FAC-003-Table 2, observed in
Real-time, absent a Sustained Outage3,
transient overvoltage factors are known,
clearances shall be derived from Table 7,
IEEE 516-2003, phase-to-phase voltages,
with appropriate altitude correction factors
applied.
R1.3. All personnel directly involved in the
design and implementation of the TVMP shall
hold appropriate qualifications and training, as
defined by the Transmission Owner, to
perform their duties.
R1.3 is ambiguous (what is “appropriate”) and
unenforceable (what if the Transmission Owner
defines no qualifications or training), and was
not included in the new version of the standard.
R1.4. Each Transmission Owner shall develop
mitigation measures to achieve sufficient
clearances for the protection of the transmission
facilities when it identifies locations on the ROW
where the Transmission Owner is restricted from
attaining the clearances specified in Requirement
1.2.1.
R5 replaces R1.4. It is superior because it
requires the Transmission Owner to take action
(take corrective action), rather than to simply
develop mitigation measures.
R5.
When a Transmission Owner is constrained
from performing vegetation work on applicable
transmission lines operating within their Rating
and all Rated Electrical Operating Conditions,
and the constraint may lead to a vegetation
encroachment into the MVCD prior to the
implementation of the next annual work plan,
then the Transmission Owner shall take
corrective action to ensure continued
vegetation management to prevent
encroachments
9
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Rationale
Legal actions and other events may occur
which result in constraints that prevent
the Transmission Owner from performing
planned vegetation maintenance work.
In cases where the transmission line is put
at potential risk due to constraints, the
intent is for the Transmission Owner to
put interim measures in place, rather than
do nothing.
The corrective action process is not
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
R1.5. Each Transmission Owner shall establish
and document a process for the immediate
communication of vegetation conditions that
present an imminent threat of a transmission line
outage. This is so that action (temporary
reduction in line rating, switching line out of
service, etc.) may be taken until the threat is
relieved.
R4.
Each Transmission Owner, without
any intentional time delay, shall notify the
control center holding switching authority for
the associated applicable line when the
Transmission Owner has confirmed the
existence of a vegetation condition that is likely
to cause a Fault at any moment.
[VRF – Medium] [Time Horizon – Real-time]
10
R4 replaces R1.5. It is superior because it
requires the Transmission Owner to take action
(notify the control center) rather than document
a process.
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Rationale
This is to ensure expeditious communication
between the Transmission Owner and the
control center when a critical situation is
confirmed.
R2. The Transmission Owner shall create and
implement an annual plan for vegetation
management work to ensure the reliability
of the system. The plan shall describe the
methods used, such as manual clearing,
mechanical clearing, herbicide treatment,
or other actions. The plan should be
flexible enough to adjust to changing
conditions, taking into consideration
anticipated growth of vegetation and all
other environmental factors that may have
an impact on the reliability of the
transmission systems. Adjustments to the
plan shall be documented as they occur.
The plan should take into consideration the
time required to obtain permissions or
permits from landowners or regulatory
authorities. Each Transmission Owner shall
have systems and procedures for
documenting and tracking the planned
vegetation management work and ensuring
that the vegetation management work was
completed according to work
specifications.
R7. Each Transmission Owner shall complete 100% of
its annual vegetation work plan of applicable
lines to ensure no vegetation encroachments
occur within the MVCD. Modifications to the
work plan in response to changing conditions
or to findings from vegetation inspections may
be made (provided they do not allow
encroachment of vegetation into the MVCD)
and must be documented. The percent
completed calculation is based on the number
of units actually completed divided by the
number of units in the final amended plan
(measured in units of choice - circuit, pole line,
line miles or kilometers, etc.) Examples of
reasons for modification to annual plan may
include
•
Change in expected growth rate/
environmental factors
Circumstances that are beyond the
•
control of a Transmission Owner 3
•
Rescheduling work between growing
seasons
•
Crew or contractor availability/ Mutual
assistance agreements
3
R7 replaces R2. It is superior because it requires
entities to takes specific action (complete 100%
of its plan) rather than more generic language
(implement its plan). Entities that do not have a
plan would be unable to meet this requirement,
as they would have no evidence to demonstrate
compliance.
Circumstances that are beyond the control of a Transmission Owner include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides,
ice storms, floods, or major storms as defined either by the TO or an applicable regulatory body.
11
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
•
•
•
•
•
Identified unanticipated high priority
work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in
land use by the landowner
Emerging technologies
Rationale
This requirement sets the expectation that
the work identified in the annual work plan
will be completed as planned. It allows
modifications to the planned work for
changing conditions, taking into
consideration anticipated growth of
vegetation and all other environmental
factors, provided that those modifications
do not put the transmission system at risk of
a vegetation encroachment.
R3. The Transmission Owner shall report
quarterly to its RRO, or the RRO’s designee,
sustained transmission line outages determined
by the Transmission Owner to have been caused
by vegetation.
R3.1. Multiple sustained outages on an
individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the
actual number of outages within a 24hour period.
R3.2. The Transmission Owner is not required
to report to the RRO, or the RRO’s designee,
certain sustained transmission line outages
caused by vegetation: (1) Vegetation related
Periodic Data Submittal: The Transmission
Owner will submit a quarterly report to its
Regional Entity, or the Regional Entity’s designee,
identifying all Sustained Outages of applicable
lines operated within their Rating and all Rated
Electrical Operating Conditions as determined by
the Transmission Owner to have been caused by
vegetation, except as excluded in footnote 2, and
including as a minimum the following:
o
The name of the circuit(s), the date, time
and duration of the outage; the voltage of the
circuit; a description of the cause of the outage;
the category associated with the Sustained
12
Moved to compliance section of standard.
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
outages that result from vegetation falling into
lines from outside the ROW that result from
natural disasters shall not be considered
reportable (examples of disasters
that could create non-reportable outages include,
but are not limited to, earthquakes,
fires, tornados, hurricanes, landslides, wind
shear, major storms as defined either by
the Transmission Owner or an applicable
regulatory body, ice storms, and floods), and
(2) Vegetation-related outages due to human or
animal activity shall not be considered
reportable (examples of human or animal activity
that could cause a non-reportable
outage include, but are not limited to, logging,
animal severing tree, vehicle contact with tree,
arboricultural activities or horticultural or
agricultural activities, or removal or digging of
vegetation).
R3.3. The outage information provided by the
Transmission Owner to the RRO, or the
RRO’s designee, shall include at a minimum: the
name of the circuit(s) outaged, the date, time and
duration of the outage; a description of the cause
of the outage; other pertinent comments; and any
countermeasures taken by the Transmission
Owner.
R3.4. An outage shall be categorized as one of
the following:
R3.4.1. Category 1 — Grow-ins: Outages
caused by vegetation growing into lines
from vegetation inside and/or outside of the
ROW;
R3.4.2. Category 2 — Fall-ins: Outages
caused by vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages
caused by vegetation falling into lines from
Outage; other pertinent comments; and any
countermeasures taken by the Transmission
Owner.
A Sustained Outage is to be categorized as one of
the following:
o
Category 1A — Grow-ins: Sustained
Outages caused by vegetation growing into
applicable lines, that are identified as an element
of an IROL or Major WECC Transfer Path, by
vegetation inside and/or outside of the ROW;
o
Category 1B — Grow-ins: Sustained
Outages caused by vegetation growing into
applicable lines, but are not identified as an
element of an IROL or Major WECC Transfer Path,
by vegetation inside and/or outside of the ROW;
o
Category 2A — Fall-ins: Sustained Outages
caused by vegetation falling into applicable lines
that are identified as an element of an IROL or
Major WECC Transfer Path, from within the ROW;
o
Category 2B — Fall-ins: Sustained Outages
caused by vegetation falling into applicable lines,
but are not identified as an element of an IROL or
Major WECC Transfer Path, from within the ROW;
o
Category 3 — Fall-ins: Sustained Outages
caused by vegetation falling into applicable lines
from outside the ROW;
o
Category 4A — Blowing together: Sustained
Outages caused by vegetation and applicable
lines that are identified as an element of an IROL
or Major WECC Transfer Path, blowing together
from within the ROW.
o
Category 4B — Blowing together: Sustained
13
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
outside the ROW.
R4. The RRO shall report the outage
information provided to it by Transmission
Owner’s, as required by Requirement 3,
quarterly to NERC, as well as any actions
taken by the RRO as a result of any of the
reported outages.
Outages caused by vegetation and applicable
lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, blowing
together from within the ROW.
The Regional Entity will report the outage
information provided by Transmission Owners, as per
the above, quarterly to NERC, as well as any actions
taken by the Regional Entity as a result of any of the
reported Sustained Outages.
R1. Each Transmission Owner shall manage
vegetation to prevent encroachments into the
MVCD of its applicable line(s) which are either
an element of an IROL, or an element of a
Major WECC Transfer Path; operating within
their Rating and all Rated Electrical Operating
Conditions of the types shown below2:
1.
An encroachment into the MVCD as shown in
FAC-003-Table 2, observed in Real-time, absent
a Sustained Outage3 ,
2.
An encroachment due to a fall-in from inside
the ROW that caused a vegetation-related
Sustained Outage4 ,
3.
An encroachment due to the blowing together
of applicable lines and vegetation located
inside the ROW that caused a vegetationrelated Sustained Outage4,
4.
An encroachment due to vegetation growth
into the MVCD that caused a vegetation-related
Sustained Outage4.
14
New requirement.
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Rationale
Lines with the highest significance to reliability
are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage
vegetation which are listed in order of
increasing degrees of severity in non-compliant
performance as it relates to a failure of a
Transmission Owner's vegetation maintenance
program:
1. This management failure is found by routine
inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in
an otherwise sound program.
2. This management failure occurs when the
height and location of a side tree within the
ROW is not adequately addressed by the
program.
3. This management failure occurs when side
growth is not adequately addressed and may
be indicative of an unsound program.
4. This management failure is usually indicative
of a program that is not addressing the most
fundamental dynamic of vegetation
management, (i.e. a grow-in under the line). If
this type of failure is pervasive on multiple
li
it
id
h i f
C
d
R2.
Each Transmission Owner shall manage
15
New requirement.
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
1.
2.
3.
4.
vegetation to prevent encroachments into the
MVCD of its applicable line(s) which are not
either an element of an IROL, or an element of
a Major WECC Transfer Path; operating within
its Rating and all Rated Electrical Operating
Conditions of the types shown below2
[Violation Risk Factor: Medium] [Time Horizon:
Real-time]:
An encroachment into the MVCD, observed in
Real-time, absent a Sustained Outage3,
An encroachment due to a fall-in from inside
the ROW that caused a vegetation-related
Sustained Outage4,
An encroachment due to blowing together of
applicable lines and vegetation located inside
the ROW that caused a vegetation-related
Sustained Outage4,
An encroachment due to vegetation growth
into the MVCD that caused a vegetation-related
Sustained Outage4
16
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Rationale
Lines with the highest significance to reliability
are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage
vegetation which are listed in order of
increasing degrees of severity in non-compliant
performance as it relates to a failure of a
Transmission Owner's vegetation maintenance
program:
1. This management failure is found by routine
inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in
an otherwise sound program.
2. This management failure occurs when the
height and location of a side tree within the
ROW is not adequately addressed by the
program.
3. This management failure occurs when side
growth is not adequately addressed and may
be indicative of an unsound program.
4. This management failure is usually indicative
of a program that is not addressing the most
fundamental dynamic of vegetation
management, (i.e. a grow-in under the line). If
this type of failure is pervasive on multiple
lines, it provides a mechanism for a Cascade.
17
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
2
This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to this reliability standard, including natural disasters such as
earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice
storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree, or installation, removal, or digging of vegetation. Nothing in this
footnote should be construed to limit the Transmission Owner’s right to exercise its full legal rights on the ROW.
3
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this
shall be considered the equivalent of a Real-time observation.
4
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage regardless of the actual number of outages within a 24-hour
period.
18
Exhibit E
Consideration of Comments Reports Created During the Development of Reliability
Standard FAC-003-2 — Transmission Vegetation Management
Project 2007-07
Transmission Vegetation Management
Related Files
Status:
Adopted by the Board of Trustees on November 3, 2011.
Purpose/Industry Need:
FAC-003-1 was approved in 2006. It has some ‘fill-in-the-blank’ components to eliminate.
In addition, the following comments submitted by FERC and stakeholders need to be
addressed in the refinement of the standard:
FERC Order 693 items
Address the issue regarding applicability:
• Work with the reliability entities and the ERO to collect and make available to the
FERC, a list of critical lower voltage transmission lines. (Refer to Applicability 4.3
section of the standard.)
• Consider other criteria in determining applicability of the standard to sub 200kV
lines.
• Address the issue of clearances for lines on both federal and non-federal lands:
• Review and analyze outage data (collected by the ERO) then consider defining
clearances needed to avoid sustained vegetation-related outages that would apply to
transmission lines crossing both federal and non-federal land.
•
Consider revising the definition of right of way to encompass required clearance
areas.
• Review the suitability of IEEE 516-2003 standard for minimum vegetation clearance.
•
Review and analyze outage data (collected by the ERO) then consider defining
clearances needed to avoid sustained vegetation-related outages that would apply to
transmission lines crossing both federal and non-federal land.
• Consider revising the definition of right of way to encompass required clearance
areas.
• Review the suitability of IEEE 516-2003 standard for minimum vegetation clearance.
Procedural items
• Re-format standard to bring it into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
• Remove references to RRO in the standard and substitute a responsible entity.
• Add newly developed compliance elements such as time horizons, violation risk
factors, violation severity levels, etc.
Stakeholder items
• Prepare technical reference material such as a “white paper” to aid in understanding
the technical basis for the standard.
• Review reporting criteria for Category 3 outages in the proposed technical reference
material and may remove the reporting requirement of Category 3 outages in R.3
and R.4.
• Consider deleting requirement R.4.
• Review the reporting exemptions to include all category outages under major
disasters in Requirement R3.2.
The development may include other improvements to the standards deemed appropriate
by the drafting team, with the consensus of stakeholders, consistent with establishing
high quality, enforceable and technically sufficient bulk power system reliability
standards.
Draft
Action
Dates
Results
10/04/11
10/13/11
(closed)
Summary>>
Consideration of
Comments
Draft 6 Standard
FAC-003-2
Clean | Redline to Last Posting
Implementation Plan
Clean | Redline
Technical References:
Clean | Redline to Last Posting
Supporting Materials:
FAC-003-1
Mapping Table
Recirculation
Ballot
Info>>
Vote >>
Full
Record>>
New and Modified Definitions
Consideration of Issues and
Directives
Violation Risk Factor & Violation
Severity Level Assignment
Technical, Policy and Regulatory
Issues Addressed by SDT
Draft 5 Standard
FAC-003-2
FAC-003-2
Clean | Redline to Last Posting
Implementation Plan
Clean | Redline to Last Posting
Successive
Ballot
Info>>
Vote >>
Full
Record>>
02/18/11
02/28/11
Consideration of
Comments (10)
Summary>>
Nonbinding
Results>>
Consideration of
Comments: NonBinding Poll (9)
Supporting Materials:
FAC-003-1
Comment Form (Word)
Technical White Paper
Clean | Redline to Last Posting
Draft 4
Standard − FAC-003-2
FAC-003-2
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Draft SAR Version 3
Vegetation Management
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Comments Consideration of
Received>> Comments (1)
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
The Transmission Vegetation Management SAR Drafting Team thanks all commenters who
submitted comments on the first draft of the Transmission Vegetation Management SAR.
This SAR was posted for a 30 day public comment period from January 15–February 14,
2007. The Standards Committee asked stakeholders to provide feedback on the standard
through a special standard Comment Form. There were 19 sets of comments, including
comments from more than 80 different people from more than 63 companies representing 7
of the 10 Industry Segments as shown in the table on the following pages.
Based on the comments received, the drafting team revised the SAR to reflect these
comments and improvements identified by the FERC in its Mandatory Reliability Standards
for the Bulk Power System Order 693.
The following major changes were made to the SAR:
Updated the Purpose to use language that matches the associated standard (e.g., where
FAC-003 is only related to the transmission system, the term, ‘bulk power system’ was
replaced with ‘transmission system’).
Added the items NERC is required to address in compliance with FERC Order 693
Added the following items to the list of items to review in refining the standard:
- Review reporting criteria for Category 3 outages in the proposed technical
reference material and may remove the reporting requirement of Category 3
outages in R.3 and R.4.
- Consider deleting requirement R.4.
- Review the reporting exemptions to include all category outages under major
disasters in Requirement R3.2.
Added a commitment to prepare a technical reference such as a “white paper” to aid in
understanding the technical basis for the standard.
The descriptions of the ‘Reliability Functions’ on page 3 of the SAR were updated to
reflect Version 3 of the Functional Model.
In this “Consideration of Comments” document stakeholder comments have been organized
so that it is easier to see the responses associated with each question. All comments
received on the standards can be viewed in their original format at:
http://www.nerc.com/~filez/standards/Vegetation-Management_Project_2007-7.html
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Director of Standards, Gerry Adamski, at
609-452-8060 or at [email protected]. In addition, there is a NERC Reliability
Standards Appeals Process.1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
-1-
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
9
1.
Anita Lee (G2)
AESO
2.
Jay Farrington (G6)
Alabama Electric Coop
9
3.
Randall Gann (G6)
Alabama Power Co.
9
4.
William J. Smith
Allegheny Power
9
5.
Ken Goldsmith (G3)
ALT
6.
Raymond Wiesehan (G6)
Ameren
9
7.
James H. Sorrels, Jr.
American Electric Power
9
8.
John Neagle (G6)
Associate Electric Coop
9
9.
William T. Rees
Baltimore Gas and Electric
9
10.
Brian Bartos
Bandera Electric Coop., Inc.
11.
Michael D. Johnson
Bonneville Power Administration
12.
Dave Rudolph (G3)
BPEC
13.
Brent Kingsford (G2)
CAISO
14.
John R. Kellum, Jr.
CenterPoint Energy Houston
Electric, LLP
9
15.
Michael Spector
Central Hudson Gas & Electric
9
16.
Alan Gale (G1)
City of Tallahassee
17.
Ed Thompson (G4)
ConEd
9
18.
John Loftis
Dominion - Electric Transmission
9
19.
Billy George (G6)
Duke Energy Carolinas
9
20.
Ralph Hale (G6)
Entergy
9
21.
Steve Myers (G2)
ERCOT
22.
Marc Tunstall (G6)
Fayetteville PWC
9
23.
Pedro Modia (G1)
Florida Power and Light Company
9
24.
Barbara Jaindl
Florida Power and Light Company
9
25.
Greg Keller
Florida Power and Light Company
9
26.
John Tamsberg
Florida Power and Light Company
9
27.
Marty Mennes
Florida Power and Light Company
9
28.
Michael Warr
Florida Power and Light Company
9
29.
Eric Senkowicz (G1)
FRCC
30.
Mark Bennett (G1)
Gainesville Regional Utilities
31.
John West (G6)
Georgia Power Co.
9
32.
Jimmy Etheridge (G6)
Georgia Transmission Corporation
9
33.
Steve Burns (G6)
Gulf Power Co.
9
34.
David Kiguel (G4) (I)
Hydro One Networks, Inc.
9
35.
George Juhn
Hydro One Networks, Inc.
9
36.
Roger Champagne (G4) (I)
Hydro-Québec TransÉnergie
9
37.
Ron Falsetti (G2) (G4) (I)
IESO Ontario
9
38.
Bill Shemley (G4)
ISO-NE
9
9
9
9
9
9
9
9
9
9
9
-2-
9
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Commenter
Organization
Industry Segment
1
2
39.
Kathleen Goodman (G4) (I)
ISO-NE
9
40.
Matt Goldberg (G2)
ISO-NE
9
41.
Brian Thumm
ITC Transmission
42.
Clark Hawkins (G1)
Lee County Electric Cooperative
43.
Eric Ruskamp (G3)
LES
44.
Don Nelson (G4)
MA Dept. of Tele. and Energy
3
4
5
6
7
8
9
10
9
9
9
9
9
9
9
9
45.
Robert Coish (G3) (I)
Manitoba Hydro
46.
Tom Mielnik (G3)
MEC
9
47.
Dick Pursley (G3)
Midwest Reliability Organization
9
48.
Bill Phillips (G2)
MISO
49.
Terry Bilke (G3)
MISO
9
50.
Carol Gerou (G3)
MP
9
51.
Joe Knight (G3)
MRO
9
9
52.
Richard Mider
New York State Electric and Gas
Corporation
9
53.
Herb Schrayshuen (G4)
NGRID
9
54.
Murale Gopinathan (G4)
Northeast Utilities
9
55.
Brian Hogue (G4)
NPCC
9
56.
Guy V. Zito (G4)
NPCC
9
57.
Alan Boesch (G3)
NPPD
9
58.
Jerad Barnhart (G4)
NSTAR
59.
Greg Campoli (G4)
NYISO
9
60.
Mike Calimano (G2)
NYISO
9
61.
Ralph Rufrano (G4)
NYPA
62.
Todd Gosnell (G3)
OPPD
63.
Tom Bowe (G2)
PJM
9
9
9
9
9
64.
Jack Gardner (G6) (I)
Progress Energy Carolinas
65.
C. Robert Moseley (G5)
Public Service Commission of SC
9
66.
David A. Wright (G5)
Public Service Commission of SC
9
67.
Elizabeth B. Fleming (G5)
Public Service Commission of SC
9
68.
G. O'Neal Hamilton (G5)
Public Service Commission of SC
9
69.
John E. Howard (G5)
Public Service Commission of SC
9
70.
Mignon L. Clyburn (G5)
Public Service Commission of SC
9
71.
Phil Riley (G5)
Public Service Commission of SC
9
72.
Randy Mitchell (G5)
Public Service Commission of SC
9
73.
Mike Gentry
Salt River Project
9
74.
Jerry Lindler (G6)
SCE&G
9
75.
John Wolfmeyer (G6)
SERC Vegetation Management
Subcommittee
76.
Sam Stonerock
Southern California Edison
9
77.
Jim Busbin (G7)
Southern Company Transmission
9
-3-
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
78.
JT Wood (G7)
Southern Company Transmission
9
79.
Marc Butts (G7)
Southern Company Transmission
9
80.
Roman Carter
Southern Company Transmission
9
81.
Charles Yeung (G2)
SPP
82.
Richard Dearman (G6) (I)
TVA
83.
Jim Haigh (G3)
WAPA
9
84.
Neal Balu (G3)
WPSR
9
85.
Pam Oreschnick (G3)
XEL
9
9
9
G1 – FRCC
G2 - ISO/RTO Council Standards Review Committee
G3 - Midwest Reliability Organization
G4 - NPCC CP9 - Reliability Standards Working Group
G5 – Public Service Commission of South Carolina
G6 - SERC Vegetation Management Subcommittee
G7 – Southern Company Transmission
I – Individual comments were submitted in addition to comments as part of a group
-4-
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Index to Questions, Comments, and Responses
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area. ................................................................................................... 6
2. Do you agree with the scope of the SAR? If not, please explain in the comment area. .18
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project? ............................................................35
-5-
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
1. Do you agree that there is a reliability-related need to address the proposed revisions to FAC-003-1 — Transmission
Vegetation Management? If not, please explain in the comment area.
Summary Consideration: Most commenters indicated that they do not believe there is a reliability need to revise the
technical aspects of this standard. The SAR Drafting Team agrees with commenters who indicated that the original was SAR
vague, and the drafting team modified the SAR to clarify that the proposed changes to this standard will address procedural
updates to bring the standard into conformance with the latest version of NERC’s Reliability Standards Development
Procedure and the Sanctions Guidelines in the ERO Rules of Procedure, and will also address the issues raised in the FERC’s
March 16, 2007 Order 693 - Mandatory Reliability Standards for the Bulk Power System.
Question #1
Commenter
Bonneville Power
Administration
Yes
No
;
Comment
Ok, Yes and No. The first FERC NOPR bullet needs to be addressed.
The second bullet is clearly discribed in the standard. A. 4.4.3. The reader must
read the statement in context. It meets the Standard Review Guidelines.
Response:
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to <200kV is necessary.
The Drafting Team does not agree that the Standard Review Guidelines have been met. For example the guidelines calls for ‘time
horizons’ to be assigned to each requirement, and the standard currently does not have these. The standard also needs to replace
its ‘levels of non-compliance’ with ‘violation severity levels’ to support the latest version of the Sanctions Guidelines.
Bandera Electric Coop.
;
The items listed as potential revisions are vague and do not provide sufficient
justification to alter the current requirements of this standard which has been in
effect less than 1 year. The current standard allows for the region to determine
which transmission lines are critical to reliability and should be included in a
Transmission Owner's Transmission Vegetation Management Plan regardless of
voltage classification. The current standard also allows each TO the flexibility to
develop its plan in accordance with its specific geography and operating
environment. There is no need to be more prescriptive.
Response:
The Drafting Team agrees that the first SAR draft was vague. The Drafting Team believes a revised standard is justified because it
needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to <200kV is necessary.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
-6-
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
Standards for the Bulk Power System.
ITC Transmission
While there may be "statutory" needs to address (e.g., FERC's request to modify
;
particular components of the existing Standard), we do not feel there is a reliability
need to do so.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
Hydro One Networks, Inc.
We believe that at this time it is premature to move forward with changes to the
;
standard that are based on voltage class issues. The Standard, as developed,
applies to the BES which have been determined by a performance based
methodology. NERC should wait until the BES vs. BPS issue is resolved.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
We believe that it is premature to move forward with changes based on voltage
Hydro-Québec TransÉnergie
;
class. Applicability of the standard should only be to those portions of the system
that are part of the Bulk Power System which have been determined by a
performance based methodology.
Response:
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to <200kV is necessary.
Northeast Power
NPCC participating members believe that it is premature to move forward with
Coordinating Council
changes based on voltage class. Applicability of the standard should only be to
;
those portions of the system that are part of the Bulk Power System which have
been determined by a performance based methodology.
Response:
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to <200kV is necessary.
American Electric Power
American Electric Power believes that the current standard (when thoroughly read
;
and understood) is completely adequate to maintain a reliable transmission system
with minimum risk of vegetation-related outages.
-7-
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following NEW procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
The current draft FAC 003 1 will provide a high level of reliability for the
New York State Electric and
Gas Corporation
transmission bulk delivery system which the public now expects. After a
;
comprehensive industry review which included industry balloting, the current
Vegetation Management Standard 003 1 was approved in Feburary 2006 and
several sections did not go in to effect for one year (2007). Sufficient time should
be allowed so that impact of the current standard can be monitored.
FAC 003 1 was designed to prevent cascading type outages and by establishing a
standard for 200KV lines and above catastrophic type power outages will be
eliminated. Lower volatge lines can be placed under this standard when the impact
on the bulk delivery system requires tighter management as determined by local
reliability organizations. Inspection cycles must be designed to meet regional
needs based on local conditons, and the current standard provides this flexiblity.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following NEW procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to <200kV is necessary.
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
SERC Reliability Corporation
The SERC VMS is unsure how to answer the question as it is worded, but has the
; ;
following comments on the SAR:
The current standard contains appropriate requirements and measures to ensure
the owners vegetation management program is implemented and managed to
ensure the reliability of the transmission system. Mandating inspection cycle
-8-
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
frequencies will not enhance nor ensure reliability by inspecting more or less
frequently. The minimum vegetation clearances at maximum operating conditions
that are established within the owner's program, which is auditable by the ERO, will
ensure reliability. Extending the requirements to lines other than those >200KV
may reduce the focus on those lines and may cause the allocation of resources
away from lines >200KV. Generally easements are narrower on lower voltage lines,
requiring more resources and emphasis on these lines. This may have an effect on
the ability to focus clearing efforts on those lines that will have a much greater
impact on the bulk power system. The IEEE standard when used as the minimum
clearance distance at maximum operating condition will ensure reliability when
these clearances are maintained by vegetation management activities. In addition,
we do not agree that a standard of zero tolerance for vegetaion-related outages in
the ROW is weak on compliance.
Response:
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team agrees with the commenter and recognizes that the IEEE standard is applicable.
The Drafting Team modified the SAR to eliminate the comment that the standard is weak on compliance as this comment was
satisfied when Version 1 of the standard was developed.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
The current standard contains appropriate levels of guidelines and penalties to
Progress Energy
;
ensure the owners vegetation management program is implemented and managed
to ensure the reliability of the transmission system. Mandating inspection cycle
frequencies will not enhance nor ensure reliability by inspecting more or less
frequently. The minimum vegetation clearances at maximum operating conditions
that are established within the owner's program that are auditable by the ERO will
ensure reliability. By adding lines other than those >200KV may reduce the focus
on those lines and impact the budget dollars allocated to focus on the lines
>200KV. Generally easements are much more narrow on lower voltage lines, the
impact on budget dollars would often require more emphasis on these lines. This
may have an effect on the ability to focus clearing efforts on those lines that will
have a much greater impact on the bulk power system. The IEEE standard when
used as the minimum clearance distance at maximum operating condition will
ensure reliability when these clearances are maintained by vegetation management
activities.
-9-
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
Response:
The current version of the standard does not include ‘time horizons’ and uses ‘levels of non-compliance’ rather than ‘violation
severity levels’ - ‘time horizons’ and ‘violation severity levels’ are needed to conform to the latest version of the Sanctions
Guidelines included in the ERO Rules of Procedure.
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team agrees with the commenter and recognizes that the IEEE standard is applicable.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
CenterPoint Energy disagrees that there is a reliability-related need to address the
CenterPoint Energy Houston
Electric, LLP
proposed revisions to FAC-003-1.
;
This SAR proposes to establish a minimum vegetation inspection cycle for
transmission facilities throughout the United States. Yet, based upon the location
of each utility, different vegetation and growth rates will be experienced
throughout the country. Placing a time specific vegetation management cycle for
all regions does not address the wide divergence of vegetation and growth rates
that each utility must face.
For instance, in certain areas of the country, such as desert areas, vegetation
growth rates are exceedingly small; therefore, vegetation management cycles
would likely be for extended periods of time. Placing a required frequent cycle will
unnecessarily increase the costs to ratepayers. While in other parts of the country,
vegetation can grow rapidly, and there should be shorter periods of time for the
vegetation management cycle.
Based upon these facts, CenterPoint Energy does not believe that adopting a
standard inspection cycle that is applicable to all regions is prudent. However,
CenterPoint Energy understands and supports the concept of standard
requirements applicable to all regions where such standardization is practical and
reasonable. In the specific case of vegetation management, it may be reasonable
and practical to establish a national standard based on maximum number of
allowed annual vegetation-caused outages per 100-circuit-miles of transmission.
Such a standard would allow utilities flexibility to use inspection cycles and other
practices that are prudent based on each utility's circumstances while still holding
utilities accountable for the results.
- 10 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
The SAR also proposes to change the 200 kV threshold and use of the IEEE
standard for minimum clearances. These requirements were established by a
broad consensus of industry experts. CenterPoint Energy believes the broad
industry consensus on these matters should be respected.
CenterPoint Energy submits the following specific comments:
Minimum inspection cycle, FERC NOPR Paragraph 382CenterPoint Energy disagrees that “complete discretion left to the transmission
owners in determining inspection cycles limits the effectiveness of the Reliability
Standard.” The standard is effective because it requires the transmission owners
to balance several factors to achieve the optimum inspection cycle.
It is not necessary to specify a specific inspection interval in the standard. The
inspection cycle interval is one component of several conditions to be considered in
FAC-003-1 Requirement R1.2.1 for establishing the required Clearance 1 of the
NERC standard. Other conditions that should be considered include operating
voltage, appropriate vegetation management techniques, fire risk, reasonably
anticipated tree and conductor movement, species types and growth rates, species
failure characteristics, local climate and rainfall patterns, line terrain and elevation,
location of the vegetation within the span, and worker approach distance
requirements. It is the growth rate of the vegetation coupled with the amount of
clearance achieved at the time of maintenance that determines the inspection cycle
interval. As such, the longer the inspection interval, the larger the clearance that
must attained to achieve balance. If the utility does not achieve balance, then it
will likely not avoid vegetation-related outages. It would not be necessary for a
utility to be faulted based on its inspection interval, rather it would be measured
for compliance under FAC-003-1 D2.3.1, D2.3.2, D2.3.3, and D2.4.1 for
operational conditions regarding maintaining the minimum clearance (Clearance 2)
required under FAC-003-1 Requirement R1.2.2 and any actual vegetation-related
outages.
FERC NOPR Paragraph 383-
- 11 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
CenterPoint Energy disagrees that “a one-year vegetation inspection cycle is the
“norm” for the industry.” The reference to “76 of 161 entities surveyed conduct
ground inspections once a year” was taken from Table 3 entitled “Ground
Inspection Frequency”. The table can also be interpreted to indicate that 78 of 161
entities surveyed conduct ground inspections on cycles other than once a year. At
best, the table shows a distribution of the varying practices of companies surveyed.
The table by itself does not indicate the level of reliability provided by each of those
companies.
The table entries may also be incomplete because the original order under Docket
EL04-52-000 under paragraph 12c asked “how often the transmission provider
inspects that facility for vegetation management purposes” which did not specify
ground or aerial inspection. The EEI template that many respondents used did
specify ground inspection and aerial inspection separately, but the template was
not used by all of the respondents as noted in the report. Interpolation of the data
collected may have affected the accuracy of the results reported, so specific
conclusions should consider the disparity between how the data request was
worded and how the data was reported. It is important to clearly distinguish
between ground inspection, aerial inspection, and pruning cycle when soliciting and
interpreting industry data. Additionally, new technologies such as airborne laser
surveys are coming to the market which may replace or augment other types of
vegetation inspections as they become cost-effective. The industry “norm” may
change as a result.
FERC NOPR Paragraph 384Although CenterPoint Energy does not agree with establishing a “one year
minimum inspection cycle”, it should be left to the discretion of the transmission
owner as to what type of inspection is employed so that the most cost-effective
methods can be utilized, depending on the system’s size and terrain. It should also
be made clear that “inspection cycle” is not intended to mean “pruning cycle”.
Remove 200kV threshold, FERC NOPR Paragraph 385CenterPoint Energy believes the applicability of FAC-003-1 should be “to all
transmission lines operated at 200kV and above and to any lower voltage lines
- 12 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
designated by the regional reliability organization as critical to reliability”, because
such a standard most closely matches the vegetation management reporting
requirements from Docket EL04-52-000. Voltages below this threshold are not
likely to impact the reliability of the Bulk Power System. Further, regional
reliability organizations have the authority to designate lower voltages critical to
reliability as appropriate. The proposed change is unnecessary.
IEEE Standard as basis for minimum clearance to prevent flashover (Clearance 2) CenterPoint Energy believes that the IEEE standard is sufficient and appropriate as
a basis to determine the specific radial clearances to be maintained between
vegetation and conductors under all rated electrical operating conditions (Clearance
2). Clearance 2 also must consider additional clearance for the dynamic movement
of the transmission conductors to avoid vegetation related outages. Thus, the
minimum clearances that a transmission owner must identify and document
depend on a variety of conditions including, but not limited to, transmisison line
voltage, temperature, wind velocities, and altitude.
Response:
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team agrees with the commenter and recognizes that the IEEE standard is applicable.
- 13 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Central Hudson Gas &
Electric
Yes
No
Comment
;
The proposed revisions listed under the FERC NOPR do not provide proper
justification to alter the requirements in the current FAC-003-1 document that was
adopted one year ago.
First, "a minimum vegetation inspection cycle that allows variation in physical
difference" is already called for under the current standard. As stated in Section
R1.1. of FAC-003-1, a schedule already should be defined under the transmission
vegetation management program (TVMP). This schedule already allows for
"variation in physical difference" since the current standard states that "this
schedule should be flexible enough to adjust for changing conditions."
Secondly, under Applicability Section 4.3., the current standard already allows for
lines with lower voltage than 200kV to be "designated by the RRO as critical" and
therefore applicable to the standard. Removal of the 200kV benchmark is not
needed.
And lastly, under the FERC staff report, the IEEE standard provides guidance in
clearances and has been the industry standard for many years. If FERC objects to
using this standard then they should provide clearances that can be discussed and
agreed upon by the transmission owners.
Response:
The FERC is no indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team agrees with the commenter and recognizes that the IEEE standard is applicable.
There was no empirical or anecdotal evidence presented by FERC staff to support
Southern California Edison
;
the Commission's view that the reliability of the Bulk Power System will be
enhanced with further revisions to FAC-003-1. This standard was the subject of
vigorous industry debate in a previous SAR. Although it is far from perfect, the
proposed revisions will not improve reliability and may very well damage existing
VM programs.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following NEW procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
- 14 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
The revisions listed in the NOPR and FERC Staff Report do not provide the
Baltimore Gas and Electric
;
necessary justification to alter the requirements in the current FAC-003-1
document. The existing requirements already allow for each utility to specify the
inspection requirements. There is no need to more prescriptive. The existing
requirements already allow for the ERO to designate critical lines less than 200 kV
so removal of the 200 kV benchmark is unecessary. The IEEE Standard is
worthwhile to keep as a benchmark without which there would be no solid guidance
for minimum clearances.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following NEW procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
The FERC is no indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team agrees with the commenter and recognizes that the IEEE standard is applicable.
We are not sure what you are asking? If you are asking whether we support the
Southern Company
Transmission
standard as it exists today-Southern does! If you are asking whether Southern Co.
; ;
supports the changes being recommended in this Standard-we DON"T.
The present standard appears to be serving its intended purpose and the industry
as currently written. The standard should not be revised until it has demonstrated
it is ineffective or inadequate for ensuring the reliability of the nation's transmission
grid.
Any changes to the standard should be based on empirical data rather than the
assumption that the Standard is not serving its intended purpose. The standard
has not been in effect long enough to determine if it is ineffective.
Response:
- 15 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
The Drafting Team agrees that the first SAR draft was vague. The Drafting Team believes a revised standard is justified because it
needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
As worded this question is confusing however the following comments are
TVA
; ;
presented on the SAR:
The current standard contains appropriate requirements and measures to ensure
that vegetation related outages will not cause cascading transmission blackouts.
Mandating new explicit inspection cycle frequencies will not enhance nor ensure
reliability by inspecting more or less frequently. The current minimum vegetation
clearances at maximum operating conditions that are established within the
owner's program, which is auditable by the ERO, is sufficient to prevent vegetation
related cascading transmission
blackouts. Extending the requirements to a much a larger population of lines would
reduce the current focus on the most important lines (those >200 kV). The IEEE
standard when used as the minimum vegetation clearance distance at maximum
operating condition will ensure desired performance of the lines. A standard of zero
tolerance for vegetation related outages in the ROW is not a weak standard on
compliance.
Response:
The Drafting Team agrees that the first SAR draft was vague. The Drafting Team believes a revised standard is justified because it
needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
The FERC is no indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team agrees with the commenter and recognizes that the IEEE standard is applicable.
- 16 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
FPL recognizes the need to address the concerns outlined in the NOPR and by the
Florida Power and Light
Company
FERC Staff.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
Public Service Commission of
South Carolina
;
Manitoba Hydro
IESO Ontario
Salt River Project
ISO New England
Dominion - Electric
Transmission
Midwest Reliability
Organization
ISO/RTO Council Standards
Review Committee
Allegheny Power
;
;
;
;
;
;
;
;
;
- 17 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Summary Consideration: Many commenters indicated there is no need to change the applicability of the requirements in
this standard. The FERC indicated that the Standard Drafting Team should review and consider whether a change to the
applicability to voltage <200kV is necessary.
Furthermore, some commenters expressed support for the IEEE standard’s use in the FAC-003-1 Standard while the FERC
declines to endorse the use of the IEEE standard as the ‘only’ minimum clearance. The SAR was revised to indicate that the
Standard Drafting Team will seek to clarify the rationale for the use of the IEEE standard in supplemental reference material
to be prepared as part of the scope of this SAR.
Question #2
Commenter
Bonneville Power
Administration
Yes
No
;
Comment
Since this posting is for comment it would have been nice to provide more
information as to why the FERC staff objects to the IEEE standard (since it meets
the guidelines for as a North America standard. Also, why are stakeholders
concerned with Reliability Coordinators vs. RRO?
Response:
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
The Drafting Team believes a revised standard is justified because it needs to include the following NEW procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity. Making FAC-003 applicable to the RRO is in
violation of the legislation that established the ERO. This legislation states that enforceable standards can apply only to
owners, users and operators of the bulk power system.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
Bandera Electric Coop.
;
;
As submitted, the SAR appears to completely re-open this standard negating many
months of work and industry comment to reach the consensus reflected in the
current FAC-003.
Response:
The ERO Rules of Procedure include the latest versions of the Reliability Standards Development Procedure Manual and the Sanctions
Guidelines. These documents were approved following the approval of FAC-003-1. FAC-003-1 will need to be revised to bring the
standard into conformance with these documents.
Northeast Power
See response to question 1, above.
Coordinating Council
Response: See the drafting team’s response to your comments on question 1.
CenterPoint Energy does not agree with the scope of the SAR for the reasons
CenterPoint Energy Houston
Electric, LLP
discussed in response to question 1.
;
;
- 18 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Response: See the drafting team’s response to
Central Hudson Gas &
Electric
Response: See the drafting team’s response to
American Electric Power
;
;
Comment
your comments on question 1.
See comments above.
your comments on question 1.
American Electric Power is not aware of any evidence to support a need for revising
the vegetation management standard.
Response:
The ERO Rules of Procedure include the latest versions of the Reliability Standards Development Procedure Manual and the Sanctions
Guidelines. These documents were approved following the approval of FAC-003-1. FAC-003-1 will need to be revised to bring the
standard into conformance with these documents.
FRCC
As stated in this SAR comment form, the improvements should be made to bring
;
the standard into conformance with the Reliability Standards Development
Procedure which at this time is version 6.0, adopted by NERC BOT, 11/1/2006. The
SAR scope via the attached Standard Review Guidelines includes two areas not
defined within the procedure. The Mitigation Time Horizons and definitions for the
violation severity levels (VSLs), Lower, Moderate, High and Severe.
We understand the description of Mitigation Time Horizons and definitions for VSLs
are included in the SAR (the concept of Violation Time Horizons is included in the
Sanctions Guidelines, appendix 4B, NERC Compliance Filing to FERC dated October
18th, 2006), but these discrepancies are part of a broader policy issue and since
their use is not clearly stipulated in the NERC Reliability Standards Development
Procedure, including them in the scope of the SAR is premature and will cause
unnecessary confusion to stakeholders and regulators.
The process is requesting the industry to comment on a scope that is defined
outside the reliability standards process and as such is subject to revisions and
interpretations outside the process as well. This appears inappropriate and at the
extreme will lead to inconsistent understanding, measurement and enforcement of
compliance actions.
The Mitigation Time Horizons and VSL levels should be defined in the Reliability
Standards Development Procedure prior to inclusion in the scope of a SAR.
Specific Items Within Current SAR Scope:
- 19 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
The establishment of minimum inspection cycles has been addressed previously, in
the development of the current standard and was found very problematic given the
large variety of vegetative conditions throughout North America. The vegetation
that was identified as a contributing cause to the 2003 Northeast Blackout had
already been identified by previous inspection activities. It was the failure to take
action on the known site conditions that contributed to the event. Therefore, a
minimum inspection cycle would still NOT have prevented or mitigated the scope of
the Blackout.
The current 200 kV threshold ensures that vegetation management efforts are
focused on the critical bulk power transfer lines and that TVM efforts are not diluted
by including additional lower voltage lines. In practicality, the RRO designation
process provides the necessary flexibility to the Regions to address localized areas
where bulk power system reliability may be compromised by lower voltage
vegetation outages. To note as well, Northeast Blackout related vegetation outages
which initiated the cascade occurred on lines that operate at 345 kV, well above the
current threshold.
The FRCC supported the development of Clearance 2, as established in the current
standard, as this was a consensus selection by not only the subject matter experts,
but many industry participants. Picking the ANSI Z133.1 Table 1 or 2 as the NOPR
suggests, could immediately place thousands of miles of transmission lines out of
compliance even though operating data indicates that the lines have performed
satisfactorily for years. The concern would be, the resulting dilution of valuable
industry and regulator resources.
The SAR includes the following stakeholder comment: "Too weak on compliance" .
We caution that we feel the compliance section does need refining, but that in a
world of limited resources should focus on trends in vegetation outages and not
necessarily on single outages. For transmission owners, two outages on a radial
230 kV circuit should not carry the same penalty as eight outages on multiple 230
kV circuits within a network. We would recommend that compliance be refined to
identify trends, relevance and risk probability to help the industry focus their
resources appropriately.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
- 20 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to <200kV is necessary.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability Standards
for the Bulk Power System.
ITC Transmission
The Standard Drafting Team should not be given lattitude to "include other
;
improvements to the standards deemed appropriate by the drafting team." The
purpose of the SAR is to identify the changes contemplated by the need for the
Standard Revision. If there are changes that the SAR requestor would like to make
to the Standard, they should be spelled out in the SAR. If the SAR requestor does
not really know the changes that should be made to the standard, then the SAR
should be withdrawn until the need for a SAR can be adequately justified.
Response:
The Drafting Team agrees and has removed the paragraph in the brief description of the SAR that opened the scope to other
improvements.
ISO/RTO Council Standards
The SRC (ISO-NE) would suggest that the SAR be clear that it will be a complete
Review Committee
review of the subject requirements: to include the addition, deletion and
;
modification of
requirements as agreed to by public consensus.
ISO New England
Response:
The Drafting Team removed the paragraph in the brief description of the SAR that opened the scope to other improvements. The
Drafting Team concurs with consensus of the commenters that the technical elements of this standard are complete. The intent of the
SAR modification is to address FERC issues and to conform to updates in the Reliability Standards Development Procedure and
Sanctions Guidelines.
FERC staff report has objection to use IEEE standard. Should we understand that
Hydro-Québec TransÉnergie
;
;
another standard is recommended instead?
Response:
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
Hydro One Networks, Inc.
To address FERC's objection to use the IEEE standard, it is necessary to clarify the
;
objective of the Vegetation Management Standard. As we understand it, the focus
of the FAC-003-1 standard is system reliability and as such, the responsibility and
authority on defining and applying the safety margins is rightly assigned to the
transmission owner. We request clarification on how employing safety factors will
address reliability and how prescribing minimum clearances within the standard will
- 21 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
improve reliability.
Please note that the Canadian Standards Association is revising standard C22.3 No.
1 - Overhead Systems. The new version will include clearances to vegetation and
the proposed minimum clearances are in alignment with FAC-003-1.
Response:
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
SERC Reliability Corporation
Minimum Inspection Intervals:
;
Progress Energy
;
The SERC VMS (Progress Energy) believes that FAC 003-1 provides the proper
amount of flexibility regarding vegetation inspection cycles and that the Standards
Drafting Team should not impose minimum inspection intervals on a continent with
such regional diversity in climate and plant life.
The purpose of Requirement 1.1 of standard FAC-003-1 is to put the responsibility
for proper inspection cycles on the entity that knows the local conditions and can
best define what that inspection frequency should be, the Transmission Owner.
Both NERC and the FERC staff have recognized that various local conditions can
have an affect on the determination of adequate inspection frequencies.
Establishing a mandatory minimum inspection frequency could have two
detrimental effects on the industry.
First, where a particular region is heavily forested and has heavy rainfall along with
extended or year round growing seasons, a “back stop” minimum inspection
frequency could lead transmission owners to conduct inspections less frequently
than required by the local conditions. This could result in a Transmission Owner
complying with the standard while not adequately protecting the reliability of that
region’s transmission system. This is a “lowest common denominator” approach
which FERC has repeatedly stated is inappropriate for the reliability standards.
Second, where a particular region is arid, sparsely forested or has a minimum
growing season, a “back stop” minimum could require a more frequent interval than
is realistically needed. This would result in increased and unnecessary costs for
electric utility customers without providing an increase in system reliability.
In its discussion of inspection intervals, FERC indicates that a “one-year vegetation
- 22 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
inspection cycle is reasonable.” FERC NOPR, 10/20/2002 paragraph 383. The
Commission continues by stating “a one-year inspection cycle is the ‘norm’ for the
industry, but not the lowest common denominator…” It follows from this
observation that the industry as a whole recognizes and follows appropriate
inspection intervals without a need to change the standard. Further, FERC also
states “some variation to a continent-wide, one-year minimum inspection cycle
should be allowed due to physical differences such as climate and species of
vegetation.” FERC NOPR 10/20/2006, paragraph 382. FERC’s express recognition
that a “one size fits all” approach is not appropriate further supports the SERC
VMS’s contention that the existing inspection requirements in standard FAC-003-1
should remain unchanged.
Finally, the performance metrics of FAC-003 require the reporting of applicable
transmission interruptions that are caused by vegetation. This process should
appropriately identify Transmission Owners’ inspection cycles that are not
adequate. In this event, the ERO has the authority to engage the Transmission
Owner in enforcement compliance actions and, therefore, can remedy any
vegetation-related outage that is attributed to the Transmission Owner’s inspection
frequency.
Standard Applicability:
The SERC VMS disagrees with the proposal to revise the 200 kV threshold for
determining facilities subject to this standard.
The majority of transmission facilities below 200 kV have significantly different
design/construction/operating characteristics and have not been cited as impacting
bulk power system reliability. For example, the Final Report on the August 14,
2003 Blackout in the United states and Canada: Causes and Recommendations
April 2004 by the U.S.- Canada Power System Outage Task Force and all referenced
major blackouts(pages 103-115) in that report, cited only outages which involved
vegetation at line voltages above 200 kV. Generally applying requirements
appropriate for 200 kV lines to lines less than 200 kV will result in significant
documentation and reporting of items such as restrictions, mitigation plans, off
right-of-way vegetation-related outage investigation/information and other issues,
all of which dilutes the focus on lines that directly impact bulk power system
reliability.
- 23 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
Revising the standard to use general criteria or broad language for defining "Bulk
Power System" transmission lines covered by the standard could become a “one
size fits all” approach. If that approach were taken, the standard would cover a
significant number of transmission lines that have no direct impact on bulk power
system reliability under standard planning/operating conditions, resulting in a
significant increase in costs for electric customers without improving “Bulk Power
System” system reliability. The SERC VMS believes that the applicability provision
of the standard should instead focus attention of the standard only on the
transmission lines below 200 kV that directly impact “Bulk Power System”
reliability, as the current version requires.
In sum, while the SERC VMS (Progress Energy) recognizes some validity in the
Commission’s concern, the SERC VMS (Progress Energy) recommends that the
applicability provision of this standard should be revised only if existing system
design, planning or operating reliability criteria and parameters are considered as a
basis for defining the applicability of the standard. To that end, the SERC VMS
recommends each Regional Entity (RE) determine applicability of FAC-003 to those
lines within the region that are between 100 kV and 200 KV if and only if they are
identified as operationally significant elements of Interconnection Reliability
Operating Limits (“IROLs”).
IEEE Standard for Minimum Clearances:
The SERC VMS disagrees with objections in the FERC staff report to the use of the
IEEE 516-2003 clearance as the minimum acceptable distances for “Clearance 2”.
The IEEE 516-2003 tables are appropriate for defining the minimum acceptable
clearances to prevent flashover between conductors and vegetation under all rated
electrical operating conditions. Closer minimum clearances such as the minimum
length of a support insulator could have been adopted as a “lowest common
denominator” clearance. However the clearance in IEEE 516-2003 was adopted to
ensure an additional margin of reliability. FERC staff references ANSI Z-133 which
is a safety standard that addresses worker safety as well as the safety of the
general public. As such, the purpose of ANSI Z-133 is to address worker safety and
is not focused on transmission line reliability, which is the purpose of FAC-003-1.
OSHA, NESC and other related safety standards have clearances in excess of IEEE
516-2003. Those clearances are clearly focused on safety issues and will still apply
- 24 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
to other aspects of design and operation of electric facilities (such as public and
worker safety) but do not need to be referenced in a vegetation management
reliability standard.
Response:
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
Minimum Inspection Intervals:
TVA
;
FAC 003-1 provides the proper amount of flexibility regarding vegetation inspection
cycles and that the Standards Drafting Team should not impose minimum
inspection intervals on a continent with such regional diversity in climate and plant
life.
Requirement 1.1 of standard FAC-003-1 places the responsibility for proper
inspection cycles on the entity that knows the local conditions and can best define
what that inspection frequency should be, the Transmission Owner. Both NERC and
the FERC staff have recognized that various local conditions can have an affect on
the determination of adequate inspection frequencies. Establishing a mandatory
minimum inspection frequency could have two detrimental effects on the industry.
First, where a particular region is heavily forested and has heavy rainfall along with
extended or year round growing seasons, a “back stop” minimum inspection
frequency
could lead transmission owners to conduct inspections less frequently than required
by the local conditions. This could result in a Transmission Owner complying with
the standard while not adequately protecting the reliability of that region’s
transmission
system. This is a “lowest common denominator” approach which FERC has
repeatedly stated is inappropriate for the reliability standards.
Page 5 of 6 January 15, 2007
Second, where a particular region is arid, sparsely forested or has a minimum
growing season, a “back stop” minimum could require a more frequent interval than
is realistically needed. This would result in increased and unnecessary costs for
electric utility customers without providing an increase in system reliability. In its
- 25 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
discussion of inspection intervals, FERC indicates that a “one-year vegetation
inspection cycle is reasonable.” FERC NOPR, 10/20/2002 paragraph 383. The
Commission continues by stating “a one-year inspection cycle is the ‘norm’ for the
industry, but not the lowest common denominator…” It follows from this
observation that the industry as a whole recognizes and follows appropriate
inspection intervals
without a need to change the standard. Further, FERC also states “some variation
to a continent-wide, one-year minimum inspection cycle should be allowed due to
physical differences such as climate and species of vegetation.” FERC NOPR
10/20/2006, paragraph 382. FERC’s recognition that a “one size fits all” approach is
not appropriate supports maintaining the existing inspection requirements in
standard FAC-003-1. Finally, the performance metrics of FAC-003 require the
reporting of applicable
transmission interruptions that are caused by vegetation. This process will identify
Transmission Owners’ inspection cycles that are not adequate. In this event, the
ERO has the authority to engage the Transmission Owner in enforcement
compliance actions and, therefore, can remedy any vegetation-related outage that
is attributed to the Transmission Owner’s inspection frequency.
Standard Applicability:
The 200 kV threshold for determining facilities subject to this standard should not
be revised. The transmission facilities below 200 kV have not been cited as
impacting bulk power system reliability. The Final Report on the August 14, 2003
Blackout in the United
states and Canada: Causes and Recommendations April 2004 by the U.S.- Canada
Power System Outage Task Force and all referenced major blackouts(pages 103115) in that report, cited only outages which involved vegetation at line voltages
above 200 kV. Generally applying requirements appropriate for 200 kV lines to lines
less than 200 kV will result in significant documentation and reporting of items such
as restrictions, mitigation plans, off right-of-way vegetation-related outage
investigation/information and other issues, all of which dilutes the focus on lines
that directly impact bulk power
system reliability. Revising the standard to use general criteria or broad language
for defining "Bulk Power System" transmission lines covered by the standard could
become a “one size fits all” approach. If that approach were taken, the standard
would cover a significant
- 26 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
number of transmission lines that have no direct impact on bulk power system
reliability under standard planning/operating conditions, resulting in a significant
increase in costs for electric customers without improving “Bulk Power System”
system reliability.
The SERC VMS believes that the applicability provision of the standard should
instead focus attention of the standard only on the transmission lines below 200 kV
that directly impact “Bulk Power System” reliability, as the current version requires.
The applicability provision of this standard should be revised only if existing system
design, planning or operating reliability criteria and parameters are considered as a
basis for defining the applicability of the standard. To that end, each Regional Entity
(RE) should determine the applicability of FAC-003 to those lines within the region
that are
between 100 kV and 200 KV if and only if they are identified as operationally
significant elements of Interconnection Reliability Operating Limits (“IROLs”).
IEEE Standard for Minimum Clearances:
Page 6 of 6 January 15, 2007
The IEEE 516-2003 should continue to be used as the minimum acceptable
distances for “Clearance 2”. The IEEE 516-2003 tables are appropriate for defining
the minimum acceptable clearances to prevent flashover between conductors and
vegetation under all
rated electrical operating conditions. Closer minimum clearances such as the
minimum length of a support insulator could have been adopted as a “lowest
common denominator” clearance. However the clearance in IEEE 516-2003 was
adopted to ensure an additional margin of reliability. FERC staff references ANSI Z133 which is a
safety standard that addresses worker safety as well as the safety of the general
public. As such, the purpose of ANSI Z-133 is to address worker safety and is not
focused on transmission line reliability, which is the purpose of FAC-003-1. OSHA,
NESC and other
related safety standards have clearances in excess of IEEE 516-2003. Those
clearances are clearly focused on safety issues and will still apply to other aspects
of design and operation of electric facilities (such as public and worker safety) but
do not need to be
referenced in a vegetation management reliability standard.
Response:
- 27 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
The scope of this SAR would have been better defined if the complete Standard
Midwest Reliability
Organization
Review Form for the Vegetation Management Standard had been included as an
;
;
attachment to the SAR. Several issues in the Standard Review Form for this SAR
were excluded with this posted SAR. For example, issues related to R3.1 and R3.2.
The MRO is also not clear on the scope of the instruction to the SDrafting Team to
"Expand the applicability to include transmission lines operated at 200 kV and
above and other facilities as determined by the ERO so that the Reliability Standard
applies to Bulk-Power System transmission lines that have an impact on reliability"
It is not clear to the MRO what is meant by "as determined by the ERO". What
process will the ERO use? The ERO should use stakeholder input to make this
determination. The current standard is applicable to all transmission lines 200 kV
and above and to any lower voltage lines designated by the RRO as critical to the
electric system in the region. Will the ERO be in a position to assume the
assessment of the criticality of lines less than 200 kV without input from the entities
that have historically operated in each region?
Also, the MRO is not clear on what is included in the term Bulk-Power System.
What guidance will the SDrafting Team have in determining what is meant by the
Bulk-Power System? Since this relates to the large issue of the Bulk Electric
System versus Bulk-Power System is this SAR the appropriate vehicle to address
this issue? There should be a wider discussion and resolution to this issue for
consistent application to all standards by all SDrafting Teams.
Response:
The comments on R3.1 and R3.2 were developed by NERC staff in a previous version of this SAR and these have been deleted from
the revised SAR. Instead, the Standard Drafting Team will apply the Standard Review Guidelines to the Standard.
The comments from the FERC NOPR were removed from the revised SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
Establishing minimum inspection cycles is a very problematic given the large
Florida Power and Light
Company
variety of vegetative conditions throughout North America. In reality most lines are
;
inspected annually for all failure modes including vegetation. The trees that played
a part of the North East Blackout were known and on the radar screen. The utility
- 28 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
failed to take action. The inspection did not prevent the outage from occurring. The
failure to take action on the known site condition was the contributing factor to the
Blackout.
We do not understand the need to establish separate criteria other than the RRO’s
critical designation. A transmission line is either necessary to the system to prevent
an overload situation or it is not. To add lines that might not be critical to the
system would dilute the effort needed to insure that the critical lines are properly
maintained. Since system stability is the focus of the standard, what criteria would
be used to bring additional lower voltage lines under the standard.
When developing Clearance 2, the committee needed to determine a distance at
which a Transmission Owner could be out of compliance even though no
interruption has occurred. In a sense this is the maximum ‘speed limit’ at which the
utility would be in violation. Their criteria was “How close can a tree be and not
cause an outage?” The engineers on the team reviewed scientific data and current
standards. The IEEE MAID standard was the consensus selection of the sub
committee. All parties need to understand that this is one of the building blocks
that would be used in determining the width of an easement or ROW. Picking the
ANSI Z133.1 Table 1 or 2 as the NOPR suggests could immediately place thousands
of miles of transmission lines out of compliance that have performed satisfactorily
for years. The ANSI tables are phase to phase safety calculations when grow-in tree
interruptions are phase to ground situations.
Response:
The FERCis no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
We are concerned that lowering the applicability threshold to all lines below 200KV
Public Service Commission of
South Carolina
will divert attention and resources from the higher voltage lines which have a
;
higher probability of causing grid problems. The RRO and transmission owners best
know which lower voltage lines should be included under the requirements of the
- 29 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
standard.
Response:
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
With respect to the item in the Brief Description section under FERC NOPR:
IESO Ontario
;
“Remove the applicability to transmission lines operated at 200 kV and above so
that the Reliability Standard applies to Bulk Power System transmission lines that
have an impact on reliability as determined by the ERO.” It is the IESO’s view that
requiring the ERO to make these determinations, is inappropriate. We believe the
standard should remain applicable to lines 200 kV and above and lines below 200
kV as determined by the Reliability Coordinator, similar to the PRC-023 standard.
The IESO also suggests that it be made clear in the SAR that it will be a complete
review of the subject requirements: to include the addition, deletion and
modification of requirements, as agreed to by public consensus.
Response:
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to transmission voltage class
<200kV is necessary.
The Drafting Team removed the paragraph in the brief description of the SAR that opened the scope to other improvements. The
Drafting Team concurs with consensus of the commenters that the technical elements of this standard are complete. The intent of the
SAR modification is to address FERC issues and to conform to updates in the Reliability Standards Development Procedure and
Sanctions Guidelines.
We disagree with the proposal from FERC NOPR regarding removing applicability to
Dominion - Electric
Transmission
transmission lines >200kv. The proposal to apply the Standard to lines the ERO
;
deems to have an impact on reliability can create inconsistency between regions
and is a "fill in the blank" requirement. It is not clear whether the proposed change
would increase or decrease the number of transmission lines which are subject to
reportable outages. In addition, we support the Standard's existing language that
limits reporting to locked out lines only.
Response:
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Commission's reccomendation to develop a "minimum" vegetation inspection
Southern California Edison
;
cycle is untimely and their proposal to revise the scope ignores plain language
contained in the standard.
In SCE’s view, the Commission's incessant need to bolt on a "widget count"
requirement (for minimum inspection cylcles) will likely lead to an increased
number of tree-to-line contacts. Unlike the static equipment located in power plants
- 30 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
and substations, trees and foliage in and around Transmission ROWs are subject to
uncontrolable and fairly unpredictable natural forces. Industry debate during the
previous SAR and comments submitted in the recently concluded NOPR
demonstrate this approach is unsound. Transmission Owners in neighboring states
commented that their cycles and trimming protocols vary from year to year and
sometimes circuit to circuit. Instituting a minimum inspection cycle of 3 years (for
example) might appeal to certain TOs because doing so will support a case for
increased rate recovery. But for others, a mandatory 3 year inspection cycle will
offer a potential cost reduction opportunity because they are already following a
voluntary 2 year inspection cycle.
The Commission's other reccomendedation should be rejected because subsection
4.3 clearly covers transmission lines operating below 200 kV. ["….any lower voltage
lines designated by the RRO as critical to the reliabilty of the electric system in the
region.”]
FAC-003-1 requires Transmission Owners to - “define a schedule for and the type
(aerial, ground) of ROW vegetation inspections”. Although the Commission staff
would prefer a specific time duration because it suits their "check list" style of
enforcement, the prudent thing to do is allow TOs the latitude to manage their part
of the bulk system and hold each accountable to the existing compliance measures
in FAC-003-1. Similarly, revising subsection 4.3 in deferrence to the Commission's
or staff's misinterpretation of plain text is unwarranted.
Response:
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle in its March 16, 2007 Order 693 and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The current standard FAC 003 1 should be monitored for one to two full years after
New York State Electric and
Gas Corporation
all segments have been implemented. February 14, 2007 is too soon to determine
;
if a revision is required.
The standard should apply to 200 KV lines and higher voltages to prevent cascading
type power outages.
The IEEE table 516 is referenced as a minimum guide for table 2 clearances. This
table provides clear and measurable distances that can used for audits and
- 31 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
potential compliance issues. The current standard allows enough flexibility so that
the clearance 2 distance can be expanded if a utility feels that is the correct
approach in a specfic region.
The physical differences between electric systems, tree growth rates, local
regulations, climate, and geography make it important to provide a flexible
standard, a "one size fits all" approach will not be effective in the long run.
Response:
The ERO Rules of Procedure include the latest versions of the Reliability Standards Development Procedure Manual and the Sanctions
Guidelines. These documents were approved following the approval of FAC-003-1. FAC-003-1 will need to be revised to bring the
standard into conformance with these documents.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The scope of the SAR is too vague on several important points.
Manitoba Hydro
;
(1) There is no definition for the phrase bulk-power system - it would be therefore
unclear as to what facilities would be covered by the standard. What guidance will
the SDrafting Team have in determining what is meant by the bulk-power system?
Since this relates to the large issue of the Bulk Electric System versus Bulk-Power
System is this SAR the appropriate vehicle to address this issue? There should be a
wider discussion and resolution to this issue for consistent application to all
standards by all SDrafting Teams.
(2)The concept of Mitigation Time Horizons has not been defined and the use of
Mitigation Time Horizons has not been detailed.
(3)The ERO is not the appropriate entity to determine which lines have an impact
on reliability. This should be Transmission Operators in coordination with Reliability
Coordinators. If this standard is to include the methodology to determine which
lines have a reliability impact on the bulk-power system, the the applicability of the
- 32 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
standard will have to include other entities besides the Transmission Owners.
(4) The SAR refers to RA, i.e., Reliability Authority. This entity no longer exists in
the Functional Model but has been replaced by Reliability Coordinator.
(5) What is meant by "Too weak on compliance"?
(5) FERC objects to IEEE Standard but there is no other guidance to the standard
drafting team.
Response:
The comments regarding Bulk Power System in the FERC NOPR comments were removed from the revised SAR.
The ERO Rules of Procedure require the inclusion of time horizons for each standard – these are defined in the Sanctions Guidelines
and are used to help determine the size of a sanction.
The revised SAR does not include the language proposing that the ERO determine which lines have an impact on reliability.
The reference to Reliability Authority (RA) was removed from the revised SAR.
The reference, ‘Too weak on compliance’ was removed from the revised SAR as it was addressed with the development of Version 1 of
this standard.
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
The scope of the SAR should be limited to formatting and changes of wording that
Southern Company
Transmission
recognize the formation of the ERO and its procedures.
;
The drafting team should not attempt to re-write the present clearance
requirements, which are based on IEEE flashover distances. The clearance
requirements in the orignal standard were written through extensive evaluation and
input from the industry. There was strong industry consensus on the present
language and the standard is serving its intended purpose very well. The clearance
standard should not be revised until it is found to be ineffective or inadequate.
The drafting team should not attempt to change the applicability of the present
standard. The present standard applies to all 200 KV and higher lines, plus any
other line the Regional Entity deems critical. A change in wording to make the
standard apply to any bulk power system transmission line deemed critical by the
ERO does not provide any additional safeguard that is not already contained in the
standard as presently written.
Response:
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
- 33 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
standard and the Drafting Team agreed to address their questions and concerns.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
As noted above.
Baltimore Gas and Electric
;
Response: See response to your question #1 comment above.
Salt River Project
Allegheny Power
;
;
- 34 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
3. Are there additional revisions, beyond those identified in the SAR that should be addressed within the scope of this project?
Summary Consideration: Commenters suggested a number of additional revisions to the SAR related to:
Applicability
Right of Way (ROW) definition
Compliance
Clearance requirements
Others
The SAR Drafting Team revised the SAR to consider these suggested revisions.
Question #3
Commenter
Bonneville Power
Administration
Yes
;
No
Comment
It is not clear if categroy 1 and 2 refer only to occupied ROW, or also to unoccupied
area reserved by the Transmission Owner for future expansion.
Response:
o Category 1 outages refer to “grow-ins” inside or outside the right-of-way regardless; while a Category 2 outage applies to “fall-ins”
on land that is inside the legal bounds of the right-or-way whether occupied or not.
The FERC has directed the ERO to address the definition of ROW in its Order 693.
As part of the SAR, the SAR Drafting Team commits the Standard Drafting Team to prepare technical reference material such as a
“white paper” to aid in understanding the technical basis for the standard and, unless the requirements in the standard are modified
to add more clarity, the SAR Drafting Team will recommend that the white paper include a discussion of the differences between
category 1 and category 2 to address your concern.
FRCC
Requirement 3.2, item (1), the reporting exemption for outages occuring due to
;
natural disaters should be expanded to include all vegetation outages that occur as
a result of the disaster. Currently the exemption applies to vegetation from outside
the ROW.
As a result of significant experience with hurricanes, our operators have found that
this distinction results in a waste of post-disaster resources. The standard currently
requires the owner to investigate and determine the original location of the
vegetation that may have caused an outage. Restoration of circuits may be
delayed and often times, determination of the original location of the vegetation is
not possible.
Response:
The SAR Drafting Team will review the reporting exemptions to all category outages under major disasters in Requirement R3.2.
Northeast Power
Only if the Bulk Power System is determined as an impact based performance
Coordinating Council
based methodology.
;
Response:
- 35 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #3
Commenter
Yes
No
Comment
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The comments regarding Bulk Power System in the FERC NOPR comments were removed from the revised SAR
SERC Reliability Corporation
;
Standard Applicability:
The outage reporting requirement for the RRO should be deleted. Making FAC-003
applicable to the RRO is in violation of the legislation that established the ERO. This
legislation states that enforceable standards can apply only to owners, users and
operators of the bulk power system. Futher, in the NOPR on NERC standards, FERC
declined to approve those standards that applied to the RROs, in part because the
RROs are not owners, users or operators.
Compliance:
The SERC VMS recommends deleting reporting requirements for Category 3
outages. These outages are not controllable, not relevant to compliance, not
related to grid reliability, not related to cascading blackouts, and such reporting
leads to unnecessarily biasing reliability related information.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team intends to review reporting criteria for Category 3 outages in the proposed technical reference material
and may review the reporting requirement of Category 3 outages in R.3 and R.4.
Standard Applicability:
Progress Energy
;
The outage reporting requirement for the RRO should be deleted. Making FAC-003
applicable to the RRO is in violation of the legislation that established the ERO. This
legislation states that enforceable standards can apply only to owners, users and
opeartors of the bulk power system. Futher, in the NOPR on NERC standards, FERC
declined to approve those standards that applied to the RROs, in part because the
RROs are not owners, users or operators.
Compliance:
Progress Energy believes that FAC-003 should focus compliance on the issues that
improve system/grid reliability. The VM standard outage reporting requirements do
not focus on ensuring grid/network reliability.
- 36 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #3
Commenter
Yes
No
Comment
Category 2 outages (“Fall-ins” from vegetation within the R/W) result in a level of
non-compliance (Level 2 or 3). However, “Fall-ins”, either off-R/W or within the
R/W, are random events. They would not occur sequentially (i.e., a fall-in causing
another line section to overload resulting in another “fall-in”) and would not have
the potential to cascade into a widespread blackout. This is a customer reliability
issue for that line, not a grid reliability issue. While it may be worthwhile to report
for tracking and trending, it is not an outage that should result in non-compliance.
Category 1 “Grow-ins” include outages that result from conductor side-wing would
be reported as Category 1 outages, resulting in non-compliance (Level 3 or 4).
However, conductor side-swing outages are random occurrences. They are not the
sequential outages that would have the potential to cascade into a widespread
blackout. This is a customer reliability issue for that line, not a grid reliability issue.
These types of outages should be not be considered any different than numerous
other random events that result in transmission line outages.
Response:
The SAR Drafting Team understands the distinction between grow-in and fall-in related outages and the prediction challenges with
fall-in related outages. Modifying the compliance section is included in the scope of the SAR.
Requirement 3.2 exempts reporting of outages from outside the ROW when natural
Florida Power and Light
Company
disasters such as tornados or hurricanes occur. Our experience with numerous
;
hurricanes indicates that all outages during these types of events should be
exempt. The focus in these situations is to get the lines back in service and restore
customers. There is insufficient manpower to adequately complete the forensics
necessary to determine an accurate root cause. It is not uncommon to find
vegetation debris in the lines or downed trees on the ROW in this situation. In most
cases it is not possible to determine the original location of these trees.
In the compliance section of the document a transmission owner becomes non
compliant with a single category 1 or 2 outage. This occurs regardless of the
circumstances. A non compliant penalty for a single outage in a situation where no
customers were affected and the system could not have been compromised is not
reasonable. It is also not an indicator of a poorly maintained system. We agree that
several Category 1 or 2 interruptions could be an indicator of neglect but one is not.
We recommend that The compliance section be reviewed with this in mind.
Response:
The Standard Drafting Team will review the reporting exemptions to all category outages under major disasters in Requirement
- 37 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #3
Commenter
Yes
No
Comment
R3.2.
Modifying the compliance section is included in the scope of the SAR.
Since the IEEE standard does not appear to be a favorable clearance requirement,
Midwest Reliability
Organization
minimum clearance requirements should be tied to legal documents such as
;
easments, state statute, or permits. This will help Transmission Owners to
maintain their ROWs based on their agreements with the land owners and not rely
on historical ROW management practices. It would also provide flexibility in
clearance requirements based on geopraphical and climatological factors that
influence different regions because landowner agreements will be different
depending on local influences.
Response:
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
TVA
Standard Applicability:
;
The outage reporting requirement for the RRO should be deleted. Making FAC-003
applicable to the RRO is in violation of the legislation that established the ERO. This
legislation states that enforceable standards can apply only to owners, users and
operators of the bulk power system. Further, in the NOPR on NERC standards, FERC
declined to approve those standards that applied to the RROs, in part because the
RROs are not owners, users or operators.
Compliance:
Reporting requirements for Category 3 outages should be eliminated. These
outages are
not controllable, not relevant to compliance, not related to grid reliability, not
related to cascading blackouts, and such reporting leads to unnecessarily biasing
reliability related information.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
The Standard Drafting Team intends to review reporting criteria for Category 3 outages in the proposed technical reference material
and may review the reporting requirement of Category 3 outages in R.3 and R.4.
- 38 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #3
Commenter
Bandera Electric Coop.
Yes
No
;
Response: See response to Comment #2.
ITC Transmission
;
Comment
See Comment #2
We think the Standard is fine the way it is.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
American Electric Power
As stated in responses to questions 1 and 2, AEP believes that the current standard
;
is adequate and that we are not aware of evidence to support a need for revising
the current vegetation management standard.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will address improvements identified by the FERC in its Order 693 - Mandatory Reliability Standards for
the Bulk Power System.
Although SCE is wholly dissatisfied with the integration of IEEE 516-2003 into FACSouthern California Edison
;
003-1 and looks forward to the day when qualified industry professionals and utility
arborists are provided an opportunity to develop a reasonable and scientifically
sound method for determining “minimum” tree-to-line clearances, we believe this
standard should be allowed to “soak” a bit before subjecting it to further revision.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will address improvements identified by the FERC in its Order 693 - Mandatory Reliability Standards for
the Bulk Power System.
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
- 39 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #3
Commenter
New York State Electric and
Gas Corporation
Yes
No
;
Comment
The Vegetation Management Standard FAC 003 1 is comprehensive, and utilities
following the established guidelines will be able to meet FERC's expecation of
preventing bulk power delivery outages by using crisp measurable guidleines that
offer limited flexiblity for varying conditions.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels, etc.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
ISO/RTO Council Standards
Review Committee
Hydro One Networks, Inc.
Allegheny Power
Dominion - Electric
Transmission
CenterPoint Energy Houston
Electric, LLP
ISO New England
Central Hudson Gas &
Electric
Public Service Commission of
South Carolina
Hydro-Québec TransÉnergie
Southern Company
Transmission
IESO Ontario
Salt River Project
Baltimore Gas and Electric
;
;
;
;
;
;
;
;
;
;
;
;
;
- 40 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
- 41 -
Consideration of Comments on Second Draft of Vegetation Management SAR
(Project 2007-07)
The Vegetation Management SAR drafting team thanks all commenters who submitted
comments on Draft 2 of the SAR. This SAR was posted for a 30-day public comment period
from April 20 through May 9, 2007. The drafting team asked stakeholders to provide feedback
on the SAR through a special SAR Comment Form. There were 27 sets of comments, including
comments from 65 different people from more than 50 companies representing 7 of the 10
Industry Segments as shown in the table on the following pages.
Based on the comments received, the drafting team recommends that the Standards
Committee advance this SAR to the standard drafting step of the standard development
process. The drafting team made only one minor modification to the SAR to clarify (on page
2) that it is the ERO that will collect vegetation-related transmission outage data, not the SDT.
In this “Consideration of Comments” document stakeholder comments have been organized so
that it is easier to see the responses associated with each question. All comments received on
the standards can be viewed in their original format at:
http://www.nerc.com/~filez/standards/Vegetation-Management_Project_2007-7.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal
is to give every comment serious consideration in this process! If you feel there has been an
error or omission, you can contact the Director of Standards, Gerry Adamski, at 609-452-8060
or at [email protected]. In addition, there is a NERC Reliability Standards Appeals
Process.1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
Consideration of Comments on Second Draft of Vegetation Management SAR (Project 2007-07)
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 – Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
1.
Anita Lee (G1)
AESO
2.
Jay Farrington (G5)
Alabama Electric Coop.
9
3.
Randy Gann (G5) (G6)
Alabama Power
9
4.
Ken Goldsmith (G6)
ALT
5.
Mary Hetz
Ameren
9
6.
Raymond Wiesehan
(G5)
Ameren
9
7.
Thad Ness
American Electric Power
9
8.
John Neagle (G5)
Associated Electric Coop.
9
9.
William T. Rees, Jr.
Baltimore Gas & Electric
10.
Dave Rudolph (G6)
Basin Electric Power
Coop.
11.
Brent Kingsford (G1)
CAISO
12.
John R. Kellum, Jr.
CenterPoint Energy
9
13.
Weston J. Davis
Central Maine Power
9
14.
CJ Ingersoll
Constellation (CEDC)
15.
Gene Walton
Dominion
9
16.
Gregory Rowland
Duke Energy
9
17.
Billy George (G5)
Duke Energy, Carolinas
9
18.
Ralph Hale (G5)
Entergy
9
19.
Paul D. Olivier
Entergy Corporation
9
20.
Steve Myers (G1)
ERCOT
21.
Marc Tunstall (G5)
Fayetteville Public Works
Comm.
9
22.
Doug Hohlbaugh
FirstEnergy Corp.
9
23.
John Tamsberg
Florida Power & Light Co.
9
24.
Nancy Huddleston
(G6)
Georgia Power Co.
9
25.
Joe Knight (G6)
Great River Energy
26.
Steve Burns (G6)
Gulf Power Co.
2
3
4
5
6
7
8
9
10
9
9
9
9
9
9
9
9
9
9
9
Page 2 of 53
9
9
June 22, 2007
Consideration of Comments on Second Draft of Vegetation Management SAR (Project 2007-07)
Commenter
Organization
Industry Segment
1
2
3
4
5
6
9
9
7
8
9
10
27.
Ken Trump (G6)
Gulf Power Co.
9
28.
David Kiguel
Hydro One Networks Inc.
9
29.
George Juhn
Hydro One Networks Inc.
9
30.
Roger Champagne
Hydro-Québec
TransÉnergie (HQT)
9
31.
Ron Falsetti (I) (G1)
Independent Electricity
SO
9
32.
Matt Goldberg (G1)
ISO-NE
9
33.
Kathleen Goodman (I)
G2)
ISO-NE
9
34.
Robert Coish (I) (G6)
Manitoba Hydro
35.
Terry Bilke (G6)
Midwest ISO
9
36.
Mike Brytowski (G6)
Midwest Reliability
Organization
9
37.
Carol Gerou (G6)
Minnesota Power
9
38.
Bill Phillips (G1)
MISO
39.
Steve Craig (G6)
Mississippi Power Co.
9
40.
Ron Reinike (G6)
Mississippi Power Co.
9
41.
Thomas E. Sullivan
National Grid
9
42.
Anthony Johnson
Northeast Utilities
9
43.
Mike Calimano (I)
(G1)
NYISO
9
44.
Todd Gosnell (G6)
OPPD
45.
Stephen Tankersley
Pacific Gas and Electric
Co. (PGE)
46.
Alicia Daugherty (G1)
PJM
47.
Jack Gardner (G3)
(G5)
Progress Energy
Carolinas
9
48.
John Pinney (G3)
Progress Energy Florida
9
49.
Philip Riley (G4)
Public Service
Commission SC
9
50.
Mignon L. Clyburn
(G4)
Public Service
Commission SC
9
51.
Elizabeth B. Fleming
(G4)
Public Service
Commission SC
9
52.
G. O’Neal Hamilton
(G4)
Public Service
Commission SC
9
53.
John E. Howard (G4)
Public Service
Commission SC
9
54.
Randy Mitchell (G4)
Public Service
Commission SC
9
55.
C. Robert Moseley
(G4)
Public Service
Commission SC
9
9
9
9
9
9
9
Page 3 of 53
June 22, 2007
Consideration of Comments on Second Draft of Vegetation Management SAR (Project 2007-07)
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
56.
David A. Wright (G4)
Public Service
Commission SC
57.
John Wolfmeyer (G5)
SERC
58.
Jerry Lindler (G5)
South Carolina E&G
9
59.
Roman Carter (G6)
Southern Transmission
9
60.
Charles Yeung (G1)
SPP
61.
Richard Dearman (I)
(G5)
TVA
9
62.
Jeffrey S. Disorda
VELCO
9
63.
Jim Haigh (G6)
WAPA
9
64.
Neal Balu (G6)
WPSR
9
65.
Pam Oreschnick (G6)
Xcel Energy
9
9
9
9
I – Indicates that individual comments were submitted in addition to comments submitted as part of a
group
G1 – IRC Standards Review Committee (IRC SRC)
G2 – NPCC CP9 Reliability Standards Working Group (NPCC CP9)
G3 – Progress Energy Carolinas/Progress Energy Florida (PGN)
G4 – Public Service Company of South Carolina (PSC SC)
G5 – SERC Vegetation Management Subcommittee (SERC VMS)
G6 – Southern Company Transmission
G7– MRO Members
Page 4 of 53
June 22, 2007
Consideration of Comments on Second Draft of Vegetation Management SAR (Project 2007-07)
Index to Questions, Comments, and Responses
1.
Do you agree there is a reliability need for the proposed modifications and review of the
standard?.............................................................................................................. 6
2.
If you are a transmission owner, have you been provided a list from a Regional Entity
(formerly RRO) of sub 200 kV critical transmission lines that must comply with FAC-0031? .......................................................................................................................11
3.
If you are a transmission owner would you provide your methodology for determining
clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1 and R1.2.2) If so, please
attach..................................................................................................................16
4.
Are there any other comments regarding the standard, its possible modifications or the
SAR? ...................................................................................................................24
Page 5 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
1. Do you agree there is a reliability need for the proposed modifications and review of the standard?
Summary Consideration: Most commenters noted that while the FAC-003-1 Standard is technically adequate, they believed
that clarification in the form of a technical white paper, and review of applicability parameters is warranted. Many of these
commenters also agreed with the need to update the standard to conform to new procedural requirements and inclusion of
compliance elements. The SDT shall consider producing a white paper to aid in clarifying the intent of the standard.
Question #1
Commenter
AEP
Yes
No
Comment
AEP
believes
that
the
current
standard
(when
thoroughly read and understood) is
; completely adequate to maintain a reliable transmission
system with minimum risk of
vegetation-related outages.
Response: The team concurs that the technical elements are generally adequate and there is no reliability need to revise the
standard. However all NERC standards must be updated to comply with new procedural requirements and inclusion of
compliance elements. The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory
Reliability Standards for the Bulk Power System. The SDT shall consider producing a white paper to aid in clarifying the
intent of the standard.
Baltimore Gas &
not convinced that the elements outlined in the proposal will improve reliability and
; I'm
Electric
have concerns that the proposed modifications may actually reduce the flexibility that is
necessary to promote system reliability or to comply with local regulations. I would
prefer to see more specifics in the proposal before supporting the modifications.
Response: The team concurs that the technical elements are generally adequate and there is no reliability need to revise the
standard. However all NERC standards must be updated to comply with new procedural requirements and inclusion of
compliance elements. The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory
Reliability Standards for the Bulk Power System. The SDT shall consider producing a white paper to aid in clarifying the
intent of the standard.
CenterPoint Energy
Energy does not agree that a revision to the TVM standard is necessary from
; CenterPoint
a reliability standpoint, and believes that the existing TVM standard is adequate for that
purpose.
Response: The team concurs that the technical elements are generally adequate and there is no reliability need to revise the
standard. However all NERC standards must be updated to comply with new procedural requirements and inclusion of
compliance elements. The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory
Reliability Standards for the Bulk Power System. The SDT shall consider producing a white paper to aid in clarifying the
intent of the standard.
Central Maine Power
The current Vegetation Management Standard FAC-003-1 has been crafted in such a
; way
as to provide crisp measurable standards that when followed will provide a high
level of power quality for the bulk power delivery system. However, clearances between
Page 6 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #1
Commenter
Yes
No
Comment
conductors and trees required to prevent tree related power outages must be consistent
with each utility’s established standards and if a transmission line passes through
federal, state or locally managed areas this line placement should not impact the
established clearances. Utilities should not be expected to negotiate clearances with
multiple land managers.
The IEEE 516 – 2003 table is an acceptable table to use as the minimum clearance to
prevent a flash over and outages. FAC-003-1 is designed to be a reliability standard and
the industry adheres to OSHA and ANSI standards to protect workers and the public.
The IEEE 516 – 2003 table lists appropriate distances that should be used to measure
compliance. The standard should continue to provide the flexibility for utility managers
to increase “Clearance 2”.
The definition for right-of-way should be clarified to include only the area that is cleared
and included as routine maintenance.
We agree that there is a need to establish time horizons and clarify violation levels.
Response: The team concurs that the technical elements are generally adequate and there is no reliability need to revise the
standard. However all NERC standards must be updated to comply with new procedural requirements and inclusion of
compliance elements. The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory
Reliability Standards for the Bulk Power System, including a review of the definition for right-of-way. The SDT shall consider
producing a white paper to aid in clarifying the intent of the standard.
Duke Energy
a reliability perspective, the current standard contains appropriate requirements
; From
and measures to ensure the Transmission Owner's vegetation management program is
implemented and managed to ensure the reliability of the transmission system.
However the standard should be revised to address non-reliability related items that are
in the SAR.
Response: The SAR DT agrees and thanks you for the comment.
HQT
is our belief that the Standard in its current form does provide adequate provisions
; It
and drivers to minimize vegetation related outages and eliminate the likelihood of
reoccurence of the August 14, 2003 blackout. However, it is recognized that the
industry needs to consolidate its view on these provisions and we support the
preparation of a “white paper” that will document the rationale concerning the
requirements of the standard, as well as review certain aspects of the standard that
have come into question.
Response: The SAR DT agrees and thanks you for the comment.
Page 7 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #1
Commenter
Hydro One Networks
Yes
No
Comment
It
is
our
belief
that
the
Standard
in
its
current
form does provide adequate provisions
; and drivers to minimize vegetation related outages
and eliminate the likelihood of
reoccurence of the August 14, 2003 blackout. However, it is recognized that the
industry needs to consolidate its view on these provisions and we support the
preparation of a “white paper” that will document the rationale concerning the
requirements of the standard, as well as review certain aspects of the standard that
have come into question.
Response: The SAR DT agrees and thanks you for the comment.
National Grid
Grid believes that compliance with all elements of the present Standard will
; National
result in TO's achieving the reliability objectives set forth in the Standard.
Response: The SAR DT agrees and thanks you for the comment.
Northeast Utilities
modifications do not increase the levels of reliability above what is already
; Proposed
required in the current version of the Stnadard.
Response: The team concurs that the technical elements are generally adequate and there is no reliability need to revise the
standard. However all NERC standards must be updated to comply with new procedural requirements and inclusion of
compliance elements. The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory
Reliability Standards for the Bulk Power System. The SDT shall consider producing a white paper to aid in clarifying the
intent of the standard.
PGN
Energy Carolinas and Progress Energy Florida are providing an answer to the
; Progress
question as it relates to the reliability need. The current standard contains appropriate
requirements and measures to ensure the Transmission Owner's vegetation
management program is implemented and managed to ensure the reliability of the
transmission system. In addition, we do not believe that a standard with a zero
tolerance for vegetation-related outages in the ROW is in need of reliability-based
revisions.
However, we do recognize the need for a revision of the standard to address nonreliability related items that are in the SAR. Procedural items such as formatting and
clarifications, such as the definition of right-of-way, need to be, and should be,
addressed.
Response: The team concurs that the technical elements are generally adequate and there is no reliability need to revise the
standard. However all NERC standards must be updated to comply with new procedural requirements and inclusion of
compliance elements. The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory
Reliability Standards for the Bulk Power System. The SDT shall consider producing a white paper to aid in clarifying the
intent of the standard.
Page 8 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #1
Commenter
SERC VMS
Yes
No
;
Comment
The SERC VMS is providing an answer to the question as it relates to the reliability need.
The current standard contains appropriate requirements and measures to ensure the
Transmission Owner's vegetation management program is implemented and managed to
ensure the reliability of the transmission system. In addition, we do not believe that a
standard with a zero tolerance for vegetation-related outages in the ROW is in need of
reliability-based revisions.
However the SERC VMS recognizes the need for a revision of the standard to address
non-reliability related items that are in the SAR. Procedural items such as formatting
and clarifications, such as the definition of right-of-way, need to be, and should be,
addressed.
Response: The team concurs that the technical elements are generally adequate and there is no reliability need to revise the
standard. However all NERC standards must be updated to comply with new procedural requirements and inclusion of
compliance elements. The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory
Reliability Standards for the Bulk Power System. The SDT shall consider producing a white paper to aid in clarifying the
intent of the standard.
CECD
Modifications to capture the Commissions concerns must be addressed therefore these
;
actions are appropriate.
Response: The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
Dominion
We support reinstating the 200kv threshold for reportable events.
;
Response: The Standard DT will review applicability as requested by the FERC. See also the drafting team responses to
question #2.
Entergy Corp.
The existing FAC-003-1 is flawed and needs revision.
;
Response: The SAR DT agrees that revisions of this standard are needed primarily to comply with new procedural
requirements and inclusion of compliance elements as well as address issues raised in the FERC’s March 16, 2007 Order 693
– Mandatory Reliability Standards for the Bulk Power System.
FirstEnergy Corp.
FirstEnergy agrees that clarification on select issues will aid the intent of this NERC
;
Standard.
Response: The SAR DT agrees and thanks you for the comment.
Florida Power & Light ;
FPL believes the technical portion of the standard provides adequate reliability protection
to the system. FPL also recognizes the need to re-format the standard to bring it into
conformance with the latest version of the Reliability Standard Development Procedure
and the ERO Sanctions Guidelines, to remove references to RRO in the standard and
substitute a responsible entity and, add compliance elements such as time horizons, and
Page 9 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #1
Commenter
Yes
No
Comment
violation severity levels.
Response: The SAR DT agrees and thanks you for the comment.
IESO
;
IRC SRC
ISO-NE
Manitoba Hydro
;
;
;
The definition of ROW should be clarified. The definition of a critical line should not be
kept to a particular voltage threshold. However, consideration could also then be given
to exempting non-critical lines operating at higher voltage levels (>200kv). Electrical
clearances should be consistent whether on Federal or non-Federal land.
Response: The standard DT will review the definition of ROW. The standard DT will review applicability parameters of this
standard, taking into account the comments from stakeholders such as NU, National Grid, Manitoba Hydro, First Energy, and
others. The SAR DT concurs with the commenter with respect to applying this standard to Federal and non-Federal lands. The
standard DT will evaluate the suitability of a case-by-case approach.
MRO
;
NYISO
PGE
;
;
As stated in the SAR.
Response: The SAR DT agrees and thanks you for the comment.
PSC SC
;
Southern Transm.
We do not feel there is a reliability need for modifying the standard. However, we do
agree certain modifications are needed to clarify procedural issues such as the amount of
time allowed for taking corrective action when items are found to be out of compliance.
Response: The team concurs that the technical elements are generally adequate and there is no reliability need to revise the
standard. However all NERC standards must be updated to comply with new procedural requirements and inclusion of
compliance elements. The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory
Reliability Standards for the Bulk Power System. The SDT shall consider producing a white paper to aid in clarifying the
intent of the standard.
TVA
The primary needs for mocdifications to this standard are in areas to address
;
clarifications and formatting not reliability related issues.
Response: The SAR DT agrees and thanks you for the comment.
;
Page 10 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
2. If you are a transmission owner, have you been provided a list from a Regional Entity (formerly RRO) of sub
200 kV critical transmission lines that must comply with FAC-003-1?
Summary Consideration: During the March 2007 SAR DT meeting, the FERC indicated they had not been presented any
evidence with respect to Regional Entity (RE) critical line determinations and asked whether such lists existed. This question
was posed to ascertain whether REs have determined which lines below 200 kV are critical.
Some commenters reported that their RE (SERC, FRCC, RFC) have determined there are no critical transmission lines that are
under 200 kV. Some commenters (NGrid, NU, HydroOne, HQT) indicated that a list was not provided by their RE (NPCC). A
commenter (MRO) noted that a list was submitted to NERC. A commenter responded that their RE (WECC) has provided such a
list. On the basis of this informal poll, the SAR DT’s assessment is that further specificity may be needed to aid in identifying
which <200kV transmission lines should come under the purview of this standard in an attempt to standardize this criteria..
The SDT shall take under consideration other applicability parameter criteria in addition to various stakeholder proposals.
Question #2
Commenter
Yes No
IRC SRC
NYISO
Baltimore Gas &
;
Electric
Response: The SAR DT thanks you
CECD
;
Comment
n/a
n/a
The reason that we do not have a list of critical lines from the RRO may be that we do
not have any lines that fit the criteria.
for your response.
SERC does not currently have any sub 200 kV critical transmission lines.
Response: The SAR DT thanks you for your response.
CenterPoint Energy
;
Central Maine Power
;
Duke Energy
;
The “Northeast Power Coordinating Council Facilities Notification List” may not be the
correct list to be used for this standard. FAC- 003-1 should set a clear expectation the
each Regional Entity will provide their transmission owners a list of critical lines including
any that may be less that 200KV. Will provide list once released from NPCC.
Response: The SAR DT thanks you for your response.
Dominion
;
The SERC region has not identified any lines below 200kV to be critical to the electrical
system in the region. Since no lines have been identified as critical to the region, no list
has been provided to Transmission Owners.
Response: The SAR DT thanks you for your response.
HQT
consider that it should be the Planning Coordinator role to determine the sub 200kV
; We
critical transmission lines and even for any transmission lines irrelevant of voltage level.
Page 11 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #2
Commenter
Comment
For that, it should follow an impact based methodology such as the one used in NPCC.
Response: The SAR DT thanks you for your response.
Hydro One Networks
;
Manitoba Hydro
MRO
Yes
No
;
;
The MRO We have not generated a list or criteria yet. We have submitted a draft criteria
to NERC
Response: The SAR DT thanks you for your response.
National Grid
Reliability Entity has not provided a list of sub 200 kV lines subject to compliance
; The
with FAC-003-1. The Standard became effective in February 2007, just 3 months ago.
Having no list today should not imply that the RE or the Standard has failed in any way.
National Grid suggests that a revised Standard should direct the RE to produce a list of
"sub 200 kV critical transmission lines" within 6 to 12 months of adoption.
Response: The standard DT will review applicability parameters of this standard, taking into account the comments from
stakeholders such as NU, National Grid, Manitoba Hydro, First Energy, and others.
Northeast Utilities
Reliability Entity has not provided a list of facilities covered under FAC-003-1. This
; The
is not a fault of the RE as there has been no direction provided as to what factors or
charateristics are required for sub-200kV lines to be included under the Standard. It is
our position that the factors that will be used to develop the list of sub-200kV faciltities
to be covered by the Standard be developed at the national level (NERC) and adopted by
all RE's for consistency.
Response: The standard DT will review applicability parameters of this standard, taking into account the comments from
stakeholders such as NU, National Grid, Manitoba Hydro, First Energy, and others.
PGN
SERC and FRCC regions have not identified any lines below 200kV to be critical to
; The
the electrical system in the region. Since no lines have been identified as critical to the
region, no list has been provided to Progress Energy Carolinas and Progress Energy
Florida. (Please note our comments on this issue in question #4.)
Response: The SAR DT thanks you for your response.
SERC VMS
SERC region has not identified any lines below 200kV to be critical to the electrical
; The
system in the region. Since no lines have been identified as critical to the region, no list
has been provided to Transmission Owners. (Please note the subcommittee's comments
on this issue in question #4.)
Response: The SAR DT thanks you for your response.
TVA
detemined that there are no TVA lines below 200kv that must comply to this
; We
standard due to their criticial needs in SERC.
Page 12 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #2
Commenter
Yes No
Comment
Response: The SAR DT thanks you for your response.
VELCO
has not been provided a specific list of critical lines below 200 kV from the RE
; VELCO
that need to be in compliance with FAC-003-1. VELCO suggests changing the wording in
the standard to identify those lines affected as 200 kV and great or those defined as Bulk
Power System facilities.
Response: The standard DT will review applicability parameters of this standard, taking into account the comments from
stakeholders such as NU, National Grid, Manitoba Hydro, First Energy, and others.
Entergy Corp.
Yes, the Reliability Entity (SERC) has performed its duty in evaluating our transmission
;
system. SERC has confirmed that Entergy has no lines operating below 200kV that are
critical to system reliability. Entergy has received its "list," but the list is blank.
With respect to applicability, it is inappropriate to set a blunt voltage level criterion for
determining which transmission lines are critical to bulk system reliability. There is no
basis in engineering or in fact for voltage-based categories of applicability. Many lines
operating at 200kV and higher essentially serve only local load, and there may in fact be
some lines operating below 200kV where the standard should be applied. Many lines of
all voltages are redundant and do not even impact local load during an outage.
Therefore, the voltage criterion is overly broad.
To support this statement, Entergy supplies the following facts:
First, during the aftermath of Hurricanes Katrina and Rita, Entergy had (59) 230kV and
500kV lines out of service simultaneously. Additionally, Entergy had (85) 115kV and
161kV lines out of service simultaneously. During the aftermath of Hurricane Rita,
Entergy had (41) 230kV and 500kV lines out of service simultaneously. Additionally,
Entergy had (124) 115kV and 161kV lines out of service simultaneously. Dispite this
overwhelming combination of simultaneous outages, no system-wide cascading blackout
was initiated. Only local load was lost during restoration. This illustrates that Standard
FAC-003-1, as it currently stands placing so much focus and penalty on even singlecontingency outages, is overbroad, arbitrary and capricious.
Second, each year the Entergy transmission system (like all other large electric utilities)
suffers numerous outages from a great number of different sources: material defects, rot
and decay, animal damage, human damage, extreme wind, lightning and, vegetation.
Over the years 2001 through 2006, 927 transmission lines suffered 5,688 outages from
a variety of sources. Vegetation outages accounted for 7.14% of those outages. Each
Page 13 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #2
Commenter
Yes
No
Comment
utility is unique, but these numbers are not unusual for a transmission system
comprising 15,000 miles of line. Dispite this large number of outages, no cascading
system black out has been intiated.
Finally, Entergy has had as many as 17 transmission lines outaged from a single tornado
event without even losing service to local load. Standard FAC-003-1 assigns too much
risk to outages in general, and too mush risk to vegetation outages in particular.
NERC and the regional reliability entities should define performance criteria that
specifically define certain contingencies and certain undesireable outcomes that would
classify a line as truly critical to bulk system reliability. The modeling software necessary
to do this is readily available and already in use today by the Reliability Entities and their
subject utilities.
If FERC has concerns about potentially devistating (albeit rare) combinations of multiple
simultaneous line outage contingencies, the REs can define strict criteria for multiple
contingencies. With respect to lines that result in IROLs and SOLs, these lines can also
be identified with specificity, without resorting to blunt voltage distinctions.
Defining system-critical lines too broadly is actually detrimental to FERC's reliability
goals. It dilutes the resources available to maintain reliability on those lines that truly
affect system reliability. Utilities should employ a more focused and intelligent approach
to targeted reliability. Such an approach would have benefits to the users of the
transmission system and to the ratepayers that pay for it.
Response: The standard DT will review applicability parameters of this standard, taking into account the comments from
stakeholders such as yourself and others.
Florida Power & Light ;
PGE
;
Provided from WECC
Response: The SAR DT thanks you for your response.
AEP
the three regions in which AEP has transmission facilities, only one RE has provided a
; ; Of
listing of sub-200 kV facilities of what we consider applicable under this standard.
Response: The SAR DT thanks you for your response.
FirstEnergy Corp.
the Reliability Entity (formerly the RRO) was requested to provide a list of
; ; ReliabilityFirst,
lines below 200 kV deemed as critical transmission lines that must comply with FAC-00301. ReliabilityFirst responded "there are no lines below 200kV deemed as critical
Page 14 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #2
Commenter
Yes
No
Comment
infrastructure".
Response: The SAR DT thanks you for your response.
Southern Transm.
are not really sure how to answer this question. The Regional Entity has not sent us
; ; We
a list, but they have advised us that we do not have any sub 200 kv critical transmisison
lines that must comply with FAC-003-1.
Response: The SAR DT thanks you for your response.
Page 15 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
3. If you are a transmission owner would you provide your methodology for determining clearance 1 and
clearance 2? (As described in FAC-003-1 R1.2.1 and R1.2.2) If so, please attach.
Summary Consideration: This question was posed to poll transmission owners with respect to determination of Clearance 1
and Clearance 2 requirements. This information was sought to obtain examples of how industry members determine Clearance
1 since it is a qualitative requirement. Clearance 2 information was sought to evaluate the application of components of IEEE
516.
Of the 15 respondents to this poll question, some provided summary methodology for determining their Clearance 1 and
Clearance 2, others have indicated that a methodology exists and is available upon request. On the basis of these responses to
the poll question, the SDT shall consider reviewing IEEE 516 components to affirm their suitability in this standard and this
information can assist in a white paper.
Question #3
Commenter
Yes No
IRC SRC
NYISO
SERC VMS
Response: The SAR DT thanks you
Baltimore Gas &
;
Electric
Central Maine Power
;
Comment
n/a
n/a
This question does not apply to the SERC EC Vegetation Management Subcommittee.
for your response.
The clearance 2 was taken directly from IEEE Table 516 – 2003. Clearance 1 is based on
“Appendix C – ISO New England Right of way Vegetation Management Standard”.
Response: The SAR DT thanks you for your response.
Florida Power & Light
;
National Grid
Detailed methodology is not attached. In summary, National Grid used Table 5 IEEE
Section 516 for determing clearance 2. These data for each voltage class were rounded
to the next higher whole number. Clearance 1 was determined by adding the clearance
2 distance, conductor sag distance, and anticipated tree growth over the maintenance
cycle.
Response: The SAR DT thanks you for your response.
PGN
Energy has an individual on the Drafting Team and will share the Progress
; Progress
Energy Florida clearance Tables with the team.
Response: The SAR DT thanks you for your response.
VELCO
has defined Clearance 1 as the maximum allowed vegetation heights (12ft high)
; VELCO
at time of maintenance. This maximum height has evolved from experience with regional
;
Page 16 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #3
Commenter
Yes
No
Comment
growth rates and other factors. VELCO's Clearance 2 is determined by the New England
ISO's Operating Procedure 3, which is slightly more stringent than IEEE 516.
Response: The SAR DT thanks you for your response.
AEP
For Clearance 1, AEP has chosen to use the minimum approach distances set forth in
;
ANSI Tree Care Standard Z133.1 (rev. October 2000) for persons other than qualified
line-clearance arborists and qualified line-clearance arborist trainees. For Clearance 2,
AEP utilizes the Z133.1 minimum approach distances for qualified line clearance arborists
and qualified line-clearance arborist trainees.
Response: The SAR DT thanks you for your response.
CenterPoint Energy
CenterPoint Energy has developed a methodology to determine clearance 1 and
;
clearance 2 as described in FAC-003-1 R1.2.1 and R1.2.2. This methodology is included
in a document titled "Specification for Transmission Vegetation Management Program"
dated February 2007. Section 5.1 of that document covers NERC Clearance 1, and
Section 5.2 covers NERC Clearance 2. Text and Tables from both Sections 5.1 and 5.2
are shown below:
5.1
NERC CLEARANCE 1
5.1.1 The appropriate clearance to conductors at the time of vegetation management
work is established as Clearance 1 in accordance with NERC Standard FAC-003-1
Requirement R1.2.1.
5.1.2 Clearance 1 is determined by considering transmission line voltage, the effects of
ambient temperature on conductor sag under maximum design loading, the effects of
wind velocities on conductor sway, and the anticipated average growth rate of the
prevalent tree species within the Company’s service area over a 5-year period.
5.1.2.1
The minimum clearance distance of IEEE Standard 516-2003 Section
4.2.2.3, Minimum Air Insulation Distances without Tools in the Air Gap, is a component
of Clearance 1.
5.1.3 Table 5.1 contains the horizontal clearance components and nominal values for
Clearance 1, and Table 5.2 contains the vertical clearance components and nominal
values for Clearance 1.
Table 5.1
Page 17 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #3
Commenter
Yes
No
Comment
NERC Clearance 1: Horizontal Clearance, feet
Horizontal Clearance Component, Nominal Voltage p-p
69kV 138kV 345kV
Electrical Clearance (1)
Average 5-Year Horizontal Tree Growth
2.46
2.95
12.00 12.00
12.00
Average Mid-span Conductor Sway (2)
Total
5.98
20.44
Nominal Horizontal Value (3)
4.40
8.13 10.04
23.08 26.44
20
23
26
(1) Based on IEEE 516-2003 Table 5 for 69kV & 138kV and Table 7 for 345kV
(2) Based on NESC C2-2007 Rule 233A(1)
(3) May be reduced for site specific tree species or conductor span configuration but not
less than Clearance 2.
Table 5.2
NERC Clearance 1: Vertical Clearance, feet
Vertical Clearance Component, Nominal Voltage p-p
69kV 138kV 345kV
Electrical Clearance (1)
2.46
Average 5-Year Vertical Tree Growth
Average Conductor Final Sag Increase (2)
2.95
4.40
15.75 15.75
15.75
7.52
9.01 10.24
Total
25.73
27.71 30.39
Nominal Vertical Value (3)
26
28
Page 18 of 53
30
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #3
Commenter
Yes
No
Comment
(1) Based on IEEE 516-2003 Table 5 for 69kV & 138kV and Table 7 for 345kV
(2) Based on NESC C2-2007 Rule 233A(1)
(3) May be reduced for site specific tree species or conductor span configuration but not
less than Clearance 2.
5.2
NERC CLEARANCE 2
5.2.1 The minimum radial clearance to prevent flashover between vegetation and
conductors is established as Clearance 2 in accordance with NERC Standard FAC-003-1
Requirement R1.2.2.
5.2.2 Clearance 2 is determined by considering transmission line voltage, the effects of
ambient temperature on conductor sag under maximum design loading, and the effects
of wind velocities on conductor sway. Clearance 2 is a radial clearance, so the vertical
component and the horizontal component are both calculated, and the largest clearance
is selected as the prevailing clearance for Clearance 2.
5.2.2.1
The minimum clearance distance of IEEE Standard 516-2003 Section
4.2.2.3, Minimum Air Insulation Distances without Tools in the Air Gap, is a component
of Clearance 2.
5.2.3 Table 5.3 contains the horizontal clearance component, Table 5.4 contains the
vertical clearance component, and Table 5.5 contains the prevailing nominal values for
Clearance 2.
Table 5.3
Horizontal Clearance Component, feet
Horizontal Clearance Component, Nominal Voltage p-p
69kV
138kV 345kV
Electrical Clearance (1)
2.46
2.95
Average Mid-span Conductor Sway (2)
5.98
8.13 10.04
Page 19 of 53
4.40
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #3
Commenter
Yes
No
Comment
8.44 11.08 14.44
Total
Nominal Horizontal Value (3)
8
11
14
(1) Based on IEEE 516-2003 Table 5 for 69kV & 138kV and Table 7 for 345kV
(2) Based on NESC C2-2007 Rule 233A(1)
(3) May be reduced for site specific tree species or conductor span configuration but not
less than Clearance 2.
Table 5.4
Vertical Clearance Component, feet
Vertical Clearance Component, Nominal Voltage p-p
69kV
138kV 345kV
Electrical Clearance (1)
2.46
2.95
Average Conductor Final Sag Increase (2) 7.52
9.01
10.24
11.96
12
14.64
15
Total
Nominal Vertical Value (3)
9.98
10
4.40
(1) Based on IEEE 516-2003 Table 5 for 69kV & 138kV and Table 7 for 345kV
(2) Based on NESC C2-2007 Rule 233A(1)
(3) May be reduced for site specific tree species or conductor span configuration but not
less than Clearance 2.
Table 5.5
NERC Clearance 2: Minimum Radial Clearance to Prevent Flashover, feet
Nominal Voltage p-p
69kV
138kV 345kV
10 12
15
Page 20 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #3
Commenter
Yes No
Comment
Response: The SAR DT thanks you for your response.
Entergy Corp.
Entergy defines four sets of clearances for vegetation approach to transmission lines.
;
The first set of clearances is the Vegetation Pruning Distance. This is the clearance to be
achieved at the time of vegetation management work which vegetation management
employees and contractors complete as part of this program. This distance varies with
each line, but is set to be the EDGE OF ROW in each case. (This clearance is referred to
as “Clearance 1” in the NERC Vegetation standard FAC-003-1, Cf B.R1.2.1).
The second set of clearances is the Vegetation Growth Alert Distance. This is the
approach distance that triggers an alert to the Asset Management vegetation
management employees that vegetation maintenance is required. Vegetation spotted on
an aerial inspection that encroaches upon this clearance is noted on the inspection for
future scheduling of pruning.
The third set of clearances is the Minimum Energized Pruning Distance. This is the
minimum approach distance vegetation can have to energized transmission lines and still
be pruned without an outage on the energized transmission line, in accordance with
OSHA safety guidelines. Any vegetation that encroaches on this minimum distance must
be pruned, and must be pruned during an outage on the associated transmission line.
The fourth set of clearances is the Minimum Vegetation Approach Distance. This is the
absolute minimum radial approach distance to prevent flashover between vegetation and
overhead ungrounded supply conductors. Under this program, vegetation should never
encroach these minimum approach distances. Vegetation must be pruned prior to
reaching this distance and must be pruned with an outage on the transmission line.
(This distance is referred to as “Clearance 2” in the NERC vegetation standard, FAC-0031, Cf B.R1.2.2.) These clearance distances are based upon those set forth in the Institute
of Electrical and Electronics Engineers (IEEE) Standard 516-2003 (Guide for
Maintenance Methods on Energized Power Lines) and as specified in Table 5.
Under this program, vegetation can encroach the Vegetation Growth Alert Distance and
the Minimum Energized Pruning Distance, but it shall not encroach upon the Minimum
Vegetation Approach Distance.
Response: The SAR DT thanks you for your response.
Page 21 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #3
Commenter
FirstEnergy Corp.
Yes
;
No
Comment
For R1.2.1 (Clearance 1), FirstEnergy used our existing specification requirement "for
minimum clearance to be achieved at locations with an easement or other restriction" to
define the minimum acceptable clearance.
For R1.2.2 (Clearance 2), FirstEnergy uses the IEEE 516-2003 standard as the minimum
as referenced in FAC-003-01. This is the minimum clearance under all operating
conditions. FirstEnergy believes this is an appropriate definition.
Response: The SAR DT thanks you for your response.
HQT
HQT clearance methodology is not specifically based on the value specified in Clearance
;
1 and Clearance 2. HQT TVMP is such organized that vegetation management work
minimize costs for line clearing and brush control while preventing outages from
vegetation cause. As such, staff qualifications required to work near energized facilities
are less than under the absolute minimum as stipulated in IEEE 516-2003, and in most
cases, the work is less labour and equipment intensive. However clearances are never
less than the absolute minimum stipulated in FAC-003-1 (R1.2.2).
The above provides the basic approach used at HQT. If the Standard Drafting Team
would like a copy of the HQT approach and methodology, this could be provided.
Response: The SAR DT thanks you for your response.
Hydro One Networks
Hydro One clearance standards are based on the Ontario Health and Safety Act (OHSA)
;
clearances rather than the absolute minimum specified in Clearance 2. OHSA clearances
at time of work minimize costs for line clearing and brush control. By maintaining OHSA
clearances during normal working conditions, staff qualifications required to work near
energized facilities are less than under the absolute minimum as stipulated in IEEE 5153003, and in most cases, the work is less labour and equipment intensive. As part of
work planning, qualified staff determine the amount of vegetation that has to be
removed to achieve OHSA clearances at the time of the next scheduled work. As well,
provisions are built into the clearances at time of work to account for conductor and tree
movement during adverse weather conditions. The objective is to provide OHSA
clearances under adverse conditions, but these are not always achieved, however
clearances are never less than the absolute minimum stipulated in FAC-003-1.
The above provides a description of our planning process. If the Standard Drafting Team
would like a copy of the Hydro One standard, this can be provided.
Response: The SAR DT thanks you for your response.
Page 22 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #3
Commenter
Manitoba Hydro
Yes
Northeast Utilities
;
No
Comment
Clearance
1
was
developed
based
on
the
limits of approach for non-qualified people
;
(public). At a minimum, we would clear beyond this distance during vegetation control
activities. Our cycle times and management approach are adjusted for this distance,
taking into account growth rates. The values will vary depending on voltage class.
Clearance 2 is based on internal design standards that take into account our
understanding of switching surge values for our system. The values used are more
conservative than IEEE 516-2003.
Response: The SAR DT thanks you for your response.
MRO
n/a
;
The methodology for determining clearance 2 is based on the requirements of FAC-0031. The IEEE Section 516 has been considered the base minimum limits for clearances as
provided under FAC-003-1 R.1.2.2. Clearances used for R.1.2.1 on the NU Transmission
System comply with the requirements of ISO-NE Operating Procedure OP-3, that
provides clearance levels required at the time of vegetation trimming or clearing under
the various transmission voltages.
Response: The SAR DT thanks you for your response.
PGE
Will be provided to the SARDT in a separate attachment[TH1].
;
Response: The SAR DT thanks you for your response.
Southern Transm.
IEEE 516-2003, Section 4.2.2.3 was adopted as the minimum allowable distance for
;
Clearance 2, with the expectation that work would normally occur prior to Clearance 2
reaching the minimum allowable distance. Clearance 1 was determined by using the
Clearance 2 value and adding a growth buffer. Sagging of conductors and their
movement in wind was then considered to ensure the growth buffer is adequate.
Response: The SAR DT thanks you for your response.
TVA
We utilize a clearance 2 based on IEEE 516 2003 Table 5 criteria. Our Clearance 1 is a
;
greater amount to allow for growth between clearing and next inspection or clearance
activities. We will provide our tables is requested.
Response: The SAR DT thanks you for your response.
Page 23 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
4. Are there any other comments regarding the standard, its possible modifications or the SAR?
Summary Consideration:
The comments were mixed with regard to:
• Whether reporting of Category 3 outages are necessary.
Most that commented agreed that:
• The 200kV applicability threshold could be clarified and the SAR DT deemed a review of applicability parameters is
desirable.
• A consistent approach to both federal and non federal lands is desirable.
• A review of the definition of ROW is desirable.
• Components of the IEEE 516 standard are suitable.
• The exclusion of major disaster related events is appropriate.
• The inclusion of compliance elements and other procedural updates of the standard are needed.
• The development of a technical white paper is desirable.
• The standard DT should review the need for Requirement R4.
On the whole, the comments are supportive of the SAR as written and the SAR DT have made no changes to the second draft
of the request.
Question #4
Commenter
CenterPoint Energy
Yes
;
;
;
;
Manitoba Hydro
PSC SC
Southern Transm.
AEP
No
Comment
We appreciate the efforts of the SAR Drafting Team.
The SAR directs the SDT to collect and analyze outage data as part of an effort to define
clearances for transmission lines on federal and non-federal lands. AEP believes that the
analysis of outage data will be meaningless and unproductive. The SAR directive
presupposes a cause-and-effect relationship between vegetation-related outages and
federal/non-federal land status. On the contrary, AEP believes that vegetation-related
data is more indicative of the effectiveness of the utility's VM program, in spite of
onerous and inordinately expensive measures required on federal lands.
Response: The standard DT looks to receive the results of the ERO analysis and use it in developing the standard.
;
Page 24 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Ameren
Yes
;
No
Comment
Ameren does not agree that each of 11 items listed in the SAR are necessary to improve
reliability. The following comments are offered for each of the 11 items identified in the
SAR detail description:
1. Standard Applicability:
Ameren disagrees with revising the 200 kV threshold for determining facilities subject to
this standard. Extending the requirements to lines other than those >200kV will dilute
the focus on those lines that impact grid reliability and shift attention to facilities,
<200kV. Utilities generally have an incentive to maintain reliability on lines less than
200kV. State commissions and customer expectations for reliable service provide this
incentive. While many facilities above 200kV directly support customer load,
transmission lines below 200kV primarily support customer load, and interruptions to
those facilities reduces load on the grid.
The majority of transmission facilities below 200 kV also have significantly different
design/construction/operating characteristics and have not been cited as impacting bulk
power system reliability. For example, the Final Report on the August 14, 2003 Blackout
in the United states and Canada: Causes and Recommendations April 2004 by the U.S.Canada Power System Outage Task Force and all referenced major blackouts (pages
103-115) in that report, cited only outages which involved vegetation at line voltages
above 200kV. Generally applying requirements that are appropriate for >200kV lines to
lines less than 200kV will result in significant documentation and reporting of items such
as restrictions, mitigation plans, off right-of-way vegetation-related outage investigation/
information and other issues, all of which dilutes the focus on lines that directly impact
bulk power system reliability.
Revising the standard to use general criteria or broad language for defining "Bulk Power
System" transmission lines covered by the standard is a “one size fits all” approach. If
that approach were taken, the standard would cover a significant number of
transmission lines that have no direct impact on bulk power system reliability under
standard planning/operating conditions, resulting in a significant cost burden for electric
customers without improving “grid” reliability. Ameren believes that the applicability
provision of the standard should focus attention of the standard only on the transmission
lines below 200kV that directly impact “Bulk Power System” reliability, as the current
version requires.
Page 25 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
Ameren recognizes some validity in the Commission’s concern; Ameren recommends
that the applicability provision of this standard should be revised only if existing system
design, planning or operating reliability criteria and parameters are considered as a basis
for defining the applicability of the standard. Ameren recommends each Regional Entity
(RE) determine applicability of FAC-003 to those lines within the region that are between
100kV and 200KV, if, and only if, they are identified as operationally significant elements
of Interconnection Reliability Operating Limits (“IROLs”). That is, any facility below
200kV that by itself would cause an Interconnected Reliability Limit Violation should the
facility be outaged.
2. Issue of Clearances (Federal vs Non-Federal Lands):
FAC-003-1 presently requires the transmission owner (TO) “identify and document
clearances between vegetation and any overhead, ungrounded supply conductors, taking
into consideration transmission line voltage, the effects of ambient temperature on
conductor sag under maximum design loading, and the effects of wind velocities on
conductor sway.” The intent of this requirement is to ensure adequate clearances to
prevent vegetation related outages. Ameren believes that only the TO has the technical
information required to determine the clearances that are necessary at the time of VM
work and that any “federal lands exemption” to clearances will result in inadequate
clearances for the existing conditions. Consistency in application of the TO’s clearance
requirements, not exceptions, is the only assurance in providing a uniform and reliable
electrical system to meet the nation’s current and future energy demands.
Any exception for a case by case clearance approach to determine vegetation
management activities/clearances on Federal lands will continue to drive inconsistency
and/or delays associated with vegetation management decisions being driven by diverse
vegetation management practices/beliefs and staff changes at the local level of Federal
agencies. Vegetation-related outages have occurred on Federal lands as a result of this
case by case approach, and if “Bulk Power Transmission System” lines continue to be
addressed on a “case by case” basis on National Forest Service (or any other Federal
lands), those lines will potentially be subject to a higher risk for vegetation-related
outages, resulting in reduced reliability for the “Bulk Power System”.
Ameren believes that reliability of the “Bulk Power System” should have the same focus
on Federal and private lands and that the EEI MOU with federal agencies is the
Page 26 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
appropriate vehicle for TO's to identify clearance variances on Ferderal lands, not
exemption language in the standard. The standard should not be used as a mechanism
by federal agencies to impose variances to proven vegetation management practices and
clearances.
3. Defining Right-of-Way:
Ameren agrees that it is appropriate to further address the definition of “right-of-way”.
Corridor widths beyond design clearance requirements have been acquired for a variety
of reasons in the past; future use, property line buffers, etc. Vegetation in those areas
that would normally fall outside of the area necessary for operation of the facility should
not be considered or treated different than vegetation that is outside of a defined
easement/permit area that is designed for the reliable operation of an existing single line
corridor.
4. IEEE Standard for Minimum Clearances:
Ameren disagrees with objections to the use of the IEEE 516-2003 clearance as the
minimum acceptable distances for “Clearance 2”. The IEEE 516-2003 tables are
appropriate for defining the minimum acceptable clearances to prevent flashover
between conductors and vegetation under all rated electrical operating conditions.
FERC staff references ANSI Z-133 which is a safety standard that addresses worker
safety as well as the safety of the general public. As such, the purpose of ANSI Z-133 is
to address worker safety and is not focused on transmission line reliability, which is the
purpose of FAC-003-1. OSHA, NESC and other related safety standards have clearances
in excess of IEEE 516-2003. Those clearances are clearly focused on safety issues and
will still apply to other aspects of design and operation of electric facilities (such as
public and worker safety) but are not appropriate to be referenced in a vegetation
management reliability standard.
5/6/7.
Procedural Items:
Ameren agrees that the procedural items related to formatting RRO references and
additional compliance elements should be addressed by the standard drafting team.
8. Technical Reference Materials:
Page 27 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
Ameren agrees that a “white paper” that defines the technical basis for the standard is
appropriate to avoid the potential for differences in interpretation of the standard’s
requirements during the various region's audit processes.
9. Category 3 Outages:
Since the right to control off right-of-way vegetation is generally beyond control of the
transmission owner Ameren believes that the reporting of category 3 outages should be
removed from the requirements.
10. Requirement R4:
Ameren believes that requirement R4 should be deleted from the standard, based on the
ERO formation and the process for delegation of authority to the regional entities.
11. Reporting Exemptions:
Ameren believes that the reporting requirement exemptions for natural disasters should
include all categories of outages. It would, for example, be difficult, without delaying
restoration efforts, to determine if the vegetation from high winds, hurricanes,
tornadoes, etc. is from on or off the "right-of-way".
Response:
1. The standard DT will review applicability parameters of this standard, taking into account the comments from
stakeholders such as NU, National Grid, Manitoba Hydro, First Energy, and others.
2. The SAR DT concurs with the commenter with respect to applying this standard to Federal and non-Federal lands. The
standard DT will evaluate the suitability of a case-by-case approach.
3. The standard DT will review the definition of ROW.
4. The SAR DT agrees with the commenter and recognizes that sections of IEEE 516 standard pertaining to minimum air
insulation distances are applicable in determining minimum vegetation clearances to prevent flashovers.
5. NERC standards must be updated to comply with new procedural requirements and must include compliance elements.
6. See #5
7. See #5
8. The SDT shall consider producing a white paper to aid in clarifying the intent of the standard.
9. The SAR indicates that the Standard Drafting Team will review reporting criteria for Category 3 outages and will review
the reporting requirement of Category 3 outages in R.3 and R.4.
Page 28 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes No
Comment
10. The standard DT will consider deletion of R.4.
11. The standard DT will review the reporting exemptions to include all category outages under major disasters in
Requirement R3.2.
Baltimore Gas &
We completely disagree with the proposal to eliminate reporting or off-right-of-way tree
;
Electric
outages. In reality, off-R/W outages can cause many of the same problems that on R/W
outages do if they were to occur at the most inappropriate time. Granted that they
typically do not occur at times of peak load, but they could. Moreover, many off-R/W
tree outages are preventable and should be addressed before they occur.
Response: The SAR indicates that the Standard Drafting Team will review reporting criteria for Category 3 outages and will
review the reporting requirement of Category 3 outages in R.3 and R.4.
CECD
CECD supports continuing to use the 200kV threshold for determining applicability of
vegetation management criteria. If the standard is deemed to apply to lower voltages
these should only be critical lower voltage transmission facilities as determined by the
Regional Entities's. CECD would also encourage the drafting team to clarify that the
Vegetation Management standards are not applicable to generator interconnection
facilities. In the registration process due to the NERC functional definitions, Generation
Owners/Operators are required to register as Transmission Owners/Operators because of
step-up transformers and other associated interconnection equipment that was not
intended to be subject to the Vegetation Management program.
Response: The standard DT will review applicability parameters of this standard, taking into account the comments from
stakeholders such as NU, National Grid, Manitoba Hydro, First Energy, and others.
;
As a registered transmission owner this standard is applicable. Registration matters should be referred to the NERC
organization certification program and the related regional entity.
Central Maine Power
The standard FAC-003-1 is intended to create a frame work that will ensure a uniform
;
level of reliability and at the same time must allow transmission owners to meet this
objective using efficient and cost effective programs. To this end utilities must have the
ability to implement “Clearance 1” distances consistently throughout their service areas.
The standard should remain focused only on 200 KV and above lines or lines listed as
critical by the Regional Entity.
Inspection cycles are sufficient as listed the current version and allow flexibility to meet
local variability in growth rates and other conditions. Concerns with inspection cycle
length can be addressed in the compliance area.
Page 29 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes No
Comment
Response: The SAR DT thanks you for your comments.
The standard DT will review applicability parameters of this standard, taking into account the comments from stakeholders
such as yourself and others.
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693)
and stakeholders indicated they did not support this change, so it was removed from the SAR.
Dominion
In response to Stakeholder item #11, we do not support exempting Category 1 or
;
Category 2 events that occur during natural disasters.
Response: A majority of the industry stakeholder comments support natural disaster exemptions.
Duke Energy
Regarding the Order 693 items, the applicability provision of the standard should focus
;
attention of the standard only on the transmission lines 200kV and above, and those
lines below 200kV that directly impact “Bulk Power System” reliability, as the current
version of FAC-003 requires. Each Regional Entity (RE) must determine applicability of
FAC-003 to those lines within the region that are less than 200kV. For example,
transmission lines below 200kV should be considered within the scope of FAC-003 if they
are identified as operationally significant elements of Interconnection Reliability
Operating Limits (“IROLs”); i.e. an outage of the facility would cause an Interconnection
Reliability Limit Violation.
The Standard DT should address the issue of the necessity of maintaining consistent
clearances for lines on both federal and non-federal lands.
We agree with the use of the IEEE 516-2003 standard for for defining the minimum
acceptable clearances to prevent flashover between conductors and vegetation under all
rated electrical operating conditions.
We believe that the reporting requirement exemptions for natural disasters should
include all categories of outages.
Response: The standard DT will review applicability parameters of this standard, taking into account the comments from
stakeholders such as NU, National Grid, Manitoba Hydro, First Energy, and others.
The SAR DT concurs with the commenter with respect to applying this standard to Federal and non-Federal lands. The
standard DT will evaluate the suitability of a case-by-case approach.
The SAR DT agrees with the commenter and recognizes that sections of IEEE 516 standard pertaining to minimum air
insulation distances are applicable in determining minimum vegetation clearances to prevent flashovers.
Page 30 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes No
Comment
The standard DT will review the reporting exemptions to include all category outages under major disasters in Requirement
R3.2.
Entergy Corp.
The policy to increase sanctions based on a finding of an "intentional economic decision
;
to violate the standard" is ill-concieved:
1. Every transmission line outage that has ever occured could have been avoided if
more money had been spent on SOMETHING, SOMWHERE.
2. No utility has an unlimited budget, so decisions based on risk, cost and benefit are
made every day.
3. After the outage, the localized initiating cause will appear so trivial and inexpensive
that it would seem that it could easily have been fixed in advance.
4. Therefore, reviewers could conclude that EVERY outage (a defacto violation of the
standard), is the result of an "economic decision to violate the standard."
Economic choices are a necessary and natural part of doing business, and do not
necessarily imply the existence of malicious motives or wrong-doing.
The current policy is going to create unnecessary costs to ratepayers, even to avoid
inconsequential outages.
Response: The compliance sanctions guideline addresses the matter of willful noncompliance. Refer to the Compliance
program with respect to this issue. However the standard DT and Compliance Elements DT will review and assign Violation
Severity Levels when modifying FAC-003-1.
FirstEnergy Corp.
The definition of Right-Of-Way requires modification to clarify it is the width required by
;
engineering to operate the line. This may or may not be the legal Right-of-Way. (See
previously submitted comments submitted by FE in Feb 2007 for more details).
Response: The standard DT will review the definition of ROW.
Florida Power & Light ;
For the record FPL re-emphasize its comments from the previous FAC 003-1 SAR.
Requirement 3.2 exempts reporting of outages from outside the ROW when natural
disasters such as tornados or hurricanes occur. Our experience with numerous
hurricanes indicates that all outages during these types of events should be exempt. The
focus in these situations is to get the lines back in service and restore customers. There
is insufficient manpower to adequately complete the forensics necessary to determine an
accurate root cause. It is not uncommon to find vegetation debris in the lines or downed
trees on the ROW in this situation. In most cases it is not possible to determine the
original location of these trees.
Page 31 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
In the compliance section of the document a transmission owner becomes non compliant
with a single category 1 or 2 outage. This occurs regardless of the circumstances. A non
compliant penalty for a single outage in a situation where no customers were affected
and the system could not have been compromised is not reasonable. It is also not an
indicator of a poorly maintained system. We agree that several Category 1 or 2
interruptions could be an indicator of neglect but one is not. We recommend that the
compliance section be reviewed with this in mind.
Response: The SDT will review the reporting exemptions to include all category outages under major disasters in
Requirement R3.2.
The SDT and Compliance Elements DT will review and assign Violation Severity Levels when modifying FAC-003-1. Note that
the levels of non-compliance that are in the approved version of FAC-003 will be replaced with violation severity levels.
HQT
Here are some general comments on the SAR:
;
1.
In the purpose section of the SAR, item 1, we don't understand the substitution of
BPS by «electric transmission system»; it seems like there is a will to make the
Standards applicable to more than the BPS. It is our understanding that NERC Standards
are aimed at the reliability of the BPS. The term BPS should be retained and instead of
modifying the SAR to widen the applicability, the Standard itself should be modified to
specifically used the term BPS in item A.3.
2.
In the detailed description section, item 1, sub-bullet, it is written that: “...the
SDT may consider other criteria in determining applicability of the Standard to sub 200
kV lines...”. We think that in item 4.3 (Applicability) of the existing Standard, there is
already the possibility of applying the Standard to sub 200 kV lines if determined by
RRO. This could be reworded by saying: “...as determined by a methodology to define
BPS element”; such as the one used by NPCC.
3.
We noticed that most Definitions ( e.g. RC, IA, PC, RP, TP, TOP, DP, GO, GOP,
PSE, MO (not even in the Glossary), LSE) used to described the Reliability Functions in
the SAR form, are somewhat different than those used in the Glossary of Terms
approved with the Standards deposited at the FERC. For consistency, if the definition
needs to be changed, this should be done through the right process, not just casually in
the SAR Form.
4.
Also, although the title in that same section of the SAR form refers to Reliability
Functions, these are in fact the Responsible Entity that performs those functions; maybe
a correction in the SAR form would be necessary.
Page 32 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes No
Comment
Response:
1. The SAR DT used ‘Bulk Electric System’ because that is the term defined in the NERC Glossary.
2. The standard DT will review applicability parameters of this standard, taking into account the comments from
stakeholders such as NU, National Grid, Manitoba Hydro, First Energy, and others. Furthermore the standard DT will
ensure that any new terms defined for use in this standard will also be added to the Glossary of Terms.
3. The standard DT will ensure that any new terms defined for use in this standard will also be added to the Glossary of
Terms. the drafting teams were directed to use the definitions for the functional model entities in the version of the
Functional Model just approved by the BOT in February, 2007. The glossary will be updated to include the revised
definitions for the functional entities.
4. Thanks for the comment.
Hydro One Networks
We believe from a transmission system perspective, category 3 outages are no different
;
than many of the other types of outages that take place on the system, such as
hardware failures, lightning damage and station equipment outages to name a few. It is
our understanding that there is no requirement to report these “other” outages, which
makes one wonder why the tree related outages that originate off the right of way need
to be reported. We are not diminishing the importance of category 3 outages, but from
a system cascading perspective, these outages are no more important than other line or
station outages, and are fewer in number than the “other” random outages. To initiate
system cascading as occurred during August 14, 2003, a number of the random outages
would have to coincide to cause a wide spread system event, which in our opinion is a
very low probability occurrence. On the other hand, a category 1 outage can occur as a
result of any system disturbance should there be deficiencies in clearances to vegetation,
as such the importance of category 1 outages is apparent and reporting is appropriate.
We support the review concerning the need to report category 3 outages and that the
ultimate decision should be based on reporting rules that take into consideration the
broader topic of reliability, rather than just vegetation related outages.
Response: The SAR indicates that the Standard Drafting Team will review reporting criteria for Category 3 outages and will
review the reporting requirement of Category 3 outages in R.3 and R.4.
IESO
;
1.
The SAR indicates that a list of critical low voltage transmission lines will be
provided to FERC. We do not interpret Order 693 to direct NERC to provide this list.
Rather, we interpret that FERC asks for defining a criteria that would include low voltage
transmission lines that have impact on Bulk Power System reliability. We do not think
the list is required.
2.
The SAR indicates: “The standard DT may consider other criteria in determining
Page 33 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
applicability of the standard to sub 200kV lines…” Per Order 693, the criteria is quite
clearly stated to be the transmission lines of less than 200 kV that could impact Bulk
Power System reliability. We don't feel any other criteria would be necessary. Further, to
identify the candidates that meet these criteria, we believe they should be determined by
the Reliability Coordinator, similar to the PRC-023 standard, since the RC has the
primary responsibility and knowledge of interconnection reliability impact.
3.
We do not understand why the SDT considers removing Category 3 incidents? In
our view, Category 3 outages are important information for assessing the effectiveness
of vegetation program. Since the industry started reporting vegetation related outages
about 3 years ago, data collected so far indicates that of a total of 98 reported
vegetation outages, 67 of them were category 3 outages. With this high percentage,
reporting of Category 3 events should be a must since the associated trends can provide
valuable information to the TOs to aid its evaluation of the vegetation management
program.
4.
The white paper and field tests are a good idea and the SDT should be
commended for these, especially the white paper.
5. Item 2 under the FERC Order 693 Items in the Detailed Description Section indicates
the SDT will also collection outage data. While we understand that FERC has directed the
ERO to collect outage data for transmission outages of lines that cross both federal and
non-federal lands, we do not feel that it is the SDT's role to perform this task. We feel
that this task should be performed by the ERO line functions or a group separate from
the SDT such that the task does not add burden to the SDT which may slow down the
standard development process or result in the standard development being driven by
unanalyzed data and resulting in erroneous requirements.
6. With respect to reporting exemptions, our position during development of the previous
version of this standard was to limit them. We commend the SDT intention to clarify the
outage exemptions under major disasters, but to consider including all category outage
exemptions in the standard body is too prescriptive and will add to the already extended
list. It can end up with a very long list of outage exemptions, thereby reducing the
coverage of the standard substantially and defeating its purpose
Response:
1. On the basis of the responses from stakeholders to Question #2 above, the SAR DT’s assessment is that further
Page 34 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes No
Comment
specificity may be needed to aid in identifying which <200kV transmission lines should come under the purview of this
standard. The SDT shall take under consideration other applicability parameter criteria, various stakeholder proposals
including IROL violation potential.
2. See # 1 above.
3. The SAR indicates that the Standard Drafting Team will review reporting criteria for Category 3 outages and will review
the reporting requirement of Category 3 outages in R.3 and R.4.
4. The SAR DT thanks you for your comment.
5. The SDT looks to receive the results of the ERO analysis and use it in developing the standard.
6. The SDT will review the reporting exemptions to include all category outages under major disasters in Requirement
R3.2.
IRC SRC
1.
The SAR indicates that a list of critical low voltage transmission lines will be
;
provided to FERC. We do not interpret Order 693 to direct NERC to provide this list.
Rather, we interpret that FERC asks for defining a criteria that would include low voltage
transmission lines that have impact on Bulk Power System reliability. We do not think
the list is required.
2.
The SAR indicates: “The standard DT may consider other criteria in determining
applicability of the standard to sub 200kV lines…” Per Order 693, the criteria is quite
clearly stated to be the transmission lines of less than 200 kV that could impact Bulk
Power System reliability. We don't feel any other criteria would be necessary. Further, to
identify the candidates that meet this criteria, we believe they should be determined by
the Reliability Coordinator, similar to the PRC-023 standard, since the RC has the
primary responsibility and knowledge of interconnection reliability impact.
3.
We do not understand why the SDT considers removing Category 3 incidents? In
our view, Category 3 outages are important information for assessing the effectiveness
of vegetation program. Since the industry started reporting vegetation related outages
about 3 years ago, data collected so far indicates that of a total of 98 reported
vegetation outages, 67 of them were category 3 outages. With this high percentage,
reporting of Category 3 events should be a must since the associated trends can provide
valuable information to the TOs to aid its evaluation of the vegetation management
program.
4.
The white paper and field tests are a good idea and the SDT should be
commended for these, especially the white paper.
Page 35 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
5. Item 2 under the FERC Order 693 Items in the Detailed Description Section indicates
the SDT will also collect outage data. While we understand that FERC has directed the
ERO to collect outage data for transmission outages of lines that cross both federal and
non-federal lands, we do not feel that it is the SDT's role to perform this task. We feel
that this task should be performed by the ERO or a group separate from the SDT such
that the task does not add burden to the SDT which may slow down the standard
development process or result in the standard development being driven by unanalyzed
data and resulting in erroneous requirements.
6. With respect to reporting exemptions, our position during development of the
previous version of this standard was to limit them. We commend the SDT intention to
clarify the outage exemptions under major disasters, but to consider including all
category outage exemptions in the standard body is too prescriptive and will add to the
already extended list. It can end up with a very long list of outage exemptions, thereby
reducing the coverage of the standard substantively and defeating its purpose. If this list
was to be developed, they could be attached as guidelines aside of the standard.
7. The SAR DT states it will deal with "critical facilities" . The SRC suggest that the DT
not use the word "critical" and adopt another term.
There is a need to define in a single standard what the term "critical" means. Standards
FAC-014 (R5.1.1); IRO-002-1 (R6) and others use the term "critical" as in: critical loads,
critical infrastructure, critical assets. The Veg Management Team is asked to avoid
making the current situation worse.
Response:
1. On the basis of the responses from stakeholders to Question #2 above, the SAR DT’s assessment is that further
specificity may be needed to aid in identifying which <200kV transmission lines should come under the purview of this
standard. The SDT shall take under consideration other applicability parameter criteria, various stakeholder proposals
including IROL violation potential.
2. The FERC Order includes the following language which indicates that FERC would support inclusion of any circuit below
200 kV that was subject to an IROL and the SAR has been written to allow this modification..
3. The SAR indicates that the Standard Drafting Team will review reporting criteria for Category 3 outages and will review
the reporting requirement of Category 3 outages in R.3 and R.4.
4. The SDT shall consider producing a white paper to aid in clarifying the intent of the standard, however a field test is
not contemplated at this time.
5. The SAR was revised to clarify that it is the ERO that will collect data and the Standard DT will receive the results of
Page 36 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes No
Comment
the ERO analysis and use it in developing the standard.
6. The standard DT will review the reporting exemptions to include all category outages under major disasters in
Requirement R3.2.
7. The FERC Order includes the following language which indicates that FERC would support inclusion of any circuit below
200 kV that was subject to an IROL and the SAR has been written to allow this modification.
ISO-NE
1.
The SAR indicates that a list of critical low voltage transmission lines will be
;
provided to FERC. We do not interpret Order 693 to direct NERC to provide this list.
Rather, we interpret that FERC asks for defining a criteria that would include low voltage
transmission lines that have impact on Bulk Power System reliability. We do not think
the list is required.
2.
The SAR indicates: “The standard DT may consider other criteria in determining
applicability of the standard to sub 200 kV lines…” Per Order 693, the criteria is quite
clearly stated to be the transmission lines of less than 200 kV that could impact Bulk
Power System reliability. We don't feel any other criteria would be necessary. Further, to
identify the candidates that meet this criteria, we believe they should be determined by
the Reliability Coordinator, similar to the PRC-023 standard, since the RC has the
primary responsibility and knowledge of interconnection reliability impact.
3.
We do not understand why the SDT considers removing Category 3 incidents. In
our view, Category 3 outages are important information for assessing the effectiveness
of a vegetation program. Since the industry started reporting vegetation-related outages
about 3 years ago, data collected so far indicates that of a total of 98 reported
vegetation outages, 67 of them were category 3 outages. With this high percentage,
reporting of Category 3 events should be a must since the associated trends can provide
valuable information to the TOs to aid its evaluation of the vegetation management
program.
4.
The white paper and field tests are a good idea and the SDT should be
commended for these, especially the white paper.
5. Item 2 under the FERC Order 693 Items in the Detailed Description Section indicates
the SDT will also collect outage data. While we understand that FERC has directed the
ERO to collect outage data for transmission outages of lines that cross both federal and
non-federal lands, we do not feel that it is the SDT's role to perform this task. We feel
that this task should be performed by the ERO or a group separate from the SDT such
Page 37 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
that the task does not add burden to the SDT which may slow down the standard
development process or result in the standard development being driven by unanalyzed
data and resulting in erroneous requirements.
6. With respect to reporting exemptions, our position during development of the previous
version of this standard was to limit them. We commend the SDT's intention to clarify
the outage exemptions under major disasters, but to consider including all category
outage exemptions in the standard body is too prescriptive and will add to the already
extended list. It can end up with a very long list of outage exemptions, thereby reducing
the coverage of the standard substantively and defeating its purpose. If this list was to
be developed, they could be attached as guidelines aside of the standard.
7. The SAR DT states it will deal with "critical facilities.” The SRC suggest that the DT not
use the word "critical" and adopt another term.
There is a need to define in a single standard what the term critical means. Standards
FAC-014 (R5.1.1); IRO-002-1 (R6) and others use the term "critical" as in: critical loads,
critical infrastructure, critical assets. This Team is asked to avoid making the current
situation worse.
Response:
1. On the basis of the responses from stakeholders to Question #2 above, the SAR DT’s assessment is that further
specificity may be needed to aid in identifying which <200kV transmission lines should come under the purview of this
standard. The SDT shall take under consideration other applicability parameter criteria, various stakeholder proposals
including IROL violation potential.
2. The FERC Order includes the following language which indicates that FERC would support inclusion of any circuit below
200 kV that was subject to an IROL and the SAR has been written to allow this modification..
3. The Standard Drafting Team intends to review reporting criteria for Category 3 outages in the proposed technical
reference material and may review the reporting requirement of Category 3 outages in R.3 and R.4.
4. The SDT shall consider producing a white paper to aid in clarifying the intent of the standard, however a field test is
not contemplated at this time.
5. The standard DT looks to receive the results of the ERO analysis and use it in developing the standard.
6. The standard DT will review the reporting exemptions to include all category outages under major disasters in
Requirement R3.2.
7. The FERC Order includes the following language which indicates that FERC would support inclusion of any circuit below
200 kV that was subject to an IROL and the SAR has been written to allow this modification.
Page 38 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
MRO
Yes
;
No
Comment
If the Regional Reliability Organization is removed as an applicable entity, what is the
Regional Entity’s responsible? How will a general consensus be formed? How do you
get people to participate in this formation?
For good planning and application of standards, methodologies need to be consistently
applied through guidelines to the drafting teams.
Specifically, this standard should provide consistent methodology that provides guidance
to the transmission owner.
In the next revision of the standard, the MRO requests that more authority be given to
the applicable entities with respect to the latitude allowed them in removing trees to the
legal limits of their agreement.
The MRO commends FERC on empowering NERC and the SAR DT via their Order 693 to
revisit the issue of clearances for lines on both Federal and non-Federal Lands. It has
come to the attention of the MRO that Federal Forest Employees as well as BLM
employees have begun the practice of chemically treating noxious weeds and invasive
species on Federal Lands. he MRO would like to have FERC, NERC, and the Standard DT
consider meeting with Federal Land Managers to discuss, on a National Level, the issue
of herbicide application by utilities on Federal Lands. At the present time there are
inconsistencies regionally on this issue that allow application in some regions but not in
others.
Response:
1. The term RRO is no longer in use and RE (or regional entity) is now the preferred term for the former Regional
Reliability Organizations. The term RE is defined in the delegation agreements between these organizations and the
ERO.
2. Such a guideline exists and is available on the NERC website entitled “Standard Drafting Team Guidelines”.
3. See answer #2 above.
4. The removal of trees within the limits stated in agreements is outside the scope of this standard.
5. The coordination of the use of herbicides is outside the scope of this standard.
National Grid
1) National Grid supports amending FAC-003-1 to bring the Standard into compliance
;
with "latest version of the Reliability Standard Development Procedure and the ERO
Sanctions Guidelines" as discussed in the SAR Background Information.
2) We do not support amendments to the Standard to address all of the issues raised by
FERC Order 693. We believe most of the FERC's concerns can be addressed by
Page 39 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
developing a "white paper" to better explain the Standard and guide its implementation.
3) National Grid does not support changing the basic approach to defining clearance from
vegetation. The clearance 1 and clearance 2 concept adopts the two management
approaches used by most TO's today and required in some state or ISO level standards.
National Grid supports using the reference to IEEE 516 as the basis for clearance 2 for
two reasons: 1 - there is no other definitive reference for flash over distances to
vegetation and 2- decades of experience by TO's acrosss the North America suggest the
IEEE 516 distances are more than adequate. The well known tree caused outages in
1996 and 2003 occurred as a result of hard contact with vegetation not flashover at
distances close to those in IEEE 516. Furthermore, FERC accepted IEEE 516 as
appropriate for use in vegetation management in the October 2006, NOPR.
4) National Grid supports amending the definition of a right-of-way though we are not
clear on what is meant in the SAR language by "to encompass required clearing areas".
National Grid is concerned with the interpretation of the present definition that the rightof-way includes uncleared fee owned or easement land reserved for future construction.
In many jurisdictions the TO may not be allowed to remove trees from these areas. A
"white paper" could better describe the definition and prevent future compliance issues
stemming from an ambiguous definition.
Response:
1. The SAR DT thanks you for your comment.
2. The SAR indicates that the SDT will produce a technical white paper to clarify intent of the standard.
3. The SAR DT agrees with the commenter not to change the basic approach and recognizes that sections of IEEE 516
standard pertaining to minimum air insulation distances are applicable in determining minimum vegetation clearances
to prevent flashovers.
4. The Standard DT will review the definition of ROW. See also answer #2 above.
Northeast Utilities
NU does not support the proposed revisions based on the issues raised by FERC Order
;
693. The Standard has not been in effect long enough to determine if there are any
shortcomings with the current requirements. It is our position that the current clearance
requirements are satisfactory in that a base minimum distance as provided under IEEE
Section 516 is sufficient and there is the need for variations in the second level of
clearances base on Regional needs and conditions.
The revisions to the definition of "right-of-way" to encompass required clearance areas
can e problematic as this could cause significant problems with current systems. There
is no detailed description on what the new definition will include or what the actual
impact will be to TO's. If the definition will include defined limits or widths of rights-of-
Page 40 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
way this may affect current facilities that do not meet these distances. Second, there
are areas where the company owns or possesses additional area beyond the current
maintained right-of-way widths. Is it proposed that the new definition expand the limits
of clearing or maintenance to include easemented or fee-owned areas beyond the
current maintained limits? Until the new definition can be presented - it is difficult to
support any changes at this time and we can only comment on the perceived negative
impacts.
Response: The SDT will review the standard to address the Commission’s determinations. The standard DT will review the
definition of ROW. Note that the ERO is required to respond to the FERC directives.
NYISO
1.
The SAR indicates that a list of critical low voltage transmission lines will be
;
provided to FERC. We do not interpret Order 693 to direct NERC to provide this list.
Rather, we interpret that FERC asks for defining a criteria that would include low voltage
transmission lines that have impact on Bulk Power System reliability. We do not think
the list is required.
2.
The SAR indicates: “The standard DT may consider other criteria in determining
applicability of the standard to sub 200kV lines…” Per Order 693, the criteria is quite
clearly stated to be the transmission lines of less than 200 kV that could impact Bulk
Power System reliability. We don't feel any other criteria would be necessary. Further, to
identify the candidates that meet this criteria, we believe they should be determined by
the Reliability Coordinator, similar to the PRC-023 standard, since the RC has the
primary responsibility and knowledge of interconnection reliability impact.
3.
We do not understand why the SDT considers removing Category 3 incidents? In
our view, Category 3 outages are important information for assessing the effectiveness
of vegetation program. Since the industry started reporting vegetation related outages
about 3 years ago, data collected so far indicates that of a total of 98 reported
vegetation outages, 67 of them were category 3 outages. With this high percentage,
reporting of Category 3 events should be a must since the associated trends can provide
valuable information to the TOs to aid its evaluation of the vegetation management
program.
4.
The white paper and field tests are a good idea and the SDT should be
commended for these, especially the white paper.
5. Item 2 under the FERC Order 693 Items in the Detailed Description Section indicates
Page 41 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
the SDT will also collect outage data. While we understand that FERC has directed the
ERO to collect outage data for transmission outages of lines that cross both federal and
non-federal lands, we do not feel that it is the SDT's role to perform this task. We feel
that this task should be performed by the ERO or a group separate from the SDT such
that the task does not add burden to the SDT which may slow down the standard
development process or result in the standard development being driven by unanalyzed
data and resulting in erroneous requirements.
6. With respect to reporting exemptions, our position during development of the previous
version of this standard was to limit them. We commend the SDT intention to clarify the
outage exemptions under major disasters, but to consider including all category outage
exemptions in the standard body is too prescriptive and will add to the already extended
list. It can end up with a very long list of outage exemptions, thereby reducing the
coverage of the standard substantively and defeating its purpose. If this list was to be
developed, they could be attached as guidelines aside of the standard.
Response:
1. On the basis of the responses from stakeholders to Question #2 above, the SAR DT’s assessment is that further
specificity may be needed to aid in identifying which <200kV transmission lines should come under the purview of this
standard. The SDT shall take under consideration other applicability parameter criteria, various stakeholder proposals
including IROL violation potential..
2. The FERC Order includes the following language which indicates that FERC would support inclusion of any circuit below
200 kV that was subject to an IROL and the SAR has been written to allow this modification..
3. The Standard Drafting Team intends to review reporting criteria for Category 3 outages in the proposed technical
reference material and may review the reporting requirement of Category 3 outages in R.3 and R.4.
4. The SAR indicates that the SDT will produce a white paper to aid in clarifying the intent of the standard, however a
field test is not contemplated at this time.
5. The SDT looks to receive the results of the ERO analysis and use it in developing the standard.
6. The SDT will review the reporting exemptions to include all category outages under major disasters in Requirement
R3.2.
PGE
1) Applicability 4.3 of the standard - PG&E believes the RE is in the best position to
;
determine sub-200kV facilities are designated critical and covered under FAC-003-1. We
suggest the ERO direct the RE to provide a list of sub-200kV lines designated critical
along with methodology used to make that determination.
2) Clearances for lines on federal and non-federal lands - PG&E believes there should be
no distinction between requirements on different lands. Vegetation encroachments have
Page 42 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
the same impact regardless of land ownership.
3) Definition of right of way - agreed
4) Suitability of IEEE 516-2003 - PG&E believes the use of IEEE 516 as the standard for
clearance requirements are adequate to ensure transmission system reliability provided
the TO has an appropriate methodology for determining clearance at time of trim and an
adequate cycle to prevent vegetation from encroaching within minimum distances. Use
of ANSI Z133.3 or FedOSHA 1910, as suggested by FERC, is not appropriate as it is
intended for worker safety and not system reliability. TO compliance with R1.2 of the
standard should address concerns FERC has with maintaining minimum clearance.
5-7) Procedural items - No comment
8) Preparation of technical manual (white paper) - agreed
9) PG&E believes the current reporting requirements under R3 of the standard should be
revised. Distinction is placed on fall-in's "in and out of the ROW" and may not be the
best method for determining severity for reporting purposes. PG&E believes a better
distinction is (a) green/healthy/no obvious decline and (b) dead or obvious signs of
disease, decay or decline. A key component of any TMVP should be hazard tree
mitigation regardless if in or out of the ROW. Suggested categories:
Category 1 - Any grow-in (as currently stated).
Category 2 - Any fall-in of a dead tree or one with obvious signs of disease, decay or
decline in or out of the ROW.
Category 3 - Either eliminate this category or specify healthy green tree or tree with no
obvious signs of decline (if retained, be specific about this being for reporting purposes
only)
PG&E recognizes that tree failures, even if dead or diseased, are not necessarily an
indicator of problematic VM program and the severity level should be reflected as such.
Tree density along with other factors make 100% identification not possible. However,
multiple occurrences could be an indicator of substandard performance and the current
standard does remains silent in respect to hazard trees other than if in or out of the
ROW.
Response:
Page 43 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes No
Comment
1. On the basis of the responses from stakeholders to Question #2 above, the SAR DT’s assessment is that further
specificity may be needed to aid in identifying which <200kV transmission lines should come under the purview of this
standard. The SDT shall take under consideration other applicability parameter criteria, various stakeholder proposals
including IROL violation potential..
2. The SAR DT concurs with the commenter with respect to applying this standard to Federal and non-Federal lands. The
standard DT will evaluate the suitability of a case-by-case approach.
3. The standard DT will review the definition of ROW.
4. The SAR DT agrees with the commenter and recognizes that sections of IEEE 516 standard pertaining to minimum air
insulation distances are applicable in determining minimum vegetation clearances to prevent flashovers.
5. n/a
6. n/a
7. n/a
8. The SAR indicates that the SDT will produce a technical white paper to clarify intent of the standard.
9. The SAR indicates that the SDT will review reporting criteria for Category 3 outages and will review the reporting
requirement of Category 3 outages in R.3 and R.4. The SDT and Compliance Elements DT will review and assign
Violation Severity Levels when modifying FAC-003-1.
PGN
Progress Energy Carolinas (PEC) and Progress Energy Florida (PEF) do not agree that
;
each of 11 items listed in the SAR are necessary to improve reliability. The following
comments are offered for each of the 11 items identified in the SAR detail description:
1. Standard Applicability:
PEC and PEF believe that the current standard wording for determining facilities subject
to this standard should not be revised. The standard as it is written provides for lines
below 200kV, that are determined to impact the grid, to be subject to the standard.
Extending the requirements to a bright line below 200kV, such as 100kV, will dilute the
focus on those lines that impact grid reliability, lines >200kV, and shift attention to
facilities, those <200kV, that do not necessarily impact grid reliability. Customer
reliability is an issue that impacts customer satisfaction and is generally driven by state
utility commissions. While some facilities above 200kV directly support customer load,
transmission lines below 200kV primarily support customer load, and interruptions to
those facilities generally reduce load on the grid.
The majority of transmission facilities below 200 kV also have significantly different
design/construction/operating characteristics and have not been cited as impacting bulk
Page 44 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
power system reliability. For example, the Final Report on the August 14, 2003 Blackout
in the United states and Canada: Causes and Recommendations April 2004 by the U.S.Canada Power System Outage Task Force and all referenced major blackouts (pages
103-115) in that report, cited only outages which involved vegetation at line voltages
above 200kV. Generally applying requirements that are appropriate for >200kV lines to
lines less than 200kV will result in significant documentation and reporting of items such
as restrictions, mitigation plans, off right-of-way vegetation-related outage investigation/
information and other issues, all of which dilutes the focus on lines that directly impact
bulk power system reliability.
Revising the standard to use general criteria or broad language for defining "Bulk Power
System" transmission lines covered by the standard is a “one size fits all” approach. If
that approach were taken, the standard would cover a significant number of transmission
lines that have no direct impact on bulk power system reliability under standard
planning/operating conditions, resulting in a significant cost burden for electric
customers without improving “grid” reliability. PEC and PEF believe that the applicability
provision of the standard should instead focus attention of the standard only on the
transmission lines below 200kV that directly impact “Bulk Power System” reliability, as
the current version requires.
While PEC and PEF recognize some validity in the Commission’s concern, PEC and PEF
recommend that the applicability provision of this standard should be revised only if
existing system design, planning or operating reliability criteria and parameters are
considered as a basis for defining the applicability of the standard. To that end, PEC and
PEF recommend each Regional Entity (RE) determine applicability of FAC-003 to those
lines within the region that are between 100kV and 200KV, if, and only if, they are
identified as operationally significant elements of Interconnection Reliability Operating
Limits (“IROLs”). That is, any facility below 200kV that, by itself, would cause an
Interconnected Reliability Limit Violation should the facility be outaged.
2. Issue of Clearances (Federal vs Non-Federal Lands):
FAC-003-1 presently requires the transmission owner (TO) “identify and document
clearances between vegetation and any overhead, ungrounded supply conductors, taking
into consideration transmission line voltage, the effects of ambient temperature on
conductor sag under maximum design loading, and the effects of wind velocities on
Page 45 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
conductor sway.” The intent of this requirement is to ensure adequate clearances to
prevent vegetation related outages. PEC and PEF believe that only the TO has the
technical information required to determine the clearances that are necessary at the time
of VM work and that any “federal lands exemption” to clearances will result in inadequate
clearances for the existing conditions. Consistency in application of the TO’s clearance
requirements, not exceptions, is the only assurance in providing a uniform and reliable
electrical system to meet the nation’s current and future energy demands.
Any exception for a case by case clearance approach to determine vegetation
management activities/clearances on Federal lands will continue to drive inconsistency
and/or delays associated with TO vegetation management decisions being driven by
diverse vegetation management practices/beliefs and staff changes at the local level of
Federal agencies. Vegetation-related outages have occurred on Federal lands as a result
of this case by case approach, and if “Bulk Power Transmission System” lines continue to
be addressed on a “case by case” basis on National Forest Service (or any other Federal
lands), those lines will potentially be subject to a higher risk for vegetation-related
outages, resulting in reduced reliability for the “Bulk Power System”.
PEC and PEF believe that reliability of the “Bulk Power System” should have the same
focus on Federal and private lands and that the EEI MOU with federal agencies is an
appropriate avenue for TO's to identify clearances on Federal lands, not an exemption in
the language of a reliability standard.
3. Defining Right-of-Way:
PEC and PEF agree that it is appropriate to further address the definition of “right-ofway”. Corridor widths that exceed the design clearance requirements have been
acquired for a variety of reasons in the past; future use, property line buffers, etc.
Vegetation in those areas that would normally be outside of the corridor width necessary
for reliable operation of the facility, but within an expanded easement area, should not
be considered, or treated, different than vegetation that is outside of a defined
easement/permit right-of-way corridor that was designed and acquired specifically for
the reliable operation of a single line.
4. IEEE Standard for Minimum Clearances:
Page 46 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
PEC and PEF believe that the IEEE 516-2003 tables are appropriate for defining the
minimum acceptable clearances to prevent flashover between conductors and vegetation
under all rated electrical operating conditions. Closer minimum clearances such as the
minimum length of a support insulator could have been adopted as a “lowest common
denominator” clearance. However the clearance in IEEE 516-2003 was adopted to ensure
an additional margin of reliability. FERC staff has made references to the use of ANSI Z133 which is a safety standard that addresses worker safety as well as the safety of the
general public. The purpose of ANSI Z-133 is to address worker safety and is not focused
on transmission line reliability, which is the purpose of FAC-003-1. OSHA, NESC and
other related safety standards have clearances in excess of IEEE 516-2003. Those
clearances are clearly focused on safety issues and will still apply to other aspects of
design and operation of electric facilities (such as public and worker safety) but are not
appropriate to be referenced in a vegetation management reliability standard as a
flashover clearance.
5/6/7.
Procedural Items:
PEC and PEF agree that the procedural items related to formatting RRO references and
revising the compliance elements to meet the new standard format should be addressed
by the standard drafting team.
8. Technical Reference Materials:
PEC and PEF agree that a “white paper” that defines the technical basis for the standard
is appropriate. This type of document, if crafted by the drafting team, should help to
avoid the potential for differences in interpretation of the standard’s requirements by the
various regions during the audit process.
9. Category 3 Outages:
Since control off right-of-way vegetation is generally beyond control of the TO and since
"fall-in" outages are random events that do not threaten grid reliability, PEC and PEF
believe that the reporting of category 3 outages should be removed from the
requirements.
10. Requirement R4:
Page 47 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
PEC and PEF believe that requirement R4 should be deleted from the standard, since the
ERO formation provides for delegation of authority to the regional entities.
11. Reporting Exemptions:
PEC and PEF believe that the reporting requirement exemptions for natural disasters
should include all categories of outages. For example, with outages caused by high
winds, hurricanes, tornadoes, etc., it would be difficult (or practically impossible in some
cases) to determine if the vegetation came from on, or off, the "right-of-way". In
addition, the effort and time necessary to make that determination would result in
delaying outage restoration efforts.
Response:
1. On the basis of the responses from stakeholders to Question #2 above, the SAR DT’s assessment is that further
specificity may be needed to aid in identifying which <200kV transmission lines should come under the purview of this
standard. The SDT shall take under consideration other applicability parameter criteria, various stakeholder proposals
including IROL violation potential..
2. The SAR DT concurs with the commenter with respect to applying this standard to Federal and non-Federal lands. The
standard DT will evaluate the suitability of a case-by-case approach.
3. The standard DT will review the definition of ROW.
4. The SAR DT agrees with the commenter and recognizes that sections of IEEE 516 standard pertaining to minimum air
insulation distances are applicable in determining minimum vegetation clearances to prevent flashovers.
5. NERC standards must be updated to comply with new procedural requirements and must include compliance elements.
6. See #5
7. See #5
8. The SAR indicates that the SDT will produce a technical white paper to clarify intent of the standard.
9. The SAR indicates that the SDT will review reporting criteria for Category 3 outages and will review the reporting
requirement of Category 3 outages in R.3 and R.4.
10. The standard DT will consider deletion of R.4.
11. The standard DT will review the reporting exemptions to include all category outages under major disasters in
Requirement R3.2.
SERC VMS
The SERC VMS does not agree that each of 11 items listed in the SAR are necessary to
;
improve reliability. The following comments are offered for each of the 11 items
identified in the SAR detail description:
1. Standard Applicability:
Page 48 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
The SERC VMS disagrees with revising the 200 kV threshold for determining facilities
subject to this standard. Extending the requirements to lines other than those >200kV
will dilute the focus on those lines that impact grid reliability and shift attention to
facilities, those <200kV. The reliability of lower voltage lines involves local customers'
reliability and satisfaction hence that reliability should be addressed by local and state
utility commissions. The majority of the >200kV lines are solely elements of the grid
and and interruptions to those lines negatively impact grid reliability. The majority of the
<200kV lines primarily support customer load, and interruptions to those facilities
actually reduces load on the grid.
The majority of transmission facilities below 200 kV also have significantly different
design/construction/operating characteristics and have not been cited as impacting bulk
power system reliability. For example, the Final Report on the August 14, 2003 Blackout
in the United states and Canada: Causes and Recommendations April 2004 by the U.S.Canada Power System Outage Task Force and all referenced major blackouts (pages
103-115) in that report, cited only outages which involved vegetation at line voltages
above 200kV. Generally applying requirements that are appropriate for >200kV lines to
lines less than 200kV will result in significant documentation and reporting of items such
as restrictions, mitigation plans, off right-of-way vegetation-related outage investigation/
information and other issues, all of which dilutes the focus on lines that directly impact
bulk power system reliability.
Revising the standard to use general criteria or broad language for defining "Bulk Power
System" transmission lines covered by the standard is a “one size fits all” approach. If
that approach were taken, the standard would cover a significant number of transmission
lines that have no direct impact on bulk power system reliability under standard
planning/operating conditions, resulting in a significant cost burden for electric
customers without improving “grid” reliability. The SERC VMS believes that the
applicability provision of the standard should instead focus attention of the standard only
on the transmission lines below 200kV that directly impact “Bulk Power System”
reliability, as the current version requires.
In sum, while the SERC VMS recognizes some validity in the Commission’s concern, the
SERC VMS recommends that the applicability provision of this standard should be revised
only if existing system design, planning or operating reliability criteria and parameters
Page 49 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
are considered as a basis for defining the applicability of the standard. To that end, the
SERC VMS recommends each Regional Entity (RE) determine applicability of FAC-003 to
those lines within the region that are between 100kV and 200KV, if, and only if, they are
identified as operationally significant elements of Interconnection Reliability Operating
Limits (“IROLs”). That is, any facility below 200kV that by itself would cause an
Interconnected Reliability Limit Violation should the facility
be outaged.
2. Issue of Clearances (Federal vs Non-Federal Lands):
FAC-003-1 presently requires the transmission owner (TO) “identify and document
clearances between vegetation and any overhead, ungrounded supply conductors, taking
into consideration transmission line voltage, the effects of ambient temperature on
conductor sag under maximum design loading, and the effects of wind velocities on
conductor sway.” The intent of this requirement is to ensure adequate clearances to
prevent vegetation related outages. The SERC VMS believes that only the TO has the
technical information required to determine the clearances that are necessary at the time
of VM work and that any “federal lands exemption” to clearances will result in inadequate
clearances for the existing conditions. Consistency in application of the TO’s clearance
requirements, not exceptions, is the only assurance in providing a uniform and reliable
electrical system to meet the nation’s current and future energy demands.
Any exception for a case by case clearance approach to determine vegetation
management activities/clearances on Federal lands will continue to drive inconsistency
and/or delays associated with TO vegetation management decisions being driven by
diverse vegetation management practices/beliefs and staff changes at the local level of
Federal agencies. Vegetation-related outages have occurred on Federal lands as a result
of this case by case approach, and if “Bulk Power Transmission System” lines continue to
be addressed on a “case by case” basis on National Forest Service (or any other Federal
lands), those lines will potentially be subject to a higher risk for vegetation-related
outages, resulting in reduced reliability for the “Bulk Power System”.
The SERC VMS believes that reliability of the “Bulk Power System” should have the same
focus on Federal and private lands and that the EEI MOU with federal agencies is the
appropriate vehicle for TO's to identify clearance variances on Ferderal lands, not
exemption language in the standard.
Page 50 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
3. Defining Right-of-Way:
The SERC VMS agrees that it is appropriate to further address the definition of “right-ofway”. Corridor widths beyond design clearance requirements have been acquired for a
variety of reasons in the past; future use, property line buffers, etc. Vegetation in those
areas that would normally fall outside of the area necessary for operation of the facility
should not be considered or treated different than vegetation that is outside of a defined
easement/permit area that is designed for the reliable operation of an existing single line
corridor.
4. IEEE Standard for Minimum Clearances:
The SERC VMS disagrees with objections to the use of the IEEE 516-2003 clearance as
the minimum acceptable distances for “Clearance 2”. The IEEE 516-2003 tables are
appropriate for defining the minimum acceptable clearances to prevent flashover
between conductors and vegetation under all rated electrical operating conditions.
Closer minimum clearances such as the minimum length of a support insulator could
have been adopted as a “lowest common denominator” clearance. However the
clearance in IEEE 516-2003 was adopted to ensure an additional margin of reliability.
FERC staff references ANSI Z-133 which is a safety standard that addresses worker
safety as well as the safety of the general public. As such, the purpose of ANSI Z-133 is
to address worker safety and is not focused on transmission line reliability, which is the
purpose of FAC-003-1. OSHA, NESC and other related safety standards have clearances
in excess of IEEE 516-2003. Those clearances are clearly focused on safety issues and
will still apply to other aspects of design and operation of electric facilities (such as public
and worker safety) but are not appropriate to be referenced in a vegetation management
reliability standard.
5/6/7.
Procedural Items:
The SERC VMS agrees that the procedural items related to formatting RRO references
and additional compliance elements should be addressed by the standard drafting team.
8. Technical Reference Materials:
The SERC VMS agrees that a “white paper” that defines the technical basis for the
Page 51 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
standard is appropriate to avoid the potential for differences in interpretation of the
standard’s requirements during the various region's audit processes.
9. Category 3 Outages:
Since the right to control off right-of-way vegetation is generally beyond control of the
TO, the SERC VMS believes that the reporting of category 3 outages should be removed
from the requirements.
10. Requirement R4:
The SERC VMS believes that requirement R4 should be deleted from the standard, based
on the ERO formation and the process for delegation of authority to the regional entities.
11. Reporting Exemptions:
The SERC VMS believes that the reporting requirement exemptions for natural disasters
should include all categories of outages. It would, for example, be difficult, without
delaying restoration efforts, to determine if the vegetation from high winds, hurricanes,
tornadoes, etc. is from on or off the "right-of-way".
Response:
1. On the basis of the responses from stakeholders to Question #2 above, the SAR DT’s assessment is that further
specificity may be needed to aid in identifying which <200kV transmission lines should come under the purview of this
standard. The SDT shall take under consideration other applicability parameter criteria, various stakeholder proposals
including IROL violation potential..
2. The SAR DT concurs with the commenter with respect to applying this standard to Federal and non-Federal lands. The
standard DT will evaluate the suitability of a case-by-case approach.
3. The standard DT will review the definition of ROW.
4. The SAR DT agrees with the commenter and recognizes that sections of IEEE 516 standard pertaining to minimum air
insulation distances are applicable in determining minimum vegetation clearances to prevent flashovers.
5. NERC standards must be updated to comply with new procedural requirements and must include compliance elements.
6. See #5
7. See #5
8. The SAR indicates that the SDT will produce a technical white paper to clarify intent of the standard.
9. The SAR indicates that the SDT will review reporting criteria for Category 3 outages and will review the reporting
requirement of Category 3 outages in R.3 and R.4.
Page 52 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes No
Comment
10. The standard DT will consider deletion of R.4.
11. The standard DT will review the reporting exemptions to include all category outages under major disasters in
Requirement R3.2.
TVA
We feel that the reporting of Category 3 outages should be eliminated.
;
We agree with the need for a "white paper" to expand on definitions and intent. We feel
that a defined maintainable width of right of way is more appropriate than the actual
easement widths because easement widhts are not purchased or operated exclusively
with or for vegetation manitenance activies. We will be pleased to share greater details
on this concern if requested.
Response: The SAR DT thanks you for your comments.
VELCO
;
Page 53 of 53
June 22, 2007
Consideration of Comments on 1st Draft FAC-003-2 Vegetation
Management SDT — Project 2007-07
The Vegetation Management Standard Drafting Team (VM SDT) thanks all commenters who
submitted comments on the 1st draft of FAC-003-2 — Transmission Vegetation Management
Program standard. This standard was posted for a 30-day public comment period from
October 27, 2008 through November 25, 2008. Stakeholders were asked to provide
feedback on the standard through a special Standard Comment Form. There were more
than 60 sets of comments, including comments from more than 100 different people from
over 60 companies representing each of the 10 Industry Segments as shown in the table on
the following pages.
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
Key differences between first posting and second posting of proposed FAC-003 -2 include:
Replaced the CCZ concept found in R4 with a practical field measurement to
address commenter’s concerns.
Eliminated the CCZ as the trigger of imminent threat in R2 to address
commenter’s concerns.
Added a sub part to the TVMP (1.6) in order to address commenter’s concerns
regarding the elimination of Clearance 1. This change requires that the TO
account for anticipated conductor movement.
Developed VRF’s and VSL’s consistent with the NERC Drafting Team Guidelines.
Created a second grow-in outage requirement to allow for different VRF levels
based on the actual criticality of the line.
There were 3 strong minority views not resolved:
Some commenters disagreed with the “zero tolerance” nature of the existing inforce standard.
Some commenters disagreed with a minimum Vegetation Inspection frequency of
one year.
Some commenters want to retain Clearance 1 that is in the existing in-force
standard.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Gerry Adamski, at 609-452-8060 or at [email protected]. In addition, there is a
NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
September 8, 2009
1
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management
Program — Project 2007-07
Index to Questions, Comments, and Responses
1.
In the Purpose Statement the term “electric transmission systems” was changed to
Bulk Electric System, and the Purpose statement was shortened by moving the
various explanatory objectives to other locations in the revised Standard. Do you
agree with the purpose statement? If not, please explain. ......................................13
2.
The Reliability Coordinator was chosen as the proper entity to identify sub-200kV
transmission lines to be subject to this standard (see applicability, R9, and R10). Do
you agree with this choice? If not, please explain. ................................................24
3.
In R1 the proposed standard replaces “prepare, and keep current” with “have”,
replaces the list of terms, “objectives, practices, approved procedures, and work
specifications,” with “designed to control vegetation”, defines the “active
transmission line ROW”, and specifies that the transmission vegetation management
program applies to that area. Do you agree with R1? If not, please explain.............36
4.
Documentation and implementation of the transmission vegetation management
program which were previously combined in Requirement R1 are now separated in
order to apply appropriate VRFs and time horizons. The implementation of some
elements has been moved into standalone requirements such as inspection cycles
(R3) and annual plan implementation (R9). Do you agree with these revisions and
separation? If not, please explain. .....................................................................51
5.
In R1.2 the Transmission Owner is required to have an inspection frequency of at
least once per calendar year. Do you agree with R1.2? If not, please explain. .........59
6.
In R1.3 the Standard requires that transmission vegetation management program
specify an Annual Plan and specifies parameters for the plan. Implementation of the
Annual Plan is separated and placed in R9. Do you agree with R1.3 and the
separation of the implementation from the specification of the Annual Plan? If not,
please explain. .................................................................................................70
7.
In R1.4 the Standard requires the Transmission Owner to have an Imminent Threat
Procedure and specifies elements to be in that procedure. Do you agree with R1.4?
If not, please explain. .......................................................................................79
8.
Requirement 1 section R1.5 replaces Version 1 sub-requirement R1.4. This section
is now referred to as interim corrective action process. This process addresses
situations where vegetation maintenance activities cannot be performed as planned.
The term corrective action plan is used in lieu of mitigation plan to avoid confusion
with other uses in NERC of “mitigation plan”. Do you agree with R1.5? If not, please
explain.......................................................................................................... 102
9.
Clearance 1 in Version 1 was a “fill-in-the-blank” requirement and was removed
from the standard. Do you agree? If not, please explain..................................... 110
10. Personnel Qualifications in R1.3 in Version 1 was a “fill-in-the-blank” requirement
and was removed from Version 2 of the standard. Do you agree? If not please
explain.......................................................................................................... 121
11. The IEEE 516 standard distances were replaced with the Gallet equation distances.
Clearance 2 was replaced by the Critical Clearance Zone. The Critical Clearance
Zone is defined as the zone of all possible positions of the conductor at the line’s
designed operating ratings including wind factors. (Please refer to pages 22-32 in
the Technical Reference Document on the Critical Clearance Zone for further
background for this question.) The imminent threat procedure, R2, requires action
to be taken to prevent an outage when the Critical Clearance Zone is approached.
Do you agree with R2? If not please explain. ..................................................... 129
September 8, 2009
2
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management
Program — Project 2007-07
12. The Standard Drafting Team revised the spark-over (also referred to as “flashover”)
distance thresholds utilizing technically-equivalent Gallet equations in lieu of IEEE
516 minimum air insulation distance (MAID) calculations that were used in FAC-0031. The rationale is that the minimum air insulation distances in IEEE 516 were
safety clearances developed under laboratory conditions and thus there exists
concern these distances may be too conservative to apply to lines operating in
actual field conditions. Do you agree with this? If not, please explain. .................. 151
13. The Standard Drafting Team applied a transient overvoltage factor (T) of 1.4 and 2.0
for ac voltage classes of 345kV and above and sub-345kV facilities, respectively.
Version 1, using the IEEE 516 method, assumes a maximum transient overvoltage
value. The Standard Drafting Team asserts that in this application of steady-state
flashovers and due to the design attributes of higher voltage systems, a lower T
factor is applicable. Do you agree with this? If not, please explain. ...................... 159
14. R3 has been added to clarify that conduction of inspections is a separate
requirement from specifying the frequency that inspections will occur. Do you agree
with R3? If not please explain.......................................................................... 165
15. Several alternatives to R4 were considered by the drafting team. The drafting team
explored these significantly different alternatives at length. They are outlined below
to provide background to industry during this comment period. (Please refer to
pages 22-32 in the Technical Reference Document on the Critical Clearance Zone for
further background for this question.) Do you agree that R4 is written in the most
effective way to achieve the purpose of the standard? If not, what do you propose
as an alternative to R4 that would ensure a level of reliability equal to or better than
FAC-003-1? ................................................................................................... 172
16. Requirements R5, R6, and R7 define that Sustained Outages due to vegetation
growing into, blowing together with, and falling into transmission lines are violations
(subject to certain exemptions). Therefore, all such outages must be reported as
violations of the standard. Do you agree with this change? If not, please explain. .. 205
17. R8 is a new requirement which separates the implementation of the annual plan
from the requirement to have an annual plan. Do you agree with R8? If not please
explain.......................................................................................................... 218
18. If you have further suggestions for improving this standard or the technical
reference document, please offer them.............................................................. 229
September 8, 2009
3
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
The Industry Segments are:
1 — Transmission Owners
2 — Transmission Owners, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 – Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
1.
John Neagle
Associated Electric Cooperative Inc.
2
3
4
5
6
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. Chris Bolick
SERC
1, 5, 6
2. John Bussman
SERC
1, 5, 6
3. Ralph Schulte
SERC
1, 5, 6
4. Ted Hilmes
SERC
1, 5, 6
5. John Settle
SERC
1, 5, 6
6. Kevin White
SERC
1, 5, 6
7. John Stickley
SERC
1, 5, 6
8. Gary Highfill
SERC
1, 5, 6
9. Jeff Neas
SERC
1, 5, 6
10. Craig Thomas
SERC
1, 5, 6
2.
Guy Zito
Additional Member
September 8, 2009
NPCC
Additional Organization
Region Segment Selection
4
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Commenter
Organization
Industry Segment
1
1. Ralph Rufrano
New York Powerm Authority
NPCC
5
2. Roger Champagne
Hydro-Quebec TransEnergie
NPCC
2
3. Rick White
Northeast Utilities
NPCC
1
4. Greg Campoli
New York Independent System Operator NPCC
2
5. Mike Garton
Dominion Resources Services, Inc.
NPCC
5
6. Chris De Graffenried
Consolidate Edison Co. of New York, Inc. NPCC
1
7. Don Nelson
Massachusetts Dept. of Public Utilities
NPCC
9
8. Kurtis Chong
Independent Electricity System Operator NPCC
2
9. Brian Gooder
Ontario Power Generation Incorporated
NPCC
5
10. David Kiguel
Hydro One Networks Inc.
NPCC
1
11. Kathleen Goodman
ISO - New England
NPCC
2
12. Brian Evans-Mongeon Utility Services, LLC
NPCC
6
13. Mike Gildea
Constellation Energy
NPCC
6
14. Lee Pedowicz
NPCC
NPCC
10
3.
Linda Perez
WECC Reliability Coordination
4.
Jerry Paulson
Western Area Power Administration, Upper Great
Plains Region
5.
Jack Gardner (Chairman)
Joe Spencer (SERC staff)
SERC Vegetation Management Subcommittee (VMS)
Additional Member
Additional Organization
3
4
5
6
7
8
9
10
Region Segment Selection
1. Jack Gardner
Progress Energy Carolinas
SERC
2. Randy Gann
Alabama Power Co.
SERC
3. John Neagle
Associated Electric Cooperative, Inc.
SERC
4. Robby Trimble
E.ON U.S. Services Inc. for LG&E & KU
Companies
SERC
5. Ralph Hale
Entergy
SERC
6. Marc Tunstall
Fayetteville Public Works Commission
SERC
7. Reggie Wallace
Fayetteville Public Works Commission
SERC
September 8, 2009
2
5
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Commenter
Organization
Industry Segment
1
8. Jerry Lindler
South Carolina Electric and Gas Company
SERC
9. Richard Dearman
Tennessee Valley Authority
SERC
10. Billy George
Duke Energy Carolinas
SERC
6.
John Pinney
Progress Energy Florida
2
3
4
5
6
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. David Crews
7.
FRCC
Michael Gammon
1, 3, 5
Kansas City Power & Light
Additional Member Additional Organization Region Segment Selection
1. Todd Fridley
SPP
1, 3, 5
2. Paul Beaulieu
SPP
1, 3, 5
3. Duane Anstaett
SPP
1, 3, 5
4. Gary O'Neil
SPP
1, 3, 5
8.
Ron Turley
Western Area Power Administration, Rocky Mountain
Region
9.
Jack Gardner
Progress Energy Carolinas
10.
Samuel Stonerock
Southern California Edison Company
11.
Jim Griffith
SERC OC Standards Review Group
Additional Member
Additional Organization
Region Segment Selection
1. Jim Case
Entergy
SERC
1, 3, 5
2. John Neagle
Assoc. Electric Coop., Inc.
SERC
1, 3, 5
3. Greg Rowland
Duke Energy-Carolinas
SERC
1, 3, 5
4. Bill Thompson
Dominion Virginia Power
SERC
1, 3, 5
5. John Rembold
Southern Illinois Power Coop.
SERC
1, 3, 5
6. Jason Marshall
Midwest ISO
SERC
2
September 8, 2009
6
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Commenter
Organization
Industry Segment
1
7. Randy Castello
Mississippi Power Co.
SERC
8. Jimmy Etheridge
Georgia Transmission Corp.
SERC
1
9. Danny Dees
Municipal electric Authority of Ga.
SERC
1, 3, 5
10. Glenn Stephens
South Carolina Public Service Auth. SERC
1, 3, 5
11. Glen Thweatt
Big Rivers Electric Coop.
SERC
1, 3, 5
12. Gerald Beckerle
Ameren
SERC
1, 3, 5
13. Sam Holeman
Duke Energy - Carolinas
RFC
1, 3, 5
14. Melinda Montgomery Entergy
SERC
1, 3, 5
15. Roman Carter
SERC
1, 3, 5
Southern Company
2
3
4
5
6
7
8
9
10
1, 3, 5
12.
Mike Neal
Western Utility Arborists
13.
John Tamsberg
Florida Power & Light
Additional Member Additional Organization Region Segment Selection
1. Eduardo Devarona
Florida Power & Light
FRCC
1
2. Silvia Parada-Fortum Florida Power & Light
FRCC
1
3. Brian J. Murphy
FRCC
1
14.
Florida Power & Light
Terry L. Blackwell
Santee Cooper
Additional Member Additional Organization Region Segment Selection
1. S. T. Abrams
Santee Cooper
SERC
1
2. Ben Fleming
Santee Cooper
SERC
1
3. Kenny Sott
Santee Cooper
SERC
1
4. Jim Peterson
Santee Cooper
SERC
1
5. Glenn Stephens
Santee Cooper
SERC
1
6. Kristi Boland
Santee Cooper
SERC
1
7. Rene' Free
Santee Cooper
SERC
1
15.
Roman Carter
September 8, 2009
Southern Company
7
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Commenter
Organization
Industry Segment
1
Additional Member
Additional Organization
1. Steve Burns
Gulf Power Co.
SERC
3
2. Nancy Huddleston
Georgia Power Co.
SERC
3
3. Ronald Reinike
Mississippi Power Co.
SERC
3
4. Randall Gann
Alabama Power Co.
SERC
3
5. Marc Butts
Southern Co. Transmission
SERC
1
6. Raymond Vice
Southern Co. Transmission
SERC
1
7. JT Wood
Southern Company Transmission SERC
1
8. Jim Busbin
Southern Co. Transmission
SERC
1
9. Chris Wilson
Southern Co. Transmission
SERC
1
16.
Charles Yeung
3
4
5
6
PJM
RFC
2
2. Jim Castle
NYISO
NPCC
2
3. Dan Rochester
IESO
NPCC
2
4. Matt Goldberg
IEONE
NPCC
2
5. Lourdes Estrada-Salinero CAISO
WECC
2
6. Anita Lee
AESO
WECC
2
7. Steve Myers
ERCOT
ERCOT
2
8. Bill Phillips
MISO
RFC
2
17.
Brent Ingebrigtson
E.ON U.S.
18.
Denise Koehn
Bonneville Power Administration
Additional Organization
9
10
Region Segment Selection
1.
John Jamrog
Vegetation/Access Road Mgmt
WECC
1
2.
Jerry Reding
Transmission Engineering
WECC
1
3. Don Swanson
Transmission Line Maintenance Technical Svcs WECC
1
4. Michael Staats
Transmission Engineering
1
September 8, 2009
8
Additional Organization Region Segment Selection
1. Patrick Brown
Additional Member
7
IRC Standards Review Committee
Additional Member
2
Region Segment Selection
WECC
8
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Commenter
Organization
Industry Segment
1
5. Steven Bottemiller
Real Property Support Svcs
WECC
1
6. Marian Wolcott
Real Property Svcs
WECC
1
7. Jennifer Bailey
Transmission Line Maintenance Technical Svcs WECC
1
8. Stephen Larson
Legal
WECC
1
9. Allen Chan
Legal
WECC
1
Transmission Field Services
WECC
1
2
3
4
5
6
7
8
9
10
10
Robin Furrer
19.
Jeffrey C. Mueller
Public Service Electric and Gas Company
20.
Sam Ciccone
FirstEnergy
Additional Member Additional Organization Region Segment Selection
1. Charles Olenik
FE
RFC
1
2. Shawn Standish
FE
RFC
1
3. Rebecca Spach
FE
RFC
1
4. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
21.
Joseph Knight
MRO NERC Standards Review Subcommittee
Additional Member Additional Organization Region Segment Selection
1. Neal Balu
WPS
MRO
2. Terry Bilke
MISO
MRO
2
3. Carol Gerou
MP
MRO
1, 3, 5, 6
4. Jim Haigh
WAPA
MRO
1, 6
5. Charles Lawrence
ATC
MRO
1
6. Ken Goldsmith
ALTW
MRO
4
7. Terry Harbour
MEC
MRO
1, 3, 5, 6
8. Pam Sordet
XCEL
MRO
1, 3, 5, 6
9. Dave Rudolph
BEPC
MRO
1, 3, 5, 6
10. Eric Ruskamp
LES
MRO
1, 3, 5, 6
September 8, 2009
3, 4, 5, 6
9
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Commenter
Organization
Industry Segment
1
11. Joe DePoorter
MGE
MRO
3, 4, 5, 6
12. Larry Brusseau
MRO
MRO
10
13. Michael Brytowski
MRO
MRO
10
22.
Jason L. Marshall
2
3
4
5
6
7
8
9
10
Midwest ISO Stakeholders Standards Collaborators
Additional Member Additional Organization Region Segment Selection
1. Jim Cyrulewski
JDRJC Associates
RFC
2. Greg Rowland
Duke Energy
SERC
1, 3, 5, 6
8
3. Kirit Shah
Ameren
SERC
1
23.
John Wolfmeyer
SERC Compliance Staff
24.
JAMES W. SMITH
ITC HOLDINGS
25.
Richard Dearman
Tennessee Valley Authority
26.
Chris Scanlon
Exelon
27.
Weston Davis
Central Maine Power Company
28.
Thad Ness
American Electric Power (AEP)
29.
Deborah Schaneman
30.
Platte River Power Authority
Alan Gale
City of Tallahassee
31.
Fred Young
Northern California Power Agency (NCPA)
32.
Jason Lietz
Northern Indiana Public Service Company
33.
Chip Turner
Tampa Electric Company
34.
Edward Bedder
Orange and Rockland Utilities Inc.
September 8, 2009
10
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
35.
Jason Shaver
American Transmission Company
36.
Alice Druffel
Xcel Energy
37.
Jeff Hackman
Ameren
38.
John Humphrey
Nebraska Public Power District
39.
Jonathan Appelbaum
Long Island power Authority
40.
Robert (Bob) B.
Suedkamp
USDA Forest Service, Southwestern Region, Regional
Office for AZ and NM
41.
Kris Manchur
Manitoba Hydro
42.
Jianmei Chai
Consumers Energy Company
43.
Dawn Travalini
National Grid
44.
Stephen Tankersley
Pacific Gas & Electric Co.
45.
Rich Salgo
NV Energy (fka Sierra Pacific / Nevada Power Co.)
46.
Patricia vanMidde
San Diego Gas & Electric
47.
David Kiguel
Hydro One Networks Inc.
48.
David Dworzak
Edison Electric Institute
49.
George Czerniewski
Consolidated Edison Company of New York (CECONY)
50.
Tom Mathews and Steve
Rueckert
WECC
September 8, 2009
7
8
9
10
11
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
51.
Sreenath Thota
Arizona Public Service Company
52.
Patrick Brown
PJM Interconnection
53.
William T. Rees
Baltimore Gas & Electric Company
54.
Greg Rowland
Duke Energy Corporation
55.
Michael Pakeltis
CenterPoint Energy
56.
Ed Davis
Entergy Services
57.
Anita Lee
Alberta Electric System Operator
58.
Richard Kafka
Pepco Holdings, Inc
59.
Virginia Cook and Kim
Wheeler
JEA
60.
Dan Rochester
Independent Electricity System Operator
61.
Karen Powell
Salt River Project
62.
Rick White
Northeast Utilities
63.
Roger Champagne
Hydro-Québec TransEnergie (HQT)
64.
Kevin Koloini
Buckeye Power, Inc.
65.
Joe Knight
Great River Energy
September 8, 2009
9
10
12
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
1. In the Purpose Statement the term “electric transmission systems” was changed to Bulk Electric System, and the
Purpose statement was shortened by moving the various explanatory objectives to other locations in the revised
Standard. Do you agree with the purpose statement? If not, please explain.
Summary Consideration: The SDT revised the purpose statement based on industry comments. The SDT returned to “electric
transmission system” based on the comments that indicated confusion with the use of “BES”. The SDT also inserted the word
“those” in front of the phrase “vegetation-related outages” to clarify that not all vegetation-related outages lead to cascading.
The revised purpose statement now reads:
Purpose: To improve the reliability of the electric transmission system by preventing those vegetation related outages that could lead to
Cascading.
Organization
Associated Electric
Cooperative Inc.
Agree?
Disagree
Question 1 Comment
The definition of Bulk Electric System includes most transmission lines operated at 100 kv and above. While
Section A.4.2.1 limits the applicability of FAC-003-2 to 200 kv and higher transmission lines, the use of the term
Bulk Electric System could cause unnecessary confusion. Associated Electric Cooperative Inc recommends the
continued use of the term "electric transmission systems."
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
SERC Vegetation
Management Subcommittee
(VMS)
Disagree
The definition of the Bulk Electric System generally does not include radial transmission lines directly serving load
and, in addition, includes all lines operated at 100 kV and above. Use of the term Bulk Electric System will cause
unnecessary confusion to the industry concerning applicability of this standard. Therefore, we recommend the
continued use of the undefined term "electric transmission systems."
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Progress Energy Florida
Disagree
The intent of the revision of the standard was to bring clarity to the standard. Referring to the BES in the purpose
creates confusion as to the applicability of the standard. Therefore, Progress Energy recommends the continued
use of the term "electric transmission systems."
Response: The SDT thanks you for your comment Based on the comments received, the SDT understands there may be confusion caused by “BES”
September 8, 2009
13
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 1 Comment
and has revised the purpose statement to delete BES and return to electric transmission system.
Kansas City Power & Light
Disagree
The definition of the bulk electric system does not match the scope of the systems covered by the vegetation
management standard. If the term bulk electric system is used , it should exclude the areas not covered by the
standard.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Western Area Power
Administration, Rocky
Mountain Region
Disagree
Use of the general term Bulk Electrical System creates unintentional confusion regarding the applicability of this
standard to lines operated at 200 kV or higher and designated lines operated below 200 kV.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Progress Energy Carolinas
Disagree
The intent of the revision of the standard was to bring clarity to the standard. Referring to the BES in the purpose
creates confusion as to the applicability of the standard. Therefore, Progress Energy recommends the continued
use of the term "electric transmission systems."
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
SERC OC Standards Review
Group
Disagree
The following comments are supplied by the SERC OC Standards Review Group (OCSRG): The definition of the
Bulk Electric System generally does not include radial transmission lines directly serving load. The current standard
covers all 200 kV and above transmission lines along with those lower voltage lines designated by the RRO while
the BES includes all lines 100 kV and above. Use of the term Bulk Electric System will cause unnecessary
confusion to the industry concerning applicability of this standard. Therefore, the SERC OCSRG recommends the
continued use of the undefined term "electric transmission systems."
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Florida Power & Light
September 8, 2009
Disagree
The Purpose Statement of any regulation or standard should be completely consistent with the body of regulation or
standard. Here the use of Bulk Electric System (which is defined as 100 kV and above) is inconsistent with the
language of the Standard that states this Standard applies to 200 kV and above. One of the primary purposes of re-
14
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 1 Comment
drafting a Reliability Standard is to clear up any previous confusion -- here the Purpose Statement instead of adding
to clarity, adds an unnecessary element of confusion. Thus, the Purpose Statement should be re-written to state
200 Kv and above.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”.
Rather than create a new class of BES (>200kv), the SDT revised the purpose statement to delete BES and return to electric transmission system.
Southern Company
Disagree
The initial FAC-003-1 drafting team had a particular reason for not using Bulk Electric System for fear of it being
widely recognized to characterize the entire networked transmission system. This reason was to limit possible
confusion with the applicability of the Standard. The Bulk Electric System definition includes all lines of the grid
operated at 100 kV and above. This term also does not necessarily include lines of any voltage class that are radial
and directly serving load. Use of this term in lieu of “electric transmission systems” has the potential to cause
additional confusion to the industry.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
E.ON U.S.
Disagree
The definition of the Bulk Electric System generally does not include radial transmission lines directly serving load
and, in addition, includes all lines operated at 100 kV and above. Use of the term Bulk Electric System will cause
unnecessary confusion to the industry concerning applicability of this standard. Therefore, we recommend the
continued use of the undefined term "electric transmission systems."
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
MRO NERC Standards
Review Subcommittee
Disagree
The standard specifically calls out that 200kV and higher are applicable to FAC-003. Changing to BES would imply
all lines 100kV and above would be applicable.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Midwest ISO Stakeholders
Standards Collaborators
September 8, 2009
Disagree
By definition Bulk Electric System includes most facilities 100 to 200 kV. The previous version of this standard
appropriately restricted the applicability of the standard to these facilities by requiring the Regional Reliability
Organization to identify only those facilities that are critical in this voltage class. This new version of the standards
attempts to limit the 100-200 kV class applicability by having the RC identify the critical facilities. We believe to
have one requirement of the standard say that it applies to all the BES and then another requirement to limit the
15
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 1 Comment
application only confuses the applicability and recommend leaving the term "electric transmission systems" in the
definition.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
SERC Compliance Staff
Disagree
The definition of the Bulk Electric System generally includes all lines operated at 100 kV and above and may
exclude radial lines to load only. The standard is applicable to lines operated at greater than 200 kV regardless of
their function. SERC staff does not believe that it is the intent of the standard to address lines operated at less than
200 kV unless they are deemed to be critical to the operation of the BES nor do we believe it is the intent to exclude
radials to load only from the applicability. Use of the term Bulk Electric System will cause unnecessary confusion to
the industry concerning applicability of this standard. Therefore, we recommend the continued use of the undefined
term "electric transmission systems."
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
ITC HOLDINGS
Disagree
ITC does not agree with the new purpose statement. The NERC Glossary of terms states that the BES ?.generally
operated at voltages of 100kV or higher and the Applicability in Section 4 clearly states the standard is intended to
apply to all line voltages of 200kV and above and those lines designated by the Reliability Coordinator (4.2.1) as
being subjected to this standard. Using the term Bulk Electric System (BES) clearly sends a confusing message and
should be eliminated. Thus the term of "electric transmission system" is appropriate for the standard
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Tennessee Valley Authority
Disagree
TVA feels the use of the term Bulk Electric System will cause unnecessary confusion to the industry concerning
applicability of this standard. TVA recommends the continued use of the undefined term "electric transmission
systems. TVA recommends changing the phrase "by preventing vegetation-related outages that could lead to
Cascading" to "by preventing those vegetation-related outages that could lead to Cascading", this removes the
improper inference that each vegetation-related outage leads to Cascading
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system. Additionally, at your suggestion and that of others,
the SDT has added the qualifying word “those” to define that the standard should address interconnection reliability and security.
September 8, 2009
16
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Central Maine Power
Company
Disagree
Question 1 Comment
Central Maine Power suggests that a definition be provided for Bulk Power.
Response: The SDT is uncertain of the need to define Bulk Power.
American Electric Power
(AEP)
Disagree
American Electric Power ("AEP") does not agree with this purpose statement. First, it is clear from the Applicability
(in Section 4) that the standard applies only to certain lines, not to the entire Bulk Electric System (BES). Reference
to the BES in the Purpose statement tends to muddy the water, potentially leading to an assumption that the
Standard indeed applies to the entire BES. AEP suggests that the term BES used herein be replaced with "electric
transmission system" or "transmission grid". Second, the phrase "by preventing vegetation-related outages that
could lead to Cascading" should be changed to "by preventing those vegetation-related outages that could lead to
Cascading", to remove any suggestion that all vegetation-related outages could lead to Cascading.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system. Additionally, at your suggestion and that of others,
the SDT has added the qualifying word “those” to define that the standard should address interconnection reliability and security.
Tampa Electric Company
Disagree
NERC glossary of terms defines the Bulk Electric System as "the electrical generation resources, transmission lines,
interconnections with neighboring systems, and associated equipment, generally operated at voltages of 100 kV or
higher." This, at a minimum, could lead to confusion over what impacts the reliability of the Grid by potentially
including facilities less than 200 kV.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Orange and Rockland Utilities
Inc.
Disagree
The use of the term "Bulk Electric System" (BES) could lead to confusion. In most regions BES includes lines with
operating voltages equal to or greater than 100kV. The Standard is intended to apply to all lines with operating
voltages equal to or greater than 200kV, and only those sub-200kV lines which are designated by the Reliability
Coordinator (paragraph 4.2.1). Use of the words "electric transmission systems" rather than BES would eliminate
this potential source of confusion.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
American Transmission
September 8, 2009
Disagree
ATC disagrees with changing the term "electric transmission systems" to "Bulk Electric System". This standard
applies to 200 kV and higher transmission lines not all BES facilities. Suggested Purpose statement: To maintain
17
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Company
Question 1 Comment
the reliability of the electric transmission system by requiring entities to have and implement a transmission
vegetation management plan.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system. We also appreciate your suggested purpose
statement but based on others’ comments to be more specific about the reliability need for this standard we modified the purpose statement as seen
in the Summary Consideration above.
Ameren
Disagree
By definition, the capitalized term, Bulk Electric System, is defined to include most facilities 100 kV and above. The
previous version of this standard appropriately restricted the applicability of the standard to those facilities operating
above 200kV and any additional facilities identified by the Regional Reliability Organization as critical. This new
version of the standards attempts to limit the 100-200 kV class applicability by having the RC identify the critical
facilities. We believe the change creates unnecessary and undesirable confusion in that one requirement of the
standard says that it applies to all the BES and then another requirement limits the application. Leaving the term
"electric transmission systems" in the definition is preferable to that proposed.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Nebraska Public Power
District
Disagree
NPPD disagrees with the change to bulk electric system, because it creates confusion on the applicability. This
standard only applies to certain lines and not the entire (bulk) system.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Manitoba Hydro
Disagree
Manitoba Hydro disagrees with changing "electric transmission systems" to "Bulk Electric System" because BES
applies to facilities 100kV and above which may not have an impact on system reliability.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Consumers Energy Company
Disagree
Consumers Energy disagrees with changing the current "electric transmission systems" to "bulk electric system".
This change will create confusion and can lead to a discrepancy concerning lines operating below 200kV that may
be included in the "bulk electric system" but are otherwise excluded from this standard.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
September 8, 2009
18
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 1 Comment
and has revised the purpose statement to delete BES and return to electric transmission system.
National Grid
Disagree
Use of the term Bulk Electric System will cause unnecessary confusion to the industry concerning applicability of
this Standard.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Edison Electric Institute
Disagree
The purpose of the standard should be revised to state 'To maintain minimum clearances sufficient to avoid any
vegetation-related Sustained Outages for all applicable conditions.' This is the identical wording taken from Order
No. 693, Paragraph 731.
Response: The SDT appreciates your comments to use the exact wording in the FERC Order for the purpose statement. However, the SDT believes
strongly that the interconnected system reliability which FERC should be protecting is better defined by the second posting statement. For instance,
there are 200 kV circuits which serve only local load. Outages to these circuits from vegetation are no different than from other causes. The issue for
this standard should be the prevention of vegetation outages that will threaten the interconnection.
Consolidated Edison
Company of New York
(CECONY)
Disagree
The phrase "Bulk Electric System" (BES) is somewhat misleading. BES includes transmission voltages greater than
100kV but this Standard addresses transmission lines with operating voltages at or above 200kV and only those
lines below 200kV designated by the Reliability Coordinator. Use of the phrase "electric transmission circuits" or
something similar rather than BES would reduce confusion.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Arizona Public Service
Company
Disagree
APS suggest the following change; To improve the reliability of the Bulk Electric System by preventing vegetation
related outages. This is a reliability standard APS would suggest removing "that could lead to widespread
cascading failures" from the purpose statement.
Response: The SDT thanks you for your comment. However, the SDT believes strongly that the interconnected system reliability which FERC should
be protecting is better defined by the second posting statement. For instance, there are 200 kV circuits which serve only local load. Outages to these
circuits from vegetation are no different than from other causes. The issue for this standard should be the prevention of vegetation outages that will
threaten the interconnection.
Duke Energy Corporation
September 8, 2009
Disagree
Duke disagrees with changing "electric transmission systems" to "Bulk Electric System" because this creates the
potential for confusion or indiscriminate expansion of the scope of applicability to 100kV facilities which may not
19
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 1 Comment
have an impact on network system reliability. Using "Bulk Electric System" confuses the applicability of the
standard. Duke believes that Section 4.2 has the specificity to clearly designate any applicable lines. Thus, the term
"electric transmission systems" is appropriate.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Entergy Services
Disagree
Entergy disagrees with changing “electric transmission systems” to “Bulk Electric System.” Historically, the
definition of the Bulk Electric System has included all lines operated at voltages 100 kV and greater. The above
change in terminology will add ambiguity to which lines this standard is applicable. Entergy is concerned about the
potential for this ambiguity leading to the expansion of the applicability of the standard to include lines below 200kv.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
JEA
Disagree
We disagree with this change as it may cause confusion on the applicability of the standard as the BES is generally
100kV and above, but this standard generally applies to 200kV and above.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Great River Energy
Disagree
The standard specifically calls out that 200kV and higher are applicable to FAC-003. Changing to BES would imply
all lines 100kV and above would be applicable
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Western Area Power
Administration, Upper Great
Plains Region
Agree
Western (UGPR) agrees with the objective of using the FERC/NERC defined term "Bulk Electric System", but
believe that the FERC/NERC definition includes lines above 100 kV. It needs to be clearly understood that use of
the generic term in the Purpose section does not supersede the specific definitions (greater than 200 kV, etc.)
contained in the Facilities section.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system based on a overwhelming industry preference for the
latter.
September 8, 2009
20
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Platte River Power Authority
Agree?
Agree
Question 1 Comment
The use of the approved terminology, Bulk Electric System, from the NERC Glossary of Terms is better than the
undefined term electric transmission systems.
Response The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system based on a overwhelming industry preference for the
latter.
Northeast Utilities
Agree
Agree with the term "bulk electric system. "Disagree with the wording of the Purpose Statement; The Purpose
statement reads "To improve the reliability of the bulk electric system by preventing vegetation related outages that
could lead to Cascading." One vegetation-caused outage does not in and of itself cause Cascading. Cascading will
only result due to a combination of events - either multiple vegetation outages during the same time or an outage
coupled with equipment malfunction or operational errors. The document seems to be internally inconsistent in this
regard. The Technical Reference for FAC-003-2 notes that outages due to trees falling from outside the right-of-way
or other outage causes on a critical facility would not constitute a possible cascading effect. If one occurrence of
these types of outages would not constitute a cascading potential then one must wonder why an outage from a tree
contact within the right-of-way is considered a possible cascading event? Suggest rewording the statement to
exclude the comment about Cascading and use "by preventing vegetation related outages on critical transmission
facilities."
Response: The SDT thanks you for your comment. The SDT acknowledges that a single vegetation-related outage will not, in the absence of other
contributing factors cause a cascading collapse of the electric grid. The intent of the standard is to prevent those vegetation-related outages that could
contribute to a cascading event. Therefore based on your comment, and others’, the SDT added “those” to further refine the intent.
Southern California Edison
Company
Agree
Q1: SCE agrees in part with the proposed revisions to the purpose statement. However, we believe the phrase
"vegetation related outages" is unnecessarily vague. Based on the content of certain requirements in Version 2, the
intent of this standard is and should be to prevent sustained outages due to vegetation-to-line contacts. SCE
respectfully suggests the purpose statement (A3) be revised to read: "To improve the reliability of the Bulk Electric
System by preventing vegetation-to-line contacts that could lead to Cascading?
Response: The SDT thanks you for your comment. The SDT focuses this standard on preventing vegetation-related Sustained Outages rather than
vegetation to line contacts as you recommend because not all contacts result in Sustained Outages.
BCTC
Agree
Yes, we agree.
Western Utility Arborists
Agree
Yes, we agree.
September 8, 2009
21
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Bonneville Power
Administration
Agree
FirstEnergy
Agree
Santee Cooper
Agree
Exelon
Agree
City of Tallahassee
Agree
Northern California Power
Agency (NCPA)
Agree
Northern Indiana Public
Service Company
Agree
Xcel Energy
Agree
Long Island power Authority
Agree
USDA Forest Service,
Southwestern Region,
Regional Office for AZ and
NM
Agree
Pacific Gas & Electric Co.
Agree
NV Energy (fka Sierra Pacific
/ Nevada Power Co.)
Agree
San Diego Gas & Electric
Agree
Hydro One Networks Inc.
Agree
September 8, 2009
Question 1 Comment
22
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
NPCC
Agree
WECC Reliability
Coordination
Agree
WECC
Agree
Baltimore Gas & Electric
Company
Agree
CenterPoint Energy
Agree
Pepco Holdings, Inc
Agree
Independent Electricity
System Operator
Agree
Salt River Project
Agree
Hydro-Quebec Transenergie
(HQT)
Agree
Buckeye Power, Inc.
Agree
Question 1 Comment
Response: The SDT thank you for your participation. The SDT made revisions to the purpose statement in response to industry comment. In order to
avoid confusion the SDT replace “BES” with “electric transmission system” and inserted the word “those” in front of the phrase “vegetation-related
outages”.
September 8, 2009
23
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
2. The Reliability Coordinator was chosen as the proper entity to identify sub-200kV transmission lines to be subject to
this standard (see applicability, R9, and R10). Do you agree with this choice? If not, please explain.
Summary Consideration: A majority of the commenters agreed with the selection of Reliability Coordinator to designate sub200 kV transmission lines to which this standard applies. However several dissenters recommended the Planning Coordinator
(PC) as a more appropriate choice. The stakeholders’ main reason for preferring the PC is the longer time horizon that the PC
normally considers in the performance of its function. Typically an RC considers the real time to months ahead operating time
horizons. A PC typically takes into account a planning horizon extending out several years. An example cited by some
stakeholders is the assignment to the PC for identifying applicable lines in NERC Standard PRC-023 R3 – Transmission Relay
Loadability.
Upon consideration of the sound rationale for replacement of RC with PC, the SDT changed Requirement R10 and R11 as well
as the applicability section 4.2 to reflect this.
Some commenters suggested that facilities critical to the derivation of an IROL should be the only criterion for selection of lines
subject to this standard. The Independent System Operator - Regional Transmission Owner Council (ISO/RTO Council) and
individual ISOs offered that all transmission lines of the BES are applicable under this standard regardless of voltage class or
impact on the BES. However the ISO/RTO Council believes that there are other standards that determine critical facilities.
The SDT agreed that including facilities critical to the derivation of an IROL would be a technically acceptable threshold to
determine applicability of sub-200 kV lines, but concluded that there are other thresholds that define circuits important to the
reliability of the Bulk Electric System (e.g., the WECC region’s Major Transfer Paths). The SDT wishes to allow the application of
other criteria in addition to IROL to support to the greatest extent possible the reliability of the BES.
Several commenters recommended the inclusion of a dispute resolution process and coordination between Transmission
Owner/RC in this standard to ensure agreement and consistency across regions. The SDT believes that the language in
Requirement R10 which specifies “consultation” OR CONSENSUS between the Planning Coordinator and its member
Transmission Owners, would minimize the need for a dispute resolution process. Additionally, other Standards in which the PC
determines important circuits to the reliability of the BES include no such mechanism.
Deleted: Reliability
Requirements R9 and R10 (now R10 and R11) were changed as follows:
R9.
Each Planning Coordinator shall prepare and review annually, a list lines that are operated below 200kV, if any, which are
subject to this standard. . Each Planning Coordinator shall consult with its Transmission Owner(s) and neighboring Planning
Coordinators to obtain input to develop the list.
September 8, 2009
Formatted: Indent: Left: 0",
Pattern: Clear (Custom
Color(RGB(211,220,233)))
24
Deleted: in consultation with its
Transmission Owner(s) and neighboring
Reliability Coordinator(s) shall jointly
prepare and keep current
Deleted: of designated applicable
Formatted: Indent: Left: 0",
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
R10. Each Planning Coordinator shall develop and document its method for assessing the reliability significance of sub-200kV lines
whose loss would place the grid at an unacceptable risk of instability, separation, or cascading failures.
Organization
Agree?
SERC Vegetation Management
Subcommittee (VMS)
Question 2 Comment
Deleted: Reliability
Deleted: considering all of the
following:¶
R10.1 Transmission lines whose loss
would result in the exceedance of an
Interconnection Reliability Operating
Limit (IROL)¶
R10.2 Transmission lines
The SERC Vegetation Management Subcommittee (VMS) abstains on this question. However, we believe that this
comment form should provide an option to abstain in addition to the options to agree/disagree.
Response: Thank you for your comment. The SDT does not believe this issue can be addressed by this team. However it is appropriate to raise this
limitation with the NERC staff.
American Transmission
Company
Disagree
Requirements 9 and 10 should be deleted and replaced with the following language. Proposed Language The
Transmission Owner shall include those transmission lines below 200 kV that that are associated with an established
IROL. (This language could either be uses as a requirement or inserted into the Applicability section.) Our statement
provides a clear decision on which lower voltage lines have to be included in an entities transmission vegetation
management program.
Response: Thank you for your comments. The SDT replaced RC with PC in Requirements R9 and R10 (now R10 and R11)as well as the applicability
section 4.2. The SDT believes that further guidance is needed to ensure all regions have evaluated and developed a list of sub 200kV lines that are subject
to this standard. The FERC indicated that not all regions produced such lists and directed the ERO, using this stakeholder process, to develop a
mechanism to provide the list. The proposed R10 continues to require consultation between the PC and Transmission Owner as well as neighboring PCs.
In R10, the SDT believes that the PC has the requisite expertise and planning horizon perspective to designate sub 200kV lines to comply with this
standard. Limiting the choice of lines to solely IROL lines may not achieve the purpose of this standard. The SDT intends in R10 that the PC employ a
technically sound criterion when designating transmission lines to be subject to this standard which includes IROL calculations.
Associated Electric
Cooperative Inc.
Disagree
Associated Electric Cooperative Inc does not believe the Reliability Coordinator (RC) is the appropriate entity to
determine whether or not selected sub-200 kv transmission lines should be subject to this standard. The planning
horizon for the RC is typically much shorter than the time needed to incorporate a sub-200 kv transmission line into a
vegetation management program. Associated recommends Planning Coordinator be designated as the applicable
functional entity and be substituted wherever Reliability Coordinator appears in the Standard.
Response: Thank you for your comment. The SDT agrees and has replaced RC with PC in Requirements R9 and R10 (now R10 and R11) as well as the
applicability section 4.2.
Santee Cooper
September 8, 2009
Disagree
The RC should not define applicable lines that are operated below 200 kV. PRC023 requires the Planning
Coordinator to define transmission lines operated at 100 kV to 200 kV that are considered critical to the reliability of
25
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 2 Comment
the Bulk Electric System. Multiple lists will lead to confusion among electric utilities.
Response: Thank you for your comments. Several commenters offered sound rationale for replacement of RC with PC including a reference to NERC
Standard PRC-023 Relay Loadability. The SDT agreed with the rationale and changed Requirements R9 and R10 (now R10 and R11) as well as the
applicability section 4.2 to reflect this.
Southern Company
Disagree
The use of the Reliability Coordinator as the entity for identifying sub-200 kV lines is inconsistent with the approach
used in other NERC standards, such as PRC-023. Other NERC standards utilize the Planning Coordinator or the RRO
as the entity. We feel the Planning Coordinator would be the appropriate entity for identifying sub-200 kV lines
covered by FAC-003-2.
Response: Thank you for your comments. Several commenters offered sound rationale for replacement of RC with PC including a reference to NERC
Standard PRC-023 Relay Loadability. The SDT agreed with the rationale and changed Requirements R9 and R10 (now R10 and R11) as well as the
applicability section 4.2 to reflect this.
SERC OC Standards Review
Group
Disagree
The SERC OCSRG does not believe that the RC is the appropriate entity to identify sub-200 kV transmissions to be
subject to this standard. Vegetation Management programs are longer than the normal operating horizons of RCs.
We believe that the proper function to identify sub-200 kV transmission lines subject to this standard is the Planning
Coordinator. This must be consistent with PRC-023, Requirement 3. We also recommend that a process be
established for dispute resolution. NERC should develop a comprehensive approach to the determination of "critical"
facilities rather than pushing a piecemeal approach as evidenced by this standard and PRC-023, among others.
Response: Thank you for your comments. Several commenters offered sound rationale for replacement of RC with PC including a reference to NERC
Standard PRC-023 Relay Loadability. The SDT agreed with the rationale and changed Requirements R9 and R10 (now R10 and R11) as well as the
applicability section 4.2 to reflect this. In regard to dispute resolution process, the SDT believes that the requirement for consultation implies cooperation
and collaboration between entities and a dispute resolution process is not currently needed.
In regard to a comprehensive approach to identify/determine “critical” facilities, the SDT agrees in concept but has some reservations. The reservations
are based upon doubt that “one size can fit all” for every context of every standard. A critical facility for one situation may not be a critical facility for
another. For example, the PRC standard seeks to identify facilities that may need to carry very heavy contingent flows to stop a cascade. This FAC-003
standard seeks to identify facilities for which their OUTAGE (due to vegetation) would create reliability concerns for the BES.
IRC Standards Review
Committee
September 8, 2009
Disagree
We do not see the role of an RC or PC in a vegetation management standard. All Transmission Owners need to
ensure they have a vegetation program to avoid unnecessary tripping of transmission lines, at any voltage levels and
regardless of their impacts on the BES. Identification of critical facilities is not a part of this standard; it belongs to
other standards that deal with SOL/IROL calculations, SPS, protection and critical infrastructure protection. R10 and
26
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 2 Comment
R11 should be removed from the standard.
Response: Thank you for your comments. The SDT does not agree with removal of R10 and R11. The SDT does not believe the burden of compliance for
low voltage circuits with little or no impact on the BES is reasonable for electricity consumers to bear. FERC has acknowledged the same and given
guidance for this standard’s applicability which provides that a distinction exists in sub-200 kV facilities. The SDT sought to develop a reasonable
mechanism that balances these concerns when we drafted R9 and R10 (now R10 and R11). The SDT agrees with respect to use of the label “critical”. This
standard does not intend to classify facilities as critical, that is left to CIP-002.
Independent Electricity System
Operator
Disagree
The IESO does not see a role for an RC or PC in a vegetation management standard. All Transmission Owners need
to ensure they have a vegetation program to avoid unnecessary tripping of transmission lines, particularly those that
impact the BES. We are of the view that identification of critical facilities is not a part of this standard; it belongs to
other standards that deal with SOL/IROL calculations, SPS, protection and critical infrastructure protection. R10 and
R11 should therefore be removed from the standard.
Response: Thank you for your comments. The SDT does not agree with removal of R10 and R11. The SDT does not believe the burden of compliance for
low voltage circuits with little or no impact on the BES is reasonable for electricity consumers to bear. FERC has acknowledged the same and given
guidance for this standards’ applicability which provides that a distinction exists in sub-200 kV facilities. The SDT sought to develop a reasonable
mechanism that balances these concerns when we drafted R9 and R10 (now R10 and R11). The SDT agrees with respect to use of the label “critical”. This
standard does not intend to classify facilities as critical, that is left to CIP-002.
Hydro-Quebec Transenergie
(HQT)
Disagree
HQT believe that the Planning Coordinator (PC) should be the entity responsible to determine the elements part of the
BPS submitted to this Standard, and in fact for all other Standards. Those elements should be determined by an
impact based methodology, as used in NPCC, with no voltage limitation and no fixed voltage threshold level as
imposed in Applicability 4.2.
Response: Thank you for your comments. Several commenters offered sound rationale for replacement of RC with PC. The SDT agreed with the rationale
and changed Requirement R9 and R10 (now R10 and R11) as well as the applicability section 4.2 to reflect this. The SDT believes each PC can determine
the appropriate threshold to assure the reliability of the BES and does not believe it necessary to instruct PCs in this regard in this Standard.
MRO NERC Standards Review Disagree
Subcommittee
The MRO disagrees that the RC is appropriately positioned to identify and designate any sub-200kV lines that should
be subject to this standard. The MRO believes that the lines below 200kV should include only those that are currently
classified as Interconnection Reliability Operating Limit (IROL) lines which are already defined and listed for registered
entities. As such R10 and R11 should be eliminated from these standards along with the RC in the applicability
section.
Response: Thank you for your comments. The SDT agrees that the RC is not appropriately positioned and replaced the RC with the PC. The SDT believes
September 8, 2009
27
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 2 Comment
that further guidance is needed to ensure all regions have evaluated and developed a list of sub 200kV lines that are subject to this standard. FERC
indicated that not all regions produced such lists and directed the ERO, using this stakeholder process, to develop a mechanism to provide the list. The
proposed R10 continues to require consultation between the PC and Transmission Owner as well as neighboring PCs. In R10, the SDT believes that the
PC has the requisite expertise and planning horizon perspective to designate sub 200kV lines to comply with this standard. Limiting the choice of lines to
solely those included in the derivation of an IROL may not achieve the purpose of this standard. The SDT intends in R10 that the PC employ a technically
sound criterion when designating transmission lines to be subject to this standard, which could include those included in the derivation of IROL
calculations.
Midwest ISO Stakeholders
Standards Collaborators
Disagree
We do not believe that the RC is the appropriate entity to identify those facilities sub-200 kV facilities that this standard
should apply to. Vegetation management is not performed in the operating horizon. Rather it is performed in the
planning and operations planning horizons. The RC should not be distracted from focusing on the operating horizon
by this task. We believe what the standard is essentially requiring is identifying critical facilities. There are other
similar requirements such as PRC-023-1 R3 that appear to require the determination of critical facilities even though
the term critical facilities is not defined. We believe this represents broader issue that requires NERC to define critical
facilities. Failure to do so could result in the inefficient identification of multiple lists of critical facilities for specific
requirements that may ultimately be challenged in due process.
Response: Thank you for your comments. Several commenters offered sound rationale for replacement of RC with PC including a reference to NERC
Standard PRC-023 Relay Loadability. The SDT agreed with the rationale and changed Requirements R9 and R10 (now R10 and R11) as well as the
applicability section 4.2 to reflect this. Your comment on time horizon further supports this change.
In regard to a comprehensive approach to identify/determine circuits, the SDT agrees in concept but has some reservations. The reservations are based
upon doubt that “one size can fit all” for every context of every standard. A critical facility for one situation may not be a critical facility for another. For
example, the PRC standard seeks to identify facilities that may need to carry very heavy contingent flows to stop a cascade. This FAC-003 standard seeks
to identify facilities for which their OUTAGE (due to vegetation) would create reliability concerns for the BES.
Ameren
Disagree
While the RC would seemingly have the wide area view to make the assignment appropriate, the standard is really
trying to determine the entity who can assess the risk to the BES of a vegetation-related outage. The management of
that risk is in the venue of the Transmission Planner who, in the long term, designs the system and, in the Operating
Horizon, establishes the parameters of operation that will lead to reliability. Certainly, the RC is preferable to the RE
(RRO). However, the TP is preferable to the RC.
Response: Thank you for your comments. Several commenters offered sound rationale for replacement of RC with PC including a reference to NERC
Standard PRC-023 Relay Loadability. The SDT agreed with the rationale and changed Requirements R9 and R10 (now R10 and R11) as well as the
applicability section 4.2 to reflect this. The PC performs its function over a similarly long term time horizon as the Transmission Planner but would be
better positioned as a result of the PC’s wider area view.
September 8, 2009
28
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Manitoba Hydro
Agree?
Disagree
Question 2 Comment
Manitoba Hydro disagrees that the RC is appropriately positioned to identify and designate any sub-200kV lines that
should be subject to this standard. Lines below 200kV should include only those that are currently classified as
Interconnection Reliability Operating Limit (IROL) lines which are already defined and listed for registered entities. As
such R10 and R11 should be eliminated from this standards along with the RC in the applicability section.
Response: Thank you for your comments. The SDT agrees that the RC is not appropriately positioned and replaced the RC with the PC in the revised draft
proposed Standard.
The SDT agrees that lines included in the derivation of an IROL should be included in the PC’s list; there are other lines that have importance to the
reliability of the BES, e.g. the WECC Major Transfer Paths. The PC is well qualified for this differentiation task and may choose to develop thresholds
which match the needs of its region. Therefore, the SDT respectfully disagrees that the only sub-200 kV circuits for which this standard should apply are
those stated by MH.
WECC
Disagree
WECC believes the Regional Entity should remain the proper entity to identify sub-200kV transmission lines subject to
this standard. The Regional Entity is in the best position to work with Transmission Owners (Transmission Owners)
and Reliability Coordinators across the interconnection to determine critical sub-200kV transmission lines.
Response: Thank you for your comments. Several commenters offered sound rationale for replacement of RC with PC. The SDT agreed with the rationale
and changed Requirements R9 and R10 (now R10 and R11) as well as the applicability section 4.2 to reflect this.
PJM Interconnection
Disagree
The RC or PC should not play a role in the vegetation management standard. All Transmission Owners need to
ensure they have a vegetation program to avoid unnecessary tripping of transmission lines, at any voltage levels and
regardless of their impacts on the BES. Identification of critical facilities is not a part of this standard; it belongs to
other standards that deal with SOL/IROL calculations, SPS, protection and critical infrastructure protection. R10 and
R11 should be removed from the standard.
Response: Thank you for your comments. The SDT does not agree with removal of R10 and R11. The SDT does not believe the burden of compliance for
low voltage circuits with little or no impact on the BES is reasonable for electricity consumers to bear. FERC has acknowledged the same and given
guidance for this standards’ applicability which provides that a distinction exists in sub-200 kV facilities. The SDT sought to develop a reasonable
mechanism that balances these concerns when we drafted R10 and R11. The SDT agrees with respect to use of the label “critical”. This standard does not
intend to classify facilities as critical, that is left to CIP-002
National Grid
Disagree
No opinion.
Response: Thank you for your participation.
September 8, 2009
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Organization
Duke Energy Corporation
Agree?
Disagree
Question 2 Comment
Duke believes that the Planning Coordinator is the appropriate entity to identify any sub-200 kV facilities that this
standard should apply to. Of note is the time frame once a sub-200kV line is designated, then the Transmission
Owner has 12 months before the line is subject to the standard. This coincides with the longer term view of the
Planning Coordinator.
Response: Thank you for your comment. Several commenters offered sound rationale for replacement of RC with PC. The SDT agreed with the rationale
and changed Requirements R9 and R10 (now R10 and R11) as well as the applicability section 4.2 to reflect this.
Great River Energy
Disagree
GRE disagrees that the RC is appropriately positioned to identify and designate any sub-200kV lines that should be
subject to this standard. GRE believes that the lines below 200kV should include only those that are currently
classified as Interconnection Reliability Operating Limit (IROL) lines which are already defined and listed for registered
entities. As such R10 and R11 should be eliminated from this standards along with the RC in the applicability section.
Response: Thank you for your comments. The SDT agrees that the RC is not appropriately positioned and replaced the RC with the PC in the draft
proposed Standard.
The SDT agrees that lines included in the derivation of an IROL should be included in the PC’s list, there are other lines that have importance to the
reliability of the BES, e.g. the WECC Major Transfer Paths. The PC is well qualified for this differentiation task and may choose to develop thresholds
which match the needs of its region. Therefore, the SDT respectfully disagrees that the only sub-200 kV circuits for which this standard should apply are
those stated by GRE.
WECC Reliability Coordination
Agree
This would be a new function in WECC RC; we are not currently staffed to perform this function.
Response: Thank you for your comment. The SDT replaced RC with PC in Requirements R9 and R10 (now R10 and R11) as well as the applicability
section 4.2.
Western Area Power
Administration, Upper Great
Plains Region
Agree
Western's (UGPR) agreement is contingent upon maintaining the requirements for consulting with Transmission
Owners and neighboring Reliability Coordinator(s) and documenting the method for assessing the reliability
significance of each included line as contained in R10 and R11.
Response: Thank you for your comment. The SDT replaced RC with PC in Requirements R9 and R10 (now R10 and R11) as well as the applicability
section 4.2. The proposed R10 continues to require consultation between the PC and Transmission Owner as well as neighboring PCs.
Progress Energy Florida
September 8, 2009
Agree
While Progress Energy agrees that the RC is the appropriate entity, the drafting team should consider including a
dispute resolution requirement for those instances when the Transmission Owner and the Reliability Coordinator
disagree as to which lines below 200 kV should be included.
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Organization
Agree?
Question 2 Comment
Response: Thank you for your comment. Several commenters offered sound rationale for replacement of RC with PC. The SDT agreed with the rationale
and changed Requirements R9 and R10 (now R10 and R11) as well as the applicability section 4.2 to reflect this. In regard to dispute resolution process,
the SDT believes that the requirement for consultation implies cooperation and collaboration between entities and a dispute resolution process is not
currently needed.
Kansas City Power & Light
Agree
I agree with the qualification that the Reliability Coordinator identify sub-200kv facilities in consultation with its
Transmission Owner(s) and neighboring Reliability Coordinator(s).
Response: Thank you for your comment. The SDT replaced RC with PC in Requirements R9 and R10 (now R10 and R11) as well as the applicability
section 4.2. The proposed R10 continues to require consultation between the PC and Transmission Owner as well as neighboring PCs.
Progress Energy Carolinas
Agree
While Progress Energy agrees that the RC is the appropriate entity, the drafting team should consider including a
dispute resolution requirement for those instances when the Transmission Owner and the Reliability Coordinator
disagree as to which lines below 200 kV should be included.
Response: Thank you for your comment. Several commenters offered sound rationale for replacement of RC with PC. The SDT agreed with the rationale
and changed Requirements R9 and R10 (now R10 and R11) as well as the applicability section 4.2 to reflect this. In regard to dispute resolution process,
the SDT believes that the requirement for consultation implies cooperation and collaboration between entities and a dispute resolution process is not
currently needed.
Southern California Edison
Company
Agree
Q2: No comments.
Response: Thank you for your participation.
Western Utility Arborists
Agree
Yes, we agree.
Response: Thank you for your comment. Please see the summary consideration – based on stakeholder comments, the SDT changed the applicability in
Requirements R9 and R10 (now R10 and R11) from the Reliability Coordinator to the Planning Coordinator.
ITC HOLDINGS
Agree
ITC agrees that the Reliability Coordinator is the appropriate entity to identify and designate any sub - 200kV lines
deemed applicable to the standard with the concurrence of the Transmission Owner.
Response: Thank you for your comment. Based on other stakeholder comments, the SDT replaced RC with PC in Requirements R9 and R10 (now R10 and
R11) as well as the applicability section 4.2. The proposed R10 continues to require consultation between the PC and Transmission Owner as well as
September 8, 2009
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Organization
Agree?
Question 2 Comment
neighboring PCs.
Tennessee Valley Authority
Agree
TVA agrees with Comment question 2
Response: Thank you for your comment. Based on other stakeholder comments, the SDT replaced RC with PC in Requirements R9 and R10 (now R10
and R11) as well as the applicability section 4.2. The proposed R10 continues to require consultation between the PC and Transmission Owner as well as
neighboring PCs.
American Electric Power (AEP) Agree
AEP concurs with the drafting team that the Reliability Coordinator is the appropriate entity for identifying sub-200kV
lines (if any) that would be subject to the Standard.
Response: Thank you for your comment. Based on other stakeholder comments, the SDT replaced RC with PC in Requirements R9 and R10 (now R10 and
R11) as well as the applicability section 4.2.
Platte River Power Authority
Agree
The Reliability Coordinator is better able to identify lines under 200 kv that would exceed an Interconnection Reliability
Operating Limit (IROL), cause instability, uncontrolled separation, or cascading outages resulting from a vegetation
related outage than the Regional Entity.
Response: Thank you for your comment. Based on other stakeholder comments, the SDT replaced RC with PC in Requirements R9 and R10 (now R10 and
R11) as well as the applicability section 4.2.
Nebraska Public Power District
Agree
NPPD agrees that the Reliability Coordinator is the correct body for identification of any sub 200kV lines that would be
subject to this standard.
Response: Thank you for your comment. Based on other stakeholder comments, the SDT replaced RC with PC in Requirements R9 and R10 (now R10 and
R11) as well as the applicability section 4.2.
Consolidated Edison Company
of New York (CECONY)
Agree
CECONY agrees provided that R10 remains the same as is currently written. This states that the Reliability
Coordinator, in consultation with the Transmission Owner, shall jointly prepare and keep current, a list of designated
applicable lines.
Response: Thank you for your comment. Based on other stakeholder comments, the SDT replaced RC with PC in Requirements R9 and R10 (now R10 and
R11) as well as the applicability section 4.2. The proposed R10 continues to require consultation between the PC and Transmission Owner as well as
neighboring PCs.
September 8, 2009
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Organization
Northeast Utilities
Agree?
Agree
Question 2 Comment
One question: Will the Reliability Coordinators use consistent criteria for listing sub 200-kV facilities to be included
under FAC-003-2? The purpose of FAC-003 is to ensure inter-regional reliability and to focus on the reliable
operation of these lines. By leaving the decision up to the individual Reliability Coordinators - there is the potential for
local differences in determining which sub-200-kV facilities may be critical. This could result in some transmission
owners having to include certain facilities under the requirements of FAC-003-2 where in other regions of the country similar facilities may not be included by the Reliability Coordinator. Although there have been criteria established to
guide the Reliability Coordinators in the determination of sub-200-KV facilities for inclusion under FAC-003-2 - is this
sufficient to ensure uniformity throughout the US? Perhaps some involvement at the Regional Entity level at least, is
warranted.
Response: Thank you for your comments. The SDT agrees with the points you raise regarding inter-regional reliability. This is addressed in part by the
requirement R10 where consultation with neighboring entities is specified. We feel that the requirement R10 ensures that inter-regional coordination is
addressed.
In addition several commenters offered sound rationale for replacement of RC with PC. The SDT agreed with the rationale and changed Requirements R9
and R10 (now R10 and R11) as well as the applicability section 4.2 to reflect this.
Baltimore Gas & Electric
Company
Agree
The documented method to assess the reliability significance of sub-200 kV lines referenced in R10 should be put out
for comment by the Reliability Coordinator to the regulated entities and FERC/NERC before it is finalized.
Response: Thank you for your comment. Several commenters offered sound rationale for replacement of RC with PC. The SDT agreed with the rationale
and changed Requirements R9 and R10 (now R10 and R11) as well as the applicability section 4.2 to reflect this.
Entergy Services
Agree
The applicability of this standard should state that it is not applicable to insulated transmission lines, such as
underground lines.
Response: Thank you for your comment. The SDT believes that the general term “transmission line” along with the associated tables and terminology
sufficiently eliminates any misconception or misdirected thought that this standard applies to underground conductors or other conductors that are
insulated in a manner that would prevent their flashover to trees.
Pepco Holdings, Inc
Agree
FERC Order 693 essentially has the RC replacing the RRO.
Response: Thank you for your comment. Several commenters offered sound rationale for replacement of RC with PC. The SDT agreed with the rationale
and changed Requirements R9 and R10 (now R10 and R11) as well as the applicability section 4.2 to reflect this.
BCTC
Agree
September 8, 2009
Yes, we agree.
33
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 2 Comment
Response: Thank you for your participation.
Buckeye Power, Inc.
Agree
Agreed on this question.
Response: Thank you for your participation.
Western Area Power
Administration, Rocky
Mountain Region
Agree
Florida Power & Light
Agree
Bonneville Power
Administration
Agree
FirstEnergy
Agree
SERC Compliance Staff
Agree
Exelon
Agree
Central Maine Power Company Agree
City of Tallahassee
Agree
Northern California Power
Agency (NCPA)
Agree
Northern Indiana Public
Service Company
Agree
Tampa Electric Company
Agree
Orange and Rockland Utilities
Agree
September 8, 2009
34
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 2 Comment
Inc.
Long Island power Authority
Agree
USDA Forest Service,
Southwestern Region,
Regional Office for AZ and NM
Agree
Consumers Energy Company
Agree
Pacific Gas & Electric Co.
Agree
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Agree
San Diego Gas & Electric
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
Arizona Public Service Co.
Agree
JEA
Agree
CenterPoint Energy
Agree
Salt River Project
Agree
September 8, 2009
35
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
3. In R1 the proposed standard replaces “prepare, and keep current” with “have”, replaces the list of terms, “objectives,
practices, approved procedures, and work specifications,” with “designed to control vegetation”, defines the “active
transmission line ROW”, and specifies that the transmission vegetation management program applies to that area. Do
you agree with R1? If not, please explain.
Summary Consideration:
Regarding the use of “have”, some commenters requested that the original wording should remain. However, the SDT and
some other commenters note that proving whether something is “current” is an opportunity for compliance ambiguity and
unintended discrimination. Therefore, the SDT continues to use “have” in the second draft.
A few commenters raised the issue concerning Critical Clearance Zone in this question and that has been addressed with the
substantive changes which have been made to the second draft standard.
While some commenters prefer the list of terms, the SDT chose the term “methods” as a more global, all encompassing term
that allows transmission owners flexibility in developing their Transmission Vegetation Management Program. The SDT agrees
the list of terms is helpful. However, when listed in a Requirement there is an expectation that all such terms must be included
and evidence produced to show compliance. The list of terms can be included in the technical reference to assist Transmission
Owners.
Finally, many commenters wanted more specificity in the reference material to describe the “Active Transmission Line Right-ofWay”. The SDT has provided additional clarification in the technical reference document.
Formatted: Space After: 6 pt,
Pattern: Clear (Custom
Color(RGB(211,220,233)))
The revised R1 is shown below:
Deleted: designed to control vegetation
Deleted: s’
R1.
Each Transmission Owner shall have a documented transmission vegetation management program that describes how it
conducts work on its Active Transmission Line Rights of Way to prevent Sustained Outages due to vegetation, considering all
possible locations the conductor may occupy under the effects of sag and sway throughout its operating range under rated
conditions. The transmission vegetation management program shall:
1.1. Specify the methods that the Transmission Owner may use to control vegetation.
Deleted: R
Deleted: methodologies
Deleted: Owner
Deleted: s
Deleted: 2
Deleted: R
1.2. Specify a Vegetation Inspection frequency of at least once per calendar year that takes into account local3 and environmental
factors.
Deleted: vegetation
1.3. Require an annual plan. An annual work plan shall:
Formatted: Superscript
Deleted: i
Deleted: R
September 8, 2009
36
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Deleted: that i
1.3.1 Identify the applicable lines to be maintained
Deleted: ies
1.3.2 Identify the work to be performed
Formatted: Font: Bold
1.3.3 Be flexible to adjust to changing conditions and to findings from Vegetation Inspections. Adjustments to the plan within the
year are permissible.
Deleted: and associated
1.3.4 Take into consideration permitting and scheduling requirements from landowners or regulatory authorities.
Deleted: vegetation
Deleted: during the year. It shall b
Deleted: i
1.4. Require a process or procedure for response to an imminent threat of a vegetation related Sustained Outage. The process or
procedure shall specify actions which shall include immediate communication of the threat to the responsible control center.
Deleted: The plan shall t
Deleted:
1.5. Specify an interim corrective action process for use when the Transmission Owner is constrained from performing vegetation
maintenance as planned.
1.6 Specify the maintenance strategies used (such as minimum vegetation-to-conductor distance or maximum vegetation height) to
ensure that Table 1 clearances in Attachment 1 are never violated. The maintenance strategies shall consider the sag and sway of the
conductor throughout its operating range under rated conditions.
Deleted: It shall support the objectives
of the transmission vegetation
management program and use the
methodologies outlined in the
transmission vegetation management
program.¶
R
Deleted: s
Deleted: Transmission Operator
Organization
Bonneville Power
Administration
Agree?
Disagree
Deleted: , and may include actions such
as a temporary reduction in line Rating,
switching lines out of service, or other
actions.
Question 3 Comment
R1: BPA understands that version 2 clearly states that the Critical Clearance Zone does not extend beyond the Deleted: R
Active Transmission Right of Way. The Technical reference provides examples of active and inactive portions of
Indent: Left: 0", First
corridors. BPA feels this list of examples is not exhaustive and therefore the technical reference language shouldFormatted:
line: 0", Space After: 6 pt, Pattern:
be changed to read, "Examples of active and inactive portions of corridors include, BUT MAY NOT BE LIMITED Clear (Custom
Transmission Owner:"
Color(RGB(211,220,233)))
Also, since it is clearly stated on page 2 of the Standard, that the Critical Clearance Zone shall not extend beyond
the limits of the Active Transmission Line Right of Way, and that these limits are not specifically defined because
they may vary by circumstance, the definition of Active Transmission Line Right of Way on Page 2 of the Standard
should include a statement that the actual physical limits of each Active Right of Way will be determined by the
Transmission Owner.
R1.1: BPA recommends retaining the version 1 language of "objectives, practices, approved procedures, and
work specifications" as it is more instructive in what is expected of a TMVP then the version 2 replacement
language of "methodologies."
Response: Thank you for your comment. The issues concerning Critical Clearance Zone have been addressed by changes which have been made to
September 8, 2009
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 3 Comment
the draft standard. The definition and use of the term “Critical Clearance Zone” have both been removed from the revised standard.
The SDT chose, for the revised standard, the term “methods” as a more global, all encompassing term that allows transmission owners flexibility in
developing their Transmission Vegetation Management Program. ANSI A300 has been referenced as a best management practice by reference as a
footnote to R1.1.
Associated Electric Cooperative Disagree
Inc.
Associated Electric Cooperative Inc agrees with the changes described in Question 3 except for the definition of
Active Transmission Line Right of Way. Associated suggests the term be revised to "Active Right-of-Way" for
consistency with the present Glossary term "Right-of-Way" and that the definition of Active Right-of-Way be
revised to explicitly permit the Transmission Owner to solely determine the appropriate width. A suggested
definition is "Active Right-of-Way: The portion of Right-of-Way utilized for active transmission facilities. The width
of the Active Right-of-Way, as determined by the Transmission Owner, shall be consistent with the Transmission
Owner’s normal standards and practices and shall be consistent with good utility practice for other transmission
lines of similar voltage and configuration. Inactive or unused portions of the Right-of-Way, intended for future
transmission lines or other facilities, may be excluded from the Active Right-of-Way."
Response: Thank you for your comment. While there is logic in your proposal to simply modify Rights-of-Way with “Active”, previous commenters
wanted to include “Transmission” to clearly eliminate the case of rights-of-way that include lower voltage facilities.
NPCC
Disagree
While we agree with the suggested changes, we believe that the Transmission Vegetation Management Program
should be focused on removal of incompatible vegetation from the Active Right of Way. We recommend using the
following phrase in R1: "designed to remove incompatible vegetation on its Active Transmission Lines' Rights 0f
Way" instead of "designed to control vegetation on its Active Transmission Lines' Rights of Way ".
Incompatible vegetation should be defined as any vegetation which has the potential to grow tall enough to
jeopardize the integrity of an applicable transmission line by growing into the Critical Clearance Zone or falling
into the Critical Clearance Zone. This would provide clear guidance to all stakeholders, support long term
vegetation management philosophies, and complement methods such as IVM where incompatible vegetation is
completely removed, and compatible vegetation is encouraged to proliferate, thereby helping to control
incompatible vegetation in an environmentally positive manner. Removal of incompatible vegetation is superior to
pruning, topping, and trimming in terms of short and long term reliability of the Bulk Electric System. This
language would also serve to align NERC and FERC with Transmission Owners who attempt achieve the highest
degree of reliability by exercising their full easement rights in cases where strong opposition from landowners and
public officials is encountered. If such language is adopted it should apply to R1 and the Transmission Vegetation
Management Program.
It should be made clear in the technical reference document that removal, rather than pruning of incompatible
vegetation is the philosophy that must be incorporated into the Transmission Vegetation Management Program. It
September 8, 2009
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 3 Comment
must be clearly explained that Transmission Owners have the flexibility to perform removals gradually over
several treatment cycles in sensitive areas as long as pruning is performed as an interim measure to ensure that
Critical Clearance Zone encroachments and on-Right of Way fall overs do not occur. It must also be made clear
that the presence of incompatible vegetation on the Right of Way will always occur and does not in itself constitute
a violation of the Standard.
Response: Thank you for your comment. The SDT has addressed removal of incompatible vegetation as a best management practice by referencing
ANSI A300 as a footnote to Requirement R1. It is noted that A300 is not a requirement of the standard, only a best management practice. We will
address your other comments in the technical reference paper for industry guidance.
Baltimore Gas & Electric
Company
Disagree
I agree with the simplification of the language, but I am uncomfortable with the definition of Active Right-of-Way
(R/W). The definition in FAC-003-2 and the examples used in the white paper continue to leave room for
interpretation, particularly with respect to the example where only one circuit is installed on a double circuit tower.
Moreover, there may be circumstances where the Active R/W is relatively narrow and the utility has an Inactive
R/W or otherwise owns land adjacent to the Active R/W that can be maintained to protect the facilities from growins. Consequently, consideration should be given to require utilities to protect lines from grow-ins into the Critical
Clearance Zone regardless of whether or not the R/W is Active or Inactive as long as the utility has the legal
ability to do the necessary work.
Response: Thank you for your comment. The Standard clearly addresses that all grow-ins are considered to be within the active right-of-way,
regardless of whether or not the tree is rooted within the active right-of-way. The Standard requires that such vegetation be managed as described in
the Transmission Owner’s Transmission Vegetation Management Program. Additionally, the SDT has revised the drawings and guidance in the technical
reference paper to eliminate the confusion you and others detected.
Northern Indiana Public Service Disagree
Company
Use of the term "have" is a notable and unnecessary weakening versus the terms "prepare and keep current".
One of the key lessons learned from past vegetation related outages and subsequent investigations and reports is
that successful UVM programs must continually adapt to changing circumstances which means practices and
procedures must be kept current. Why weaken this expectation in the standard? Also, I disagree with the
elimination from the revised standard the present requirement R1 that all Transmission Vegetation Management
Programs include certain essential components (objectives, practices, approved procedures & work
specifications). Why make changes that imply Transmission Vegetation Management Program's without these
key components are acceptable?
Response: Thank you for your comment. The SDT believes that the term “have” is appropriate. While sympathetic to your perception about the terms, in
order to “have” a Transmission Vegetation Management Program it had to have been prepared. Latency of the plan, like all plans required by NERC
standards, can easily be addressed in compliance without creating the task of proving “current” if it is included in the Requirement. The SDT chose, for
the revised standard, the term “methods” as a more global, all encompassing term that allows transmission owners flexibility in developing their
September 8, 2009
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 3 Comment
Transmission Vegetation Management Program. ANSI A300 has been referenced as a best management practice by reference as a footnote to R1.1.
Xcel Energy
Disagree
We propose adding the following language to the end of the definition for "Active Transmission Line Right of
Way": OR OTHER PURPOSES, REGARDLESS OF THE PREMISES DIMENSIONS IN ANY EASEMENT,
LICENSE AGREEMENT OR OTHER LAND RIGHT DOCUMENT.
Response: Thank you for your comment. The SDT believes that the definition of “active transmission line right-of-way” is appropriate for meeting the
objectives of the Standard. This topic will be covered in the technical reference document which will be issued with the next draft of the Standard.
Hydro One Networks Inc.
September 8, 2009
Disagree
We agree in changing the text as proposed only if R1 is expanded as suggested below. The standard as written is
primarily, if not exclusively focused on outage prevention through one means, to keep vegetation out of the
Critical Clearance Zone. The burden to accomplish this is placed on the Transmission Owner/Operator as it
should be. The first section highlights that a program is required, but does not provide a requirement above this
simplistic view, and from our perspective the Measures do not introduce any further rigour. This simplistic
approach, in our opinion, does not adequately address the reliability risks associated with the various
methodologies of managing vegetation. The White Paper notes removal is superior to pruning in ensuring tree
conflicts do not occur. The White Paper includes elements of vegetation management risks, but the revised
standard for the most part excludes this issue. One could argue that the audits and fines will manage reliability
risks, but we are not convinced that this will do so in a consistent and adequate manner. There are numerous
clearance risk factors associated with managing vegetation on rights of way. Some of these are: accurate
measurement of conductor sag, accurate measurement of vegetation, vegetation growth rate, conductor sway,
tree movement. If one looks at Table 1, the Clearance Distances are to the nearest cm or 1/100 of a foot. This
makes one wonder, how realistic are the expectations laid out in the standard? To manage the risks around the
Critical Clearance Zone the Standard requires each Transmission Owner to work with these precise numbers and
build in a margin of safety to manage the situation. Will each Transmission Owner use identical criteria to trigger
work? This doubtful, so this leads one to believe that the standard has not been designed to produce consistent
results, which in our opinion is the case. So one has varied field conditions that are difficult to nail down, precise
clearance requirements to the nearest 1/100? and the likelihood of inconsistent margins of safety. We realize that
the audit process will help to assess these situations, but it may not be enough to achieve a somewhat uniform
risk profile across the transmission systems. Other standards that we are familiar with include a margin of safety
such as added clearance above the absolute minimum recognizing that it may not be practical to work to such
precise measures. Examples of standards that use this approach to ensure consistent and reliable results include
OHSA and the Canadian Standards Association. We are not advocating that this standard follows an identical
approach, but do want to highlight that the standard may fall short in the area of managing vegetation
management risks which in turn have a direct impact on reliability. Considering the above, it is suggested that the
aspect of managing vegetation reliability risks be added to the White Paper to allow Transmission Owners to
develop somewhat consistent criteria. Further on the topic of managing risk. We believe that reliability risks are
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 3 Comment
directly related to the amount of incompatible vegetation on a right of way that is approaching the Critical
Clearance Zone. Incompatible vegetation would be vegetation that has the potential to grow into the Critical
Clearance Zone at full growth. We suggest that risks could be reduced significantly by including direction in the
standard concerning the management of incompatible vegetation. This would drive a greater degree of
consistency among Transmission Owners and would reduce the amount of vegetation on rights of way that have
the potential to cause flashover. In addition, this would reinforce the reliability risks associated with vegetation,
not just from a clearance perspective but also from a volume perspective, and would provide a more
comprehensive view for the public and interest groups. In order to respond to what we consider a shortcoming of
the proposed standard, our suggestion would be to expand R1.1 similar to the following:
Specify the methodologies that the Transmission Owner uses to control vegetation and demonstrate that the
removal of non-compatible vegetation is a focus within the plan. It is recognized that reliability risks increase
appreciably with an increase in incompatible vegetation on an active right of way, and the Transmission Owner is
required to remove incompatible vegetation at a point no later in time when it poses a threat to the reliability of the
transmission line. Exceptions include vegetation used for designated visual screens, trees of a historic
significance, vegetation to control erosion, agreements made at the time of environmental approval for
construction,???etc.
Response: Thank you for your comments. The SDT revised the standard so that it no longer references the “Critical Clearance Zone.” The SDT chose,
in the revised standard, to use the term “methods” as a more global, all encompassing term that allows transmission owners flexibility in developing
their Transmission Vegetation Management Program. ANSI A300 has been referenced as a best management practice by reference as a footnote to R1.1.
Moreover, we believe the Standard as subsequently revised provides flexibility for Transmission Owners to develop their own vegetation management
programs. But we are sensitive to the issues you raised and have tried to define through the subsections in R1 that specific elements are necessary.
CenterPoint Energy
September 8, 2009
Disagree
The term "Active Transmission Line Right-of-way" is not defined in sufficient detail in the Definition of Terms Used
in the Standard section to know how to apply the Requirements. The term causes a circular reference problem
with the term "Critical Clearance Zone" that refers to the "limits of the Active Transmission Line Right-of-way"
which has no specific definition as to its limits within the proposed revised Standard. There is an attempt to
differentiate between the "Total R.O.W." and the "Active R.O.W." portion by using the phrase "occupied by active
transmission facilities", but no specific limits of such occupation are included within the definition. Are "active
transmission facilities" only the physical energized conductors as-is, where-is? Does "occupied" include the
conductor vertical and horizontal movement envelope and any horizontal and vertical electrical clearance as well?
Does the term "Active Transmission Line Right-of-way" refer to the legal limits of the right-of-way? The new R9
includes the phrase "within the extent of its easement and/or legal rights" which seems to support that definition.
The phrase "a strip of land" seems to refer to a metes and bounds description, but how is that relevant when no
specific land space is defined, such as with a railroad occupation or Corp of Engineer's permit? On page 16 of the
Technical Reference, there is a reference to the Bramble and Byrnes wire-border zone technique. The wire zone
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Question 3 Comment
is defined in the Technical Reference as "the section of a utility transmission right-of-way directly under the wires
and extending outward about 10 feet on each side". Are the limits of the "Active Transmission Line Right-of-way"
intended to be equivalent to the Bramble and Byrnes wire zone, or is the Transmission Owner to use its discretion
to define the limits? The examples in the Technical Reference document do not define the limits of the "active
transmission facilities" either. The "Active R.O.W." limit in Figure 1 and Figure 3 is arbitrary. Figure 2 is supposed
to display an edge zone for vegetation to exist, which implies an "Inactive R.O.W" portion, but no such zone is
defined. Figure 1 also has trees shown inside the "Total R.O.W." and within the "Inactive R.O.W." that are tall
enough and close enough to be within falling distance of the active transmission line which seems averse to R7
for vegetation falling into a conductor when the Transmission Owner likely has legal rights to remove them if they
are within the "Total R.O.W." and are within falling distance. The interpretation of M7 will be difficult in this case
without a specific method to define the "Active R.O.W." portion of the Total R.O.W. We recommend deleting the
confusing terms "Active Transmission Line Right-of-way and "Critical Clearance Zone" and returning to the prior
Clearance 2 Requirement with the newly specified minimum clearances from Table I of Attachment 1 as an
alternative approach should the definition of minimum vegetation clearance distances remain integral to the
Standard.
Response: Thank you for your comments. The Critical Clearance Zone concept has been removed from the latest draft of the Standard. While the SDT
believes that the definition of “active transmission line right-of-way” in the Standard is appropriate, this concept will be further reviewed by the SDT in
the context of the technical reference and your comments. And we agree that a further explanation is required to eliminate questions like the ones you
raised. The new examples in the technical reference should eliminate that ambiguity.
JEA
Disagree
The standard should EITHER require an entity to have and follow a program OR hold an entity to performance
standards, but not both. Requiring a procedure in conjunction with performance requirements incents the entity to
write procedures that meet only the minimum requirements of the standard, as they will be audited and held
accountable for what is documented and performance against that. If performance requirements are in place
without the concurrent requirement for a procedure, then the entity is incented to develop procedures that meet
best practices in order to assure that they will meet or beat the performance standards, because in this scenario,
such procedures do not expose the entity to additional compliance risk while enhancing reliability.
Response: Thank you for your comment. The Standard provides the framework for Transmission Owners to develop and implement an effective
transmission vegetation management program in support of the main reliability objective: preventing sustained outages of transmission lines that could
lead to cascading. During the drafting process, many members of the drafting team asserted that several of the requirements are merely facilitative in
nature and would be unnecessary if sustained outages are successfully prevented. Because this standard is relatively new compared to standards that
were developed from operating policies that had been followed for decades, there is a sense that the benefits of "defense in depth" (keeping the
facilitating requirements) may be warranted until entities have more experience with mandatory vegetation management.
September 8, 2009
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Salt River Project
Agree?
Disagree
Question 3 Comment
R1.1 states "Specify the methodologies that the Transmission Owner uses to control vegetation". The word
"methodologies" does not adequately replace "objectives, practices, approved procedures, and work
specifications". Recommend to keep the original wording.
Response: Thank you for your comments. The SDT chose “methods” in R1 part 1.1 to provide flexibility for Transmission Owners to develop their own
vegetation management programs. ANSI A300 has been referenced as a best management practice in a footnote to 1.1. The Technical Reference
Document provides examples of the variations in methods that are necessary due to the wide diversity of vegetation across North America.
Hydro-Quebec Transenergie
(HQT)
Disagree
While we agree with the suggested changes for the terms proposed , we believe that the Transmission Vegetation
Management Program should be focused on removal of incompatible vegetation from the Active Right of
Way.R1.1 could read: Specify the methodologies that the Transmission Owner uses to control vegetation and
demonstrate that the removal of non-compatible vegetation is a focus within the plan. Incompatible vegetation
should be defined as any vegetation which has the potential to grow tall enough to jeopardize the integrity of an
applicable transmission line by growing into the Critical Clearance Zone or falling into the Critical Clearance
Zone . This would provide clear guidance to all stakeholders, support long term vegetation management
philosophies, and complement methods such as IVM where incompatible vegetation is completely removed, and
compatible vegetation is encouraged to proliferate, thereby helping to control incompatible vegetation in an
environmentally positive manner.
Response: Thank you for your comments. The SDT has re-written this Requirement to address your concerns in a manner that allows transmission
owners flexibility in developing their Transmission Vegetation Management Program. ANSI A300 has been referenced as a best management practice by
reference as a footnote to R1.1. Moreover, we believe the Standard as subsequently revised provides flexibility for Transmission Owners to develop
their own vegetation management programs.
Western Area Power
Administration, Upper Great
Plains Region
Agree
A question that has surfaced during discussions within the industry is "Can the Transmission Owner designate an
active R/W width that is less than the easement width even with a single-circuit line with no R/W set aside for
vegetation buffer or future development?" OR, does the easement width equate to "Active T-Line ROW" under
the situation described above.
Response: Thank you for your comment. The intent of the Standard is that such rights-of-way as identified in your response are considered as “active
transmission rights-of-way” in general for their full width. The definition of “active transmission line right-of-way” was developed to recognize that in
some cases additional ROW width was secured to allow for buffers and future expansion. This is further described in the technical reference document.
Western Utility Arborists
September 8, 2009
Agree
Yes, we agree, subject to the qualification about “active” rights-of-way under Comment #16. Under R1.1, it says
“Specify the methodologies that the Transmission Owner uses to control vegetation.” The single word
“methodologies” does not adequately replace “objectives, practices, approved procedures, and work
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Question 3 Comment
specifications.” The Western Utilities recommends keeping the original wording. We would also like to point out
that the original intent of the standard was to ensure that utilities had a complete vegetation management
program. The new standard is evolving towards an outage control program, and no longer encourages programs
or behaviors that would ensure the causes of outages are prevented long before they become a problem. The
standard now redirects efforts to avoiding outages instead of managing vegetation.
Response: Thank you for your comments. The SDT has re-written this Requirement to address your concerns in a manner that allows transmission
owners flexibility in developing their Transmission Vegetation Management Program. ANSI A300 has been referenced as a best management practice by
reference as a footnote to R1.1. Moreover, we believe the Standard as subsequently revised provides flexibility for Transmission Owners to develop
their own vegetation management programs. The SDT believes that the latest draft includes Requirements that dictate appropriate behavior in
controlling vegetation but also added a strong statement that outages, that could have been prevented, are inconsistent with interconnection reliability
and should be violations.
Southern California Edison
Company
Agree
Q3: No Comments.
Response: Thank you for your response.
FirstEnergy
Agree
The Inactive Right of Way, by definition, should include a strip of trees on each side of the of the right of way that
was purchased, but not cleared at the time of construction. This could be a narrow strip ten feet on each side that
is intended for future hazard tree removal.
Response: Thank you for your comment. The definition of “Active Transmission Line Right-of-Way” has been modified in the current draft of the
Standard. The SDT believes that the definition of “Active Transmission Line Right-of-Way” as currently defined is appropriate. The definition was
developed to recognize that in some cases additional ROW width was secured to allow for buffers and future expansion. This is further described in the
technical reference document. However, the SDT does not agree that a categorical “set aside” which is not active but can be is appropriate for all
Transmission Owners. Rather, some Transmission Owners may want to manage the entire rights-of-way. But flexibility is permitted within the current
draft.
MRO NERC Standards Review
Subcommittee
Agree
The MRO agrees but requests further clarification on the definition of the term "Active" in Active Transmission
Line R.O.W. For example: A utility has a 150 foot easement for a 230kV line and currently manages 80 feet. First;
is it the intent of the standard that the utility manage the entire 150 foot easement? Second; is the entire
easement considered the Active Transmission Line R.O.W?
Response: Thank you for your comment. The Transmission Owner is responsible for determining the Active ROW width based upon the definition of
“active transmission line right-of-way” included in the Standard. The scenario presented in your comment does not provide enough information for the
September 8, 2009
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Organization
Agree?
Question 3 Comment
SDT to provide a definitive answer. The definition of “Active Transmission Line Right-of-Way” has been changed in the most current draft. In addition a
technical reference document with a more detailed explanation of this topic will be issued with the next draft. These documents should provide clarity.
The definition was developed to recognize that in some cases additional ROW width was secured to allow for buffers and future expansion. This is
further described in the technical reference document. However, the SDT does not agree that a categorical “set aside” which is not active but can be is
appropriate for all Transmission Owners. Rather, some Transmission Owners may want to manage the entire rights-of-way. But flexibility is permitted
within the current draft.
ITC HOLDINGS
Agree
The standard doesn't actually explain or define the Active Transmission Line Right of Way.
Response: Thank you for your comment. A definition of “Active Transmission Line ROW” is included in the Standard. This definition has been modified
in the most current draft of the Standard. The technical reference will provide further clarity.
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 3
Response: Thank you for your comment.
American Electric Power (AEP)
Agree
While Requirement R1 does not actually define "Active Transmission Line Right of Way" (it is defined on page 2
of the Standard), AEP concurs with R1, except as noted below for R1.4.
Response: Thank you for your comment.
Platte River Power Authority
Agree
The list of terms, "objectives, practices, approved procedures and work specifications," from version 1 provides
more clarity that the one word "methodology" and should both be replaced. The newly defined term "active
transmission line ROW" provides clarity to the portion of the ROW requiring vegetation management and is a
valuable addition to the standard.
Response: Thank you for your comment. The SDT revised R1.1 to allow transmission owners the necessary flexibility in developing their Transmission
Vegetation Management Program. ANSI A300 has been referenced as a best management practice by reference as a footnote to R1.1.
American Transmission
Company
Agree
We agree with the idea but the term "active transmission facilities" needs additional clarity. This clarity could be
accomplished with a footnote. Proposed Footnote: A transmission facility that contains a transmission line to
which FAC-003 is applicable. The proposed footnote aids in the identification of applicable transmission facilities.
Response: Thank you for your comment. Applicable lines are defined in Section 4 of the Standard.
September 8, 2009
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Organization
Agree?
USDA Forest Service,
Agree
Southwestern Region, Regional
Office for AZ and NM
Question 3 Comment
My disagreement with R1
Response: Thank you for your comment; however the SDT does not understand your comment.
National Grid
Agree
Defining "Active Transmission Line Right-of-Way" solves the Right-of-Way definition problem within the SAR.
Response: Thank you for your comment.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Agree
Yes, we agree, subject to the qualification about “active” rights-of-way under Comment #16. We would also like to
point out that the original intent of the standard was to ensure that utilities had a complete vegetation
management program. The new standard is evolving towards an outage control program, and no longer
encourages programs or behaviors that would ensure the causes of outages are prevented long before they
become a problem. Instead, it redirects efforts to avoiding outages instead of managing vegetation. If this is now
the preferred approach, the term Transmission Vegetation Management Program is no longer valid and should
perhaps be changed to the Transmission Vegetation Outage Prevention Program. Under R1.1, it says “Specify
the methodologies that the Transmission Owner uses to control vegetation.” The single word “methodologies”
does not adequately replace “objectives, practices, approved procedures, and work specifications.” We
recommend that the SDT retain the original wording.
Response: Thank you for your comments. The SDT revised R1.1 to allow transmission owners the necessary flexibility in developing their Transmission
Vegetation Management Program. ANSI A300 has been referenced as a best management practice by reference as a footnote to R1.1. The SDT believes
that the latest draft includes Requirements that dictate appropriate behavior in controlling vegetation but also added a strong statement that outages,
that could have been prevented, are inconsistent with interconnection reliability and should be violations.
San Diego Gas & Electric
Agree
Yes, we agree, subject to the qualification about "active" rights of way under comment 16. Under R1.1 it says
"Specify the methodologies that the Transmission Owner uses to control vegetation." The single word
"methodologies" does not adequately replace "objectives, practices, approved procedures, and work
specifications." We recommend keeping the original wording.
Response: Thank you for your comment. The SDT revised R1.1 to allow transmission owners the necessary flexibility in developing their Transmission
Vegetation Management Program. ANSI A300 has been referenced as a best management practice by reference as a footnote to R1.1.
Northeast Utilities
September 8, 2009
Agree
With respect to "active transmission line ROW" the examples provided in the Technical Reference document for
FAC-003-2 show that any areas of the easement or fee-owned right-of-way not cleared in accordance with
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Agree?
Question 3 Comment
company approved design standards will not be considered "active transmission line ROW". Any vegetation
contacts resulting from trees that fail in these non-cleared sections ("corridor edge zones") would not constitute a
violation of FAC-003-2.The definition of the "active transmission line right-of-way" states that this does not include
areas of the easement or fee-owned property that is unused or inactive and intended for other facilities. Does this
imply that areas not cleared and not intended for other facilities are part of the active right-of-way? If a company
had constructed new lines and allowed for a buffer strip of the easement that was not cleared, but is also not
intended for new facilities, and trees are allowed to remain in this strip - that an outage from contact with a tree
falling into the lines from this buffer would constitute a violation of R7 as a tree falling from within the active rightof-way? Does this imply that trees in these buffer strips must be removed? This will constitute a very costly and
problematic position that will result in extreme adverse public opposition to the required clearing. It is suggested
that the clearing limits of any right-way comply with some established standards or codes. A utility should not be
allowed to eliminate a large number of vegetation violations by simply decreasing the size or width of the active
right-of-way. However, this may also need to be flexible when new lines are constructed when easement widths
are limited due to local or state requirements.
Response: Thank you for your comments. The definition of “Active Transmission Line Right-of-Way” has been modified in the current draft of the
Standard. The SDT believes that the definition of “Active Transmission Line Right-of-Way” as currently defined is appropriate. The definition was
developed to recognize that in some cases additional ROW width was secured to allow for buffers and future expansion. This is further described in the
technical reference document. The new section in the technical reference attempts to address these issues.
Buckeye Power, Inc.
Agree
OK with R1. However, the active transmission line right of way seems to be a reduction in ROW width which
would likely decrease reliability during the one moment when we need it most.
Response: Thank you for your comment. The “active transmission line right-of-way” definition has been developed to address rights-of-way obtained
for future facilities. It is not intended to diminish the Transmission Owners’ responsibility to manage vegetation on a right-of-way which was acquired
solely for the purpose of the subject line and is necessary for the reliable operation of the line.
Great River Energy
Agree
GRE agrees but requests further clarification on the definition of the term "Active" in Active Transmission Line
R.O.W. For example: A utility has a 150 foot easement for a 230kV line and currently manages 80 feet. First; is it
the intent of the standard that the utility manage the entire 150 foot easement? Second; is the entire easement
considered the Active Transmission Line R.O.W?
Response: Thank you for your comment. The Transmission Owner is responsible for determining the Active ROW width based upon the definition of
“active transmission line right-of-way” included in the Standard. The scenario presented in your comment does not provide enough information for the
SDT to provide a definitive answer. The definition of “Active Transmission Line Right-of-Way” has been changed in the most current draft. In addition a
technical reference document with a more detailed explanation of this topic will be issued with the next draft. These documents should provide clarity.
September 8, 2009
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BCTC
Agree?
Agree
Question 3 Comment
Yes, we agree, subject to the qualification about “active” rights-of-way under Comment #16.
We would also like to point out that the original intent of the standard was to ensure that utilities had a complete
vegetation management program. The new standard is evolving towards an outage control program, and no
longer encourages programs or behaviours that would ensure the causes of outages are prevented long before
they become a problem. Instead, it redirects efforts to avoiding outages instead of managing vegetation. If this is
now the preferred approach, the term Transmission Vegetation Management Program is no longer valid and
should perhaps be changed to the Transmission Vegetation Outage Prevention Program.
Under R1.1, it says “Specify the methodologies that the Transmission Owner uses to control vegetation.” The
single word “methodologies” does not adequately replace “objectives, practices, approved procedures, and work
specifications.” BCTC recommends keeping the original wording.
Thank you for your comments. The SDT revised R1.1 to allow transmission owners the necessary flexibility in developing their Transmission Vegetation
Management Program. ANSI A300 has been referenced as a best management practice by reference as a footnote to R1.1. The SDT believes that the
latest draft includes Requirements that dictate appropriate behavior in controlling vegetation but also added a strong statement that outages, that could
have been prevented, are inconsistent with interconnection reliability and should be violations.
WECC Reliability Coordination
Agree
SERC Vegetation Management
Subcommittee (VMS)
Agree
Progress Energy Florida
Agree
Kansas City Power & Light
Agree
Agree
Western Area Power
Administration, Rocky Mountain
Region
Progress Energy Carolinas
Agree
SERC OC Standards Review
Group
Agree
September 8, 2009
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Agree?
Florida Power & Light
Agree
Santee Cooper
Agree
Southern Company
Agree
E.ON U.S.
Agree
Midwest ISO Stakeholders
Standards Collaborators
Agree
SERC Compliance Staff
Agree
Exelon
Agree
Central Maine Power Company
Agree
City of Tallahassee
Agree
Northern California Power
Agency (NCPA)
Agree
Tampa Electric Company
Agree
Orange and Rockland Utilities
Inc.
Agree
Ameren
Agree
Nebraska Public Power District
Agree
Long Island power Authority
Agree
Manitoba Hydro
Agree
September 8, 2009
Question 3 Comment
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Organization
Agree?
Consumers Energy Company
Agree
Pacific Gas & Electric Co.
Agree
Edison Electric Institute
Agree
Consolidated Edison Company
of New York (CECONY)
Agree
WECC
Agree
Arizona Public Service
Company
Agree
Duke Energy Corporation
Agree
Entergy Services
Agree
Pepco Holdings, Inc
Agree
September 8, 2009
Question 3 Comment
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
4. Documentation and implementation of the transmission vegetation management program which were previously
combined in Requirement R1 are now separated in order to apply appropriate VRFs and time horizons. The
implementation of some elements has been moved into standalone requirements such as inspection cycles (R3) and
annual plan implementation (R9). Do you agree with these revisions and separation? If not, please explain.
Summary Consideration: Most respondents were in favor of separating the documentation from the implementation. A
minority of the respondents wanted to keep the two together. The SAR directed the team to bring the standard into
conformance with the latest version of the Sanctions Guidelines. Retention of documentation to demonstrate compliance is now
addressed, in most cases, solely in the “Data Retention” section of standards and does not need to be covered in requirements.
If an entity does not retain data and there is no impact to reliability, then the retention of that data, if needed to demonstrate
compliance, is covered under the Data Retention section.
Some respondents advocated modifying the order or sequence of the standard’s requirements. The SDT has considered various
sequence options and offers a re-sequencing proposal as Question #12 in the second Comment Form.
Organization
BCTC
Agree?
Question 4 Comment
Although it’s important to have these two separate aspects – documentation and implementation – separating
them spatially in the document itself makes the standard longer than necessary and creates redundancy. It
seems obvious that if you prepare elements of the Transmission Vegetation Management Program, they also
need to be implemented. The document would be easier to follow if the two elements were kept together.
Response: The SDT thanks you for your comments. The SDT determined that the requirements to document and implement are distinctly different
activities and therefore separated them. Having separate requirements allows for assignment of VRF’s and VSL’s that more closely reflect their
respective characteristics. The SDT has considered various sequence options and offers a re-sequencing proposal as Question #12 in the second
Comment Form.
Western Utility Arborists
Although it’s important to have these two separate aspects “documentation and implementation “separating
them spatially in the document itself makes the standard longer than necessary and creates redundancy. It
seems obvious that if you prepare elements of the Transmission Vegetation Management Program, they also
need to be implemented. The document would be easier to follow if the two elements were kept together.
Response: The SDT thanks you for your comments. The SDT determined that the requirements to document and implement are distinctly different
activities and therefore separated them. Having separate requirements allows for assignment of VRF’s and VSL’s that more closely reflect their
respective characteristics. The SDT have considered various sequence options and offer a re-sequencing proposal as Question #12 in the second
September 8, 2009
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Organization
Agree?
Question 4 Comment
Comment Form.
Progress Energy Florida
Disagree
The sub-requirements should be moved up to requirement level if the team desires to have different VRFs and
VSLs.
Response: The SDT thanks you for your comments. The Standards drafting team has dropped the sub requirement designations and the sub parts are
simply listed as part of R1.
Progress Energy Carolinas
Disagree
The sub-requirements should be moved up to requirement level if the team desires to have different VRFs and
VSLs.
Response: The SDT thanks you for your comments. The Standards drafting team has dropped the sub requirement designations and the sub parts are
simply listed as part of R1.
Southern California Edison
Company
Disagree
Q4: SCE does not agree with separating the documentation and implementation aspects of the Transmission
Vegetation Management Program into separate requirements R3 and R9 (respectively). SCE believes that
proposed R3 and corresponding M3 should be eliminated and replaced with a modified version of proposed
R9. SCE respectfully suggests that proposed R9 be revised to read: "Each Transmission Owner shall
implement and follow its Vegetation Management Program to the extent allowed by existing easement and/or
legal rights."
Response: The SDT thanks you for your comments. The team believes that conducting inspections is independently important and therefore should be
addressed in a separate requirement. The SDT debated the issue of whether to include "Each Transmission Owner shall implement and follow its
Vegetation Management Program to the extent allowed by existing easement and/or legal rights". The final consensus of the SDT was to exclude the
requirement because having the legal rights do not imply one is obligated to exercise those rights to their fullest extent. The SDT did not want to give
that impression.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Disagree
Although it’s important to have these two separate aspects “ documentation and implementation “ separating
them spatially in the document itself makes the standard longer than necessary and creates redundancy. It
seems obvious that if you prepare elements of the Transmission Vegetation Management Program, they also
need to be implemented. The document would be easier to follow if the two elements were kept together.
Response: The SDT thanks you for your comments. The SDT determined that the requirements to document and implement are distinctly different
activities and therefore separated them. Having separate requirements allows for assignment of VRF’s and VSL’s that more closely reflect their
respective characteristics. The SDT have considered various sequence options and offer a re-sequencing proposal as Question #12 in the second
Comment Form.
September 8, 2009
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Organization
San Diego Gas & Electric
Agree?
Disagree
Question 4 Comment
The document would be easier to follow if kept together. Separation of the recommendations and
implementation will make this a redundant process, because both will say the same thing.
Response: The SDT thanks you for your comments. The SDT determined that the requirements to document and implement are distinctly different
activities and therefore separated them. Having separate requirements allows for assignment of VRF’s and VSL’s that more closely reflect their
respective characteristics. The SDT considered other sequence options and offer a re-sequencing proposal as Question #12 in the second Comment
Form.
JEA
Disagree
See comment from #3.
Response: The SDT thanks you for your comments. See response to Q #3.
Salt River Project
Disagree
Although we agree that it is important to identify both aspects of the program for "prepare/documentation" and
"implementation", we do not agree that this needs to be documented in separate requirements. It makes the
standard longer than necessary and creates redundancy. The document would be easier to follow if the two
elements were kept together in the same requirement. In addition, it is not defined what is "VRFs". We
understand that this was detailed in a previous draft document as "Violation Risk Factor". This needs to be
defined and clarified in order to provide comment back.
Response: The SDT thanks you for your comments. The SDT determined that the requirements to document and implement are separate and require
different levels of VRF’s and VSL’s. The team refers you to the Sanction Guidelines of North American Electric Reliability Corporation to explain the
use of VRF’s and VSL’s.
CenterPoint Energy
Disagree
Additional revisions are needed to clarify the requirements. For instance, R1.3 refers to "the objectives" of the
Transmission Vegetation Management Program, which are no longer a required element and are not specified
in M1.3. Reference to "the objectives" should be deleted. The last sentence of R1.3 should read: "It shall use
the methodologies outlined in the transmission vegetation management program."R1.4 requires a process for
a response to an "imminent threat of a vegetation related Sustained Outage", but R2 refers to implementing an
"imminent threat procedure" to "prevent an encroachment of the Critical Clearance Zone". The requirement
and the implementation should both refer to an "imminent threat of a vegetation related Sustained Outage".
Response: The SDT thanks you for your comments. The team is posting a revised standard and R1 identifies the required elements of the
Transmission Vegetation Management Program. The sub requirements have been changed to elements that roll up into R1 and an additional element
has been added to cover methods used to control vegetation – the word, “objectives” is not used in the revised standard.
MRO NERC Standards Review
September 8, 2009
Agree
The MRO believes that clarity was improved by separating documentation and implementation. The MRO
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Organization
Agree?
Subcommittee
Question 4 Comment
suggests that moving the requirement for implementation so that it immediately follows the requirement for
documentation will further enhance clarity.
Response: The SDT thanks you for your comments. The SDT has considered various sequence options and offers a re-sequencing proposal as
Question #12 in the second Comment Form.
Midwest ISO Stakeholders
Standards Collaborators
Agree
This is a good change from a compliance perspective; the documentation requirements can now be assigned
lower VRFs than the implementation requirements.
Response: The SDT thanks you for your comments.
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 4
Response: The SDT thanks you for your comments.
Exelon
Agree
Refer to footnotes in R1.1 and 1.2. Are applicable entities to be held accountable to ANSI A300 (footnote 2)
and for providing documentation to support analysis that "local factors" were accounted for (footnote 3)?
These footnotes should be requirements or they should be removed and included in a Reference Document
not subject to compliance audit.
Response: The SDT thanks you for your comments. Please note the phrase in the current version of footnote 2,” while not a requirement of this
standard.” A300 is a recommended best practice and not a requirement. Footnotes may be used to provide explanatory information.
American Electric Power (AEP)
Agree
AEP agrees with these changes from Version 1.
Response: The SDT thanks you for your comments.
Platte River Power Authority
Agree
The separation allows lower sanctions and penalties to be assessed for weak documentation and higher
sanctions and penalties to be assessed for weak inspection programs and weak vegetation management.
However, the standard would be easier to follow if the two elements were kept together in the document.
Response: The SDT thanks you for your comments. The SDT determined that the requirements to document and implement are separate and require
different levels of VRF’s and VSL’s. The SDT has considered various sequence options and offers a re-sequencing proposal as Question #12 in the
second Comment Form.
City of Tallahassee
September 8, 2009
Agree
See Question 6 and 17.
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 4 Comment
Response: The SDT thanks you for your comments. See the responses to Questions 6 and 17.
Northern Indiana Public Service
Company
Agree
I agree with the separation and re-ordering of documentation and implementation requirements into two
distinct groups. This is a welcome improvement to the standard.
Response: The SDT thanks you for your comments. The SDT has considered various sequence options and offers a re-sequencing proposal as
Question #12 in the second Comment Form.
National Grid
Agree
These revisions and separation make it easier to match requirements and measures.
Response: The SDT thanks you for your comments.
Ameren
Agree
This is a good change from a compliance perspective; the documentation requirements can now be assigned
lower VRFs than the implementation requirements
Response: The SDT thanks you for your comments.
Duke Energy Corporation
Agree
This is a good change from a compliance perspective; the documentation requirements can now be assigned
lower VRFs than the implementation requirements.
Response: The SDT thanks you for your comments
Great River Energy
Agree
GRE believes that clarity was improved by separating documentation and implementation. GRE suggests that
moving the requirement for implementation so that it immediately follows the requirement for documentation
will further enhance clarity
Response: The SDT thanks you for your comments. The SDT has considered various sequence options and offers a re-sequencing proposal as
Question #12 in the second Comment Form.
Associated Electric Cooperative
Inc.
Agree
NPCC
Agree
WECC Reliability Coordination
Agree
September 8, 2009
55
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Western Area Power
Administration, Upper Great
Plains Region
Agree
SERC Vegetation Management
Subcommittee (VMS)
Agree
Kansas City Power & Light
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
SERC OC Standards Review
Group
Agree
Florida Power & Light
Agree
Santee Cooper
Agree
Southern Company
Agree
E.ON U.S.
Agree
Bonneville Power Administration
Agree
FirstEnergy
Agree
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
Central Maine Power Company
Agree
Northern California Power Agency
Agree
September 8, 2009
Question 4 Comment
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 4 Comment
(NCPA)
Tampa Electric Company
Agree
Orange and Rockland Utilities Inc.
Agree
American Transmission Company
Agree
Nebraska Public Power District
Agree
Long Island power Authority
Agree
USDA Forest Service,
Southwestern Region, Regional
Office for AZ and NM
Agree
Manitoba Hydro
Agree
Consumers Energy Company
Agree
Pacific Gas & Electric Co.
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
Consolidated Edison Company of
New York (CECONY)
Agree
WECC
Agree
Arizona Public Service Company
Agree
Baltimore Gas & Electric
Company
Agree
September 8, 2009
57
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Entergy Services
Agree
Pepco Holdings, Inc
Agree
Independent Electricity System
Operator
Agree
Northeast Utilities
Agree
Hydro-Quebec Transenergie
(HQT)
Agree
Buckeye Power, Inc.
Agree
September 8, 2009
Question 4 Comment
58
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
5. In R1.2 the Transmission Owner is required to have an inspection frequency of at least once per calendar year. Do you
agree with R1.2? If not, please explain.
Summary Consideration: The majority of the respondents were in favor of the one year frequency. Most of the minority
commenters wanted to leave the decision with the Transmission Owner. Since vegetation inspections can be included in
overhead maintenance inspections, the SDT did not consider the annual inspection requirement to be burdensome. Several
commenters asked for a definition of “inspection” and the SDT is proposing the following modification to an existing NERC
Glossary definition of “Vegetation Inspection:”
Vegetation Inspection: The systematic examination of vegetation conditions on an Active Transmission Line Right of Way.
This inspection may be combined with a general line inspection. The inspection includes the documentation of any vegetation
that may pose a threat to reliability prior to the next planned inspection or maintenance work, considering the current location
of the conductor and other possible locations of the conductor due to sag and sway for rated conditions.
Organization
BCTC
Agree?
Question 5 Comment
Clarification is required on exactly what an inspection is, which should perhaps be outlined in the white paper. At
BCTC although all lines are currently inspected at least once every year the thoroughness of the inspection will vary
with the local conditions. Some areas with limited vegetation management issues only require a patrol from the air
and are often inspected as part of a routine line patrol, where the lineman looks for vegetation concerns in addition to
undertaking maintenance work. Other areas require a detailed ground inspection. BCTC needs some assurance that
this inspection will not constitute a dedicated, comprehensive vegetation management inspection of the entire
operating system. . Therefore, BCTC needs the ability within the Transmission Vegetation Management Program to
define what an inspection is in the context of our utility operations.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections. The SDT
revised the NERC glossary term Vegetation Inspection to allow it to be combined with other line inspections.
Western Utility Arborists
September 8, 2009
Clarification is required on exactly what an inspection is, which should perhaps be outlined in the white paper. There
are areas where inspections are not necessary at all, such as lines over a parking lot, or in a remote desert area. The
Western Utilities need some assurance that this inspection will not constitute a dedicated, comprehensive vegetation
management inspection. Inspections are currently often part of a routine line patrol, where the lineman looks for
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 5 Comment
vegetation concerns in addition to undertaking maintenance work. Therefore, the Transmission Owner needs the
ability within their Transmission Vegetation Management Program to define what an inspection is in the context of
their utility operations.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections. The SDT
revised the NERC glossary term Vegetation Inspection to allow it to be combined with other line inspections.
Associated Electric
Cooperative Inc.
Disagree
While Associated Electric Cooperative Inc agrees with this requirement in general, there may be areas (e.g. highly
arid terrain, open water, etc.) where an annual interval is unnecessary and adds little or nothing to reliability.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
NPCC
Disagree
There were differing opinions within the group. Those entities with extensive overhead transmission felt the once a
year requirement was overly prescriptive and would not improve reliability, others were in agreement with the "at least
once per calendar year" requirement.
Response: The SDT thanks you for your comments. The consensus of the SDT is that annual inspections add to the reliability of the system.
Tennessee Valley Authority
Disagree
TVA suggests that R1.2 be changed by adding "except in cases where lines or significant sections of lines are over
terrain which is void of vegetation(such as bodies of deep water)or over terrain void of any vegetation that can grow
to a mature height that could threaten the conductors, then longer cycles will be acceptable". This would avoid
unnecessary expenses in such cases.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
Western Area Power
Administration, Rocky
Mountain Region
Disagree
Some areas such as highly developed urban areas, deserts, or grassland prairie may not be conducive to tall
vegetation growth and require frequent (annual) inspection.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
September 8, 2009
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Southern California Edison
Company
Agree?
Disagree
Question 5 Comment
Q5: SCE does not agree with imposing a one-size-fits-all inspection frequency of ?at least once per calendar year?
upon all U.S. Transmission Owners. The associated technical paper presents no credible evidence or statistical
corroboration to support the proposed inspection frequency. Until such time as a thorough industry study or similar
evidence is presented that demonstrates the proposed inspection frequency is cost effective and will enhance system
reliability, Transmission Owners should be allowed to establish their own inspection frequency rate. Regarding the
enforcement of a non-standardized inspection frequency, should a Transmission Owner incur a vegetation-to-line
contact that results in a Sustained Outage, upon review of the investigation results, the responsible Reliability
Coordinator and/or NERC could then impose a more stringent inspection frequency requirement upon the infracting
Transmission Owner. The imposition of more stringent inspection frequencies could be applied on a temporary or
permanent basis, depending on the severity of the outage, but lacking a demonstrated need, good performing
Transmission Owners should be allowed to establish their own inspection frequencies based upon their individual
needs and operating conditions. SCE respectfully suggests R1.2 be revised to read: "Specify a vegetation inspection
frequency that takes into account local and environmental factors."
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
SERC OC Standards Review
Group
Disagree
While the SERC OCSRG agrees with this requirement in general, there may be areas (e.g., desert terrain) where an
annual interval would be unnecessary and not cost effective.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
City of Tallahassee
Disagree
While TAL's specific conditions and current process would meet this requirement, I can envision where some
conditions may not require an annual inspection. These might include desert conditions, crop fields, over water, etc.
To dictate a specific one-year requirement could be burdensome to some utilities with no improvement to the
reliability of the BES.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
Xcel Energy
Disagree
Add a note of exception to the requirement for inspections on those lines that do not have vegetation management
issues (e.g. lines that traverse desert areas only).
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
September 8, 2009
61
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 5 Comment
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
Disagree
USDA Forest Service,
Southwestern Region,
Regional Office for AZ and NM
It would seem also that the T.O. should be expected to react to circumstances that create the need for a more
frequent inspection cycle such as conditions that cause widespread vegetation mortality such as drought and/or
beetle infestations.
Response: The SDT thanks you for your comments. The standard does restrict the number of inspections and does require the Transmission Owner to
examine the local and environmental conditions that might require a greater frequency.
Consumers Energy Company
Disagree
FERC required NERC in Order 693 to develop appropriate inspection cycles based on local factors. Potential annual
tree growth varies considerably within the geography of the United States and FAC-003-1 recognized this factor and
left it up to the utility to determine the most appropriate inspection cycle for their system. This was in lieu of having
proper data readily available to determine inspection cycles for various areas that could be incorporated into the
standard. FAC-003-2 greatly decreases the minimum separation distance between conductors and vegetation.
Table 1 shows the minimum distance at sea level for a 345 kV line a 3.12 feet. This is considerably less than the
potential annual growth rate of many tree species in many areas of the United States. Therefore, the annual
inspection cycle would not be acceptable to identify tree growth that can violate the minimum distance before it
occurs. Consumers Energy strongly believes that using the Gallet formula to determine the minimum clearance
between conductors and vegetation will decrease the reliability of the system compared to the minimum clearance
requirements in FAC-003-1.
Response: The SDT thanks you for your comments. The consensus of the SDT is that the frequency of inspection does not drive the minimum clearance
the Transmission Owner operates from. The SDT would expect the minimum clearance to be driven by growth rate and maintenance frequency.
National Grid
Disagree
R1.2, M1.2 and M1.3 in the Standard all refer to calendar year. National Grid objects to inspections being based on a
calendar year. Transmission Owners should be able to define their own "year". (See Question No. 18.)
Response: The SDT thanks you for your comments. By using “once per calendar year” the standard does not confine the inspection to a specific date.
This improves flexibility in the inspection schedule.
Hydro One Networks Inc.
September 8, 2009
Disagree
Clarification is required on the requirements. The frequency and need for inspection is based on a number of factors
that include: type of vegetation on a right of way, change in growing conditions and the Transmission Owner’s
clearance standards (i.e., if the clearance standards are well above the Critical Clearance then the risk to reliability
may be very low, so why inspect for vegetation clearances on an annual basis?) This being the case, clarification is
needed on inspection requirements relative to the overall approach used to manage vegetation clearances. For
example, Hydro One conducts routine line inspections on an annual basis and identifies clearance issues. Would this
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 5 Comment
meet the requirements of the standard?
Response: The SDT thanks you for your comments. Yes. The SDT added a definition for Vegetation Inspection to the standard.
NV Energy (fka Sierra Pacific / Disagree
Nevada Power Co.)
Clarification is required on exactly what an inspection is, which should perhaps be outlined in the white paper. There
are areas where inspections are not necessary at all, such as lines over a parking lot, or in a remote desert area. We
need some assurance that this inspection will not constitute a dedicated, comprehensive vegetation management
inspection. Inspections are currently often part of a routine line patrol, where the lineman looks for vegetation
concerns in addition to undertaking maintenance work. Therefore, the Transmission Owner needs the ability within
their Transmission Vegetation Management Program to define what an inspection is in the context of their utility
operations.
Response: The SDT thanks you for your comments. The SDT added a definition for Vegetation Inspection to the standard.
CenterPoint Energy
Disagree
The Standard and the Technical Reference provide no specific justification for defining a 1-year inspection frequency
and is arbitrary. The requirement itself does not take into account "local and environmental factors". Since the type
of inspection is not specified within the Standard, a frequency of at least once per calendar year is currently workable
for CenterPoint Energy, but it may not necessarily be appropriate for Transmission Owners with sparsely vegetated
service territories. The Technical Reference for R1.2 should state, "the Transmission Owner is given discretion as to
the inspection method", and "that while the inspection frequency is specified, it is not the intent of the Standard that all
vegetation be maintained on the same frequency". For example, CenterPoint Energy currently utilizes a 5-year
ground-based inspection cycle coupled with a 5-year cycle for vegetation maintenance, and performs a supplemental
annual aerial inspection.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations and this is explained in the Technical Reference. Vegetation inspections can be included in
overhead maintenance inspections. The SDT added a definition for Vegetation Inspection to the standard which would work provided you do your annual
flight.
Alberta Electric System
Operator
Disagree
The AESO believes that the inspection schedule should consider local and environmental factors that may impact the
anticipated growth rate of vegetation. In many of the areas in Alberta, due to cold climate and arid conditions, we
have slow vegetation growth rates. The requirement for minimum annual inspection is not necessary. We recommend
the inspection schedule be determined by the Transmission Owner and documented in its vegetation management
plan.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done at
September 8, 2009
63
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 5 Comment
least annually to cover both engineering and vegetation situations. A more frequent cycle may specified by the Transmission Owner to account for local
conditions. Slow growth rates, arid conditions etc. which may render an annual frequency unnecessary for Vegetation Inspections can be included in
overhead maintenance inspections.
Pepco Holdings, Inc
Disagree
While an annual inspection is reasonable and appropriate for all but very low precipitation areas, In Order 693, the
Commission directs the ERO to develop compliance audit procedures, using relevant industry experts, which would
identify appropriate inspection cycles based on local factors. The SDT does not seem to have taken the local factors
into account. FERC also does not want to leave this up to the Transmission Owners. While the standards being
developed are moving many things to the RC, PHI sees that as the only way to have someone other than the
Transmission Owner determine an inspection cycle that would consider local factors.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done at
least annually to cover both engineering and vegetation situations. A more frequent cycle may specified by the Transmission Owner to account for local
conditions. Slow growth rates, arid conditions etc. which may render an annual frequency unnecessary for Vegetation Inspections can be included in
overhead maintenance inspections.
Hydro-Quebec Transenergie
(HQT)
Disagree
The frequency and need for inspection is based on a number of factors that include: type of vegetation on a right of
way, rainfall during any given year, climate (very slow growth in nordic area), when the last removal of vegetation was
done, etc. HQT believes R1.2 is overly prescriptive when a “at least once a year” becomes mandatory; these terms
should be removed from the Standard.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done at
least annually to cover both engineering and vegetation situations. A more frequent cycle may specified by the Transmission Owner to account for local
conditions. Slow growth rates, arid conditions etc. which may render an annual frequency unnecessary for Vegetation Inspections can be included in
overhead maintenance inspections.
Bonneville Power
Administration
Agree
It would be helpful to clarify what is expected in regards to what constitutes an inspection. This could be done in the
technical reference. Some Transmission Operators inspect vegetation as part of line patrol that focuses on more
than just the condition of vegetation along the Right of Way. It should be clear that the Transmission Owner, though
required to complete a inspection frequency of at least once per calendar year, has the ability to implement the type
of inspection it deems necessary. Also the frequency of once per calendar year may create some unintended
reporting difficulties if Transmission Owners currently track progress and completion of inspections using a different
convention than calendar year, e.g., fiscal year or other period. It may be helpful to change the wording of R1.2 from
"at least once per calendar year" to "once in a twelve month period."
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
September 8, 2009
64
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 5 Comment
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
MRO NERC Standards
Review Subcommittee
Agree
The MRO suggests rewording the requirement to remove ". and environmental" . The MRO believes that local factors
includes environmental.
Response: The SDT thanks you for your comments. The SDT considers local conditions to account for design and operating situation and
environmental includes both the normal expected environmental conditions and changes from the norm such as drought major storms, fire etc.
SERC Vegetation
Management Subcommittee
(VMS)
Agree
While the SERC VMS agrees in general, there may be areas (i.e. desert terrain) where an annual interval would be
unnecessary and not cost effective.
Response: The SDT thanks you for your comments. The consensus of the SDT is that annual inspections add to the reliability of the system.
American Electric Power
(AEP)
Agree
AEP agrees with this change.
Response: The SDT thanks you for your comments.
Platte River Power Authority
Agree
The inspection frequency is reasonable.
Response: The SDT thanks you for your comments.
American Transmission
Company
Agree
We agree with a minimum inspection frequency, but believe that the additional verbiage "? that takes into account
local and environmental factors" should be deleted. The additional verbiage does not provide greater reliability only
more documentation. Proposed Language: Specify a vegetation inspection frequency of at least once per calendar
year.
Response: The SDT thanks you for your comments. The consensus of the SDT is that local and environmental factors might demand a greater frequency
than once per calendar year and vegetation inspections can be included in overhead maintenance.
Arizona Public Service
Company
September 8, 2009
Agree
Clarification is required on exactly what an inspection is, which should perhaps be outlined in the white paper. There
are areas where inspections are not necessary at all, such as lines over a parking lot, or in a remote desert area. APS
needs some assurance that this inspection will not constitute a dedicated, comprehensive vegetation management
inspection. Inspections are currently often part of a routine line patrol, where the forester or lineman looks for
vegetation concerns in addition to undertaking maintenance work. Therefore, the Transmission Owner needs the
65
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 5 Comment
ability within their Transmission Vegetation Management Program to define what an inspection is in the context of
their utility operations.
Response: The SDT thanks you for your comments. The SDT added a definition for Vegetation Inspection to the standard.
Pacific Gas & Electric Co.
Agree
This requirement is appropriate to ensure adequate inspection frequencies, however, a clear definition of "inspection"
should be contained in either the standard or white paper.
Response: The SDT thanks you for your comments. The SDT added a definition for Vegetation Inspection to the standard.
JEA
Agree
Although there are probably few areas where this is appropriate, the entity should be able to reduce the required
number of inspections with RC approval if they are able to demonstrate that vegetation conditions surrounding
transmission lines does not warrant inspections at that frequency.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
Salt River Project
Agree
The Transmission owner needs the ability to define what an inspection is in the context of their utility operation.
Inspections may not constitute a dedicated, comprehensive vegetation management inspection, but could often be
part of a routine line patrol, where linemen or engineers look for vegetation concerns in addition to undertaking
maintenance work. Clarification of that would be helpful, suggest that could be documented in the Technical
Reference document.
Response: The SDT thanks you for your comments. The SDT added a definition for Vegetation Inspection to the standard.
Great River Energy
Agree
GRE suggests rewording the requirement to remove ". and environmental" . GRE believes that local factors takes into
account environmental.
Response: The SDT thanks you for your comments. The SDT considers local conditions to account for design and operating situation and
environmental includes both the normal expected environmental conditions and changes from the norm such as drought major storms, fire etc.
San Diego Gas & Electric
September 8, 2009
Agree
The term "inspection" needs to be better defined, as well as the term "calendar year."
66
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Progress Energy Carolinas
Agree
Florida Power & Light
Agree
Santee Cooper
Agree
Southern Company
Agree
Question 5 Comment
WECC Reliability Coordination Agree
Western Area Power
Administration, Upper Great
Plains Region
Agree
Progress Energy Florida
Agree
Kansas City Power & Light
Agree
E.ON U.S.
Agree
FirstEnergy
Agree
Midwest ISO Stakeholders
Standards Collaborators
Agree
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
Exelon
Agree
Central Maine Power
Company
Agree
September 8, 2009
67
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Northern California Power
Agency (NCPA)
Agree
Northern Indiana Public
Service Company
Agree
Tampa Electric Company
Agree
Orange and Rockland Utilities
Inc.
Agree
Ameren
Agree
Nebraska Public Power
District
Agree
Long Island power Authority
Agree
Manitoba Hydro
Agree
Edison Electric Institute
Agree
Consolidated Edison
Company of New York
(CECONY)
Agree
WECC
Agree
Baltimore Gas & Electric
Company
Agree
Duke Energy Corporation
Agree
Entergy Services
Agree
September 8, 2009
Question 5 Comment
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Organization
Agree?
Independent Electricity
System Operator
Agree
Northeast Utilities
Agree
Buckeye Power, Inc.
Agree
September 8, 2009
Question 5 Comment
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
6. In R1.3 the Standard requires that transmission vegetation management program specify an Annual Plan and
specifies parameters for the plan. Implementation of the Annual Plan is separated and placed in R9. Do you agree
with R1.3 and the separation of the implementation from the specification of the Annual Plan? If not, please explain.
Summary Consideration: The majority of the respondents are in favor of the changes. There was a minority of the
respondents that made a valid point that elements in the annual plan were lost in the posting. The SDT determined that the
requirement to document and implement are separate and require different levels of VRF’s and VSL’s. The SDT chose a
compromise wording to accommodate those points.
Organization
BCTC
Agree?
Question 6 Comment
The document would benefit from keeping the two requirements together, since they relate to the same topic.
Under the new wording in R1, the Transmission Vegetation Management Program no longer has a requirement to
include objectives. However, there is a phrase in R1.3 to “support the objectives…and methodologies…outlined in
the…program.” To be consistent with R1.3, BCTC recommends that R1.1 be reworded to specify the
methodologies and objectives that the Transmission Owner uses to control vegetation.
Response: The SDT thanks you for your comments. However, the SDT determined that the requirements to document and implement should be
separate and require different levels of Violation Risk Factors and Violation Severity Levels. Thus, the SDT respectfully does not adopt your
suggestion to keep the two requirements together. The SDT also disagrees with returning “objectives” to R1. We do, however, agree that there exists
a small dichotomy since “objectives” are no longer stated in R1 while being referenced in part 1.3. Subsequently the SDT has removed this wording
from part 1.3. Further, the SDT has revised R1 to require the Transmission Owner to specifically describe how it will conduct work to comply with the
Standard in lieu of requiring the Transmission Owner to only identify general objectives.
Western Utility Arborists
The document would benefit from keeping the two requirements together, since they relate to the same topic.
Under the new wording in R1, the Transmission Vegetation Management Program no longer has a requirement to
include objectives. However, there is a phrase in R1.3 to “support the objectives” and methodologies “outlined in
the “program.” To be consistent with R1.3, the Western Utilities recommends that R1.1 be reworded to specify the
methodologies and objectives that the Transmission Owner uses to control vegetation.
Response: The SDT thanks you for your comments. However, the SDT determined that the requirements to document and implement should be
separate and require different levels of Violation Risk Factors and Violation Severity Levels. Thus, the SDT respectfully does not adopt your
suggestion to keep the two requirements together. The SDT also disagrees with returning “objectives” to R1. We do, however, agree that there exists
a small dichotomy since “objectives” are no longer stated in R1 while being referenced in part 1.3. Subsequently the SDT has removed this wording
from part 1.3. Further, the SDT has revised R1 to require the Transmission Owner to specifically describe how it will conduct work to comply with the
September 8, 2009
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Organization
Agree?
Question 6 Comment
Standard in lieu of requiring the Transmission Owner to only identify general objectives.
NPCC
Disagree
R1.2 and R1.3 should specifically state calendar year, and the Annual Plan and inspection follow the same
calendar year timing.
Response: The SDT thanks you for your comments. The SDT points out that these two parts, R1.2 and R1.3, refer to different aspects of the
Transmission Vegetation Management Program. Further, to assist in clarity, the SDT has revised part 1.3 and in doing so has removed the phrase
“during the year” since it added no value to the requirement. The SDT does not agree with your suggestion to base the annual plan on a calendar year
and feels that the Transmission Owner should retain the flexibility to determine the time period for - Requirement R1 clearly limits the scope of the
TVMP to work on the entity's Active Transmission Line Rights of Way - and the "annual work plan" is one element of the overall TVMP annual plan.
City of Tallahassee
Disagree
While I can agree with a separate requirement (R9) to implement the plan developed in R1.3, they need to both
have the flexibility desired in R1.3. I do not see that flexibility in R9. See response to question 17.
Response: The SDT thanks you for your comments. R9 is the implementation of 1.3 which is flexible. The flexibility of 1.3 carries through to R9.
Northern Indiana Public
Service Company
Disagree
I disagree with the elimination of the present requirement R2 (last sentence) that requires a Transmission Owner to
have proper quality control (QC) systems and procedures in place to document & track planned UVM work so as to
verify it was completed properly to work specifications. The need for this requirement was demonstrated as
recently as last year when a grow-in outage occurred at BG&E due to a contractor trimming the wrong tree at the
wrong location, a situation that could have been prevented with effective QC.
Response: The SDT thanks you for your comments. The consensus of the SDT is that in order to implement the plan the Transmission Owner must
complete its work plan to its standards. The level of QC is within the Transmission Owner’s purview.
USDA Forest Service,
Disagree
Southwestern Region,
Regional Office for AZ and NM
I think that the Transmission Owner should be able to specify the effective period of the plan whether it is one year
or ten years. Arizona utilities are starting to think in terms of multi-year corridor management plans. A one year
planning period could be specified as the minimum planning period.
Response: The SDT thanks you for your comments. The SDT agrees that long term plans can be of value and can be done within the standard. The
standard is trying to insure the immediate reliability work is budgeted and completed.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
September 8, 2009
Disagree
The document would benefit from keeping the two requirements together, since they relate to the same topic.
Under the new wording in R1, the Transmission Vegetation Management Program no longer has a requirement to
include objectives. However, there is a phrase in R1.3 to “support the objectives” and methodologies” outlined in
the “program.” To be consistent with R1.3, we recommend that R1.1 be reworded to specify the methodologies and
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Question 6 Comment
objectives that the Transmission Owner uses to control vegetation.
Response: The SDT thanks you for your comments. However, the SDT determined that the requirements to document and implement should be
separate and require different levels of Violation Risk Factors and Violation Severity Levels. Thus, the SDT respectfully does not adopt your
suggestion to keep the two requirements together. The SDT also disagrees with returning “objectives” to R1. We do, however, agree that there exists
a small dichotomy since “objectives” are no longer stated in R1 while being referenced in part 1.3. Subsequently the SDT has removed this wording
from part 1.3. Further, the SDT has revised R1 to require the Transmission Owner to specifically describe how it will conduct work to comply with the
Standard in lieu of requiring the Transmission Owner to only identify general objectives.
Arizona Public Service
Company
Disagree
The document would benefit from keeping the two requirements together, since they relate to the same topic.
Under the new wording in R1, the Transmission Vegetation Management Program no longer has a requirement to
include objectives. However, there is a phrase in R1.3 to “support the objectives” and methodologies “outlined in
the “program.” To be consistent with R1.3, APS recommends that R1.1 be reworded to specify the methodologies
and objectives that the Transmission Owner uses to control vegetation.
Response: The SDT thanks you for your comments. However, the SDT determined that the requirements to document and implement should be
separate and require different levels of Violation Risk Factors and Violation Severity Levels. Thus, the SDT respectfully does not adopt your
suggestion to keep the two requirements together. The SDT also disagrees with returning “objectives” to R1. We do, however, agree that there exists
a small dichotomy since “objectives” are no longer stated in R1 while being referenced in part 1.3. Subsequently the SDT has removed this wording
from part 1.3. Further, the SDT has revised R1 to require the Transmission Owner to specifically describe how it will conduct work to comply with the
Standard in lieu of requiring the Transmission Owner to only identify general objectives.
Baltimore Gas & Electric
Company
Disagree
See response to question no. 17.
Response: The SDT thanks you for your comments. See response to comments on #17.
JEA
Disagree
See comment from #3.
Response: The SDT thanks you for your comments. See response to comments on #3.
Salt River Project
September 8, 2009
Disagree
The document would be easier to follow if the two elements were kept together in the same requirement (similar to
comments stated in Comment #4 above). It makes the standard longer than necessary and creates redundancy.
Also, under the new wording in R1, the Transmission Vegetation Management Program no longer has a
requirement to include objectives. However, there is a phrase in R1.3 to "support the objectives” and
methodologies “outlined in the..program". To be consistent with R1.3, it is recommended that R1.1 be reworded to
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Question 6 Comment
specify the methodologies and objectives that the Transmission Owner uses to control vegetation.
Response: The SDT thanks you for your comments. However, the SDT determined that the requirements to document and implement should be
separate and require different levels of Violation Risk Factors and Violation Severity Levels. Thus the SDT respectfully does not adopt your suggestion
to keep the two requirements together. The SDT also disagrees with returning “objectives” to R1. We do, however, agree that there is a small
dichotomy since “objectives” are no longer stated in R1, while being referenced in part 1.3. Subsequently, the SDT has removed this wording from
part 1.3 Further, the SDT has revised R1 to require the Transmission Owner to specifically describe how it will conduct work to comply with the
Standard in lieu of requiring the Transmission Owner to only identify general objectives.
Hydro-Quebec Transenergie
(HQT)
Disagree
R1.2 and R1.3 specify calendar year. The individual entities should define the 12 month period for their programs.
Response: The SDT thanks you for your comments. The annual work plan may be for a calendar year or for a fiscal year.
Western Area Power
Administration, Upper Great
Plains Region
Agree
The description of the annual plan now appears to require a detailed plan for each line. Under FAC-003-1,
Western (UGPR) identified higher priority vegetation during aerial inspection and handled those expediciously. We
then addressed a percentage of the lower priority trees based upon a number of agency defined factors (vegetation
priority, ground conditions, resource availability, etc). The less rigid annual plan allowed us the freedom to cut the
lower priority trees that made the best sense to cut. We are concerned that the additional rigidity will create a everchanging annual plan because we may have to adjust dozens of lines based on inspections. We question whether
it is prudent to occupy finite resources in continually modifying the annual plan when the real benefits accrue from
actually performing the vegetation management activities.
Response: The SDT thanks you for your comments. The SDT intent is for the Transmission Owner’s Transmission Vegetation Management Program to
be developed based on the unique requirements of each Transmission Owner’s system. For example, where the Transmission Owner has a heavily
forested or geographically large territory the annual plan may address many transmission lines on a cyclic basis along with additional items found on
the vegetation inspections. On the other hand, where the Transmission Owner has a very sparsely forested territory, or a small number of
transmission line miles, the Transmission Vegetation Management Program may necessitate an annual plan that only addresses items found on the
vegetation inspections. Therefore, the specificity of the annual plan is subject to the discretion of the Transmission Owner. We agree that only the
appropriate amount of resources should be applied to the execution and management of the annual plan, provided the overall Transmission Vegetation
Management Program is effective.
Progress Energy Florida
September 8, 2009
Agree
Annual Plan should be a defined term in the standard. Without a definition, the term may be interpreted differently
by industry and the regulator. The drafting team should raise the prominence of annual plan and define the
attributes of an annual plan.
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Response: The SDT thanks you for your comments. The SDT did attempt to address this concern by breaking the annual plan into 4 separate subrequirements. We feel this may help limit the range of subjective interpretations of this requirement.
Progress Energy Carolinas
Agree
Annual Plan should be a defined term in the standard. Without a definition, the term may be interpreted differently
by industry and the regulator. The drafting team should raise the prominence of annual plan and define the
attributes of an annual plan.
Response: The SDT thanks you for your comments. The SDT did attempt to address this concern by breaking the annual plan into 4 separate subrequirements. We feel this may help limit the range of subjective interpretations of this requirement.
Southern California Edison
Company
Agree
Q6: SCE agrees in part. Proposal R1.3, requiring Transmission Owners to establish an annual maintenance plan is
generally acceptable. However, SCE disagrees with including peripheral information in R1.3 and the institution of a
separate implementation requirement (R9). Further, we note that some portions of FAC-003-1 (R2) appear to have
been transplanted into proposed R1.3 and that the word “shall” has been replaced with the word “should”. SCE
believes that inserting the word “shall” into statements that are clearly advisory in nature does not necessarily
create enforceable requirements. As proposed, an enforcement auditor might incorrectly determine that the new
“requirement” statements in proposed R1.3, describing the need for “flexibility”, “consideration of permitting and
scheduling requirements”, and self-determined “methodologies” is a comprehensive list of items for the
maintenance plan. Because this list of program elements is not complete, SCE recommends all text following the
opening sentence be removed from R1.3 and inserted into the supporting technical paper. SCE respectfully
suggests that R1.3 be revised to read: "Specifies a plan that identifies the applicable lines to be maintained and
associated work to be performed."
Response: The SDT thanks you for your comments. The consensus of the SDT is the components of an annual work plan must be part of the
requirement to ensure that all plans are adequate. Major changes that could affect reliability must be made.
FirstEnergy
September 8, 2009
Agree
Although we agree with R1.3, we suggest it be broken up into subrequirements to allow for better clarity to the
reader as well as aid in the development of violation severity levels when developed. We suggest the
following:R1.3. Require an annual plan that includes the following as a minimum: (Note: Adjustments to the plan
within the year are permissible) R1.3.1. It shall identify the applicable lines to be maintained and associated work
to be performed during the year. R1.3.2. Is shall be flexible to adjust to changing conditions and to findings from
vegetation inspections. R1.3.3. It shall take into consideration permitting and scheduling requirements from
landowners or regulatory authorities. R1.3.4. It shall support the objectives of the transmission vegetation
management program and use the methodologies outlined in the transmission vegetation management program.
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Question 6 Comment
Response: The SDT thanks you for your comments. Requirement R1.3 has been subdivided for clarity in proposed version 2.
MRO NERC Standards
Review Subcommittee
Agree
The MRO suggests removing the words "during the year" from sentence 1 and removing the words "within the
year" in sentence 3. The MRO believes that having it only within the plan year is too restrictive.
Response: The SDT thanks you for your comments. By definition an annual plan covers a one year period. This one year period, at the discretion of
the Transmission Owner, may or may not be constrained to a calendar year. However, in an effort to make the requirement more concise, the SDT did
remove the words “during the year” from the requirement but retained the words “within the year” in the requirement.
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 6 and proposes that the Annual Plan be a defined term.
Response: The SDT thanks you for your comments. The SDT did attempt to address this concern by breaking the annual plan into 4 separate subrequirements. We feel this may help limit the range of subjective interpretations of this requirement.
American Electric Power
(AEP)
Agree
AEP agrees with these changes.
Response: The SDT thanks you for your comments.
Platte River Power Authority
Agree
Under the new working in R1., the Transmission Vegetation Management Program no longer has a requirement to
include objectives. However, there is a phrase in R1.3. to "support the objectives.. and methodologies outlined in
the Transmission Vegetation Management Program". R1.3. should be consistent with the wording in R1.
Response: The SDT thanks you for your comments. The SDT has made changes to address this concern and the word, “objectives” is no longer used
in the revised standard.
American Transmission
Company
Agree
ATC agrees with separating the implementation Requirements from the Annual Plan Requirements.
Response: The SDT thanks you for your comments.
Manitoba Hydro
Agree
Agree with the separation - but suggest that the time horizon of one year be removed as some changes may push
the work beyond the current planning year.
Response: The SDT thanks you for your comments. By definition an annual plan covers a one year period. This one year period, at the discretion of
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Question 6 Comment
the Transmission Owner, may or may not be constrained to a calendar year. If findings during the year from Vegetation Inspections justify changes to
the plan, such adjustments are allowed as long as they occur within the planning year, not after the fact.
San Diego Gas & Electric
Agree
To be consistent with R1.3, we recommend that R1.1 be reworded to specify the methodologies and objectives that
the Transmission Owner uses to control vegetation.
Response: The SDT thanks you for your comments. The SDT has made changes to address this concern.
CenterPoint Energy
Agree
See comments to Q4 above as well.
Response: The SDT thanks you for your comments. See response to comments on Q4.
Great River Energy
Agree
GRE suggests removing the words "during the year" from sentence 1 and removing the words "within the year" in
sentence 3. GRE believes that having it only within the plan year is too restrictive.
Response: The SDT thanks you for your comments. By definition an annual plan covers a one year period. This one year period, at the discretion of
the Transmission Owner, may or may not be constrained to a calendar year. However, in an effort to make the requirement more concise, the SDT did
remove the words “during the year” from the requirement but retained the words “within the year” in the requirement.
WECC Reliability Coordination Agree
Associated Electric
Cooperative Inc.
Agree
SERC Vegetation
Management Subcommittee
(VMS)
Agree
Kansas City Power & Light
Agree
Western Area Power
Administration, Rocky
Mountain Region
Agree
SERC OC Standards Review
Agree
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Question 6 Comment
Group
Florida Power & Light
Agree
Santee Cooper
Agree
Southern Company
Agree
E.ON U.S.
Agree
Bonneville Power
Administration
Agree
Midwest ISO Stakeholders
Standards Collaborators
Agree
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
Exelon
Agree
Central Maine Power
Company
Agree
Northern California Power
Agency (NCPA)
Agree
Tampa Electric Company
Agree
Orange and Rockland Utilities
Inc.
Agree
Ameren
Agree
September 8, 2009
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Nebraska Public Power
District
Agree
Long Island power Authority
Agree
Consumers Energy Company
Agree
National Grid
Agree
Pacific Gas & Electric Co.
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
Consolidated Edison
Company of New York
(CECONY)
Agree
WECC
Agree
Duke Energy Corporation
Agree
Entergy Services
Agree
Pepco Holdings, Inc
Agree
Northeast Utilities
Agree
Buckeye Power, Inc.
Agree
September 8, 2009
Question 6 Comment
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7. In R1.4 the Standard requires the Transmission Owner to have an Imminent Threat Procedure and specifies elements
to be in that procedure. Do you agree with R1.4? If not, please explain.
Summary Consideration: Approximately half of the comments received were critical of the lack of a definition for imminent
threat. The SDT prefers to allow the verbiage “an imminent threat of a vegetation-related Sustained Outage” to stand without
further definition.
About the same number of commenters objected to the “prescriptive” list of other actions for the Transmission Operator, and
that language has been removed from R1.4.
R1.4
Require a process or procedure for response to imminent threats of a vegetation related Sustained Outage. The process or
procedure shall specify actions which shall include immediate communication of the threat to the responsible control center.
Commenters also expressed a desire to set the procedure for specific internal needs and the SDT modified the language to give
that latitude to the Transmission Owner when developing its Imminent Threat procedure.
Some comments referred to parts of the standard not asked about in this question and the SDT directed the commenters to
review the changes in R1, R2 and R4.
Organization
Associated Electric Cooperative
Inc.
Agree?
Disagree
Question 7 Comment
The language in R1.4, requiring notification of the Transmission Operator, is inconsistent with the Applicability in
Section A.4.1.1 which designates the Transmission Owner as the responsible entity.
Response: Thank you for your comment. The main purpose of requirement R1.4 is to enhance the responsible operator’s situational awareness of the
power system’s status. Therefore, the salient requirement of this procedure is notification of the responsible operator of any potential threat to the
power system. This requirement does not mandate any action of the responsible operator and thus, this entity would not need to be listed in the
Applicability section. Please also note that the wording in R1.4 has been altered to change the “Transmission Operator” to the “responsible control
center”, to better identify the appropriate responsible party.
NPCC
Disagree
September 8, 2009
While we strongly agree that an imminent threat procedure should be required in the Transmission Vegetation
Management Program, we disagree with some specific wording in R1.4. R1.4 requires immediate
communication of an imminent threat to the Transmission Operator, which we would normally agree with. R2
however requires that the imminent threat procedure be implemented when the Critical Clearance Zone (Critical
Clearance Zone ) is approached by vegetation. "Approached" is not defined as a specific distance, so this part
of the requirement is left up to the individual's interpretation. In cases where the Critical Clearance Zone is
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Deleted: Transmission Operator
Deleted: , and may include actions such
as a temporary reduction in line Rating,
switching lines out of service, or other
actions.
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Question 7 Comment
approached by vegetation no threat to the system is possible if the vegetation is removed before it actually
grows into the Critical Clearance Zone . In many cases the vegetation can be removed without taking clearance
outages because the Critical Clearance Zone is large, and the conductor and vegetation are still relatively far
apart. In such cases there is no need to notify the Transmission Operator, although there is a need to remove
the vegetation immediately. We recognize that the opposite is also true, and that in some cases it will be
necessary to notify the Transmission Operator because a clearance outage or line de-rating may be required to
remove the vegetation. We therefore suggest a simple change to the wording of the second sentence of R1.4.
Change "?. specify actions which shall include immediate communication of the threat to the Transmission
Operator, and may include actions such as a temporary reduction in line Rating, switching lines out of service, or
other actions" to ".. specify actions which may include immediate communication of the threat to the
Transmission Operator, a temporary reduction in line Rating, switching lines out of service, or other actions”.
This change will address the issue which is described above and will allow each Transmission Operator to
develop an imminent threat procedure that best fits their system. It should also be noted that many Transmission
Operators have imminent threat procedures in place to address all imminent threats to their transmission system,
not just threats due to vegetation. It makes sense for Transmission Owners to have only one imminent threat
process, therefore the flexibility that can be achieved in the context of this standard would be helpful.
Response: Thank you for your comment. We agree with your comments concerning the Critical Clearance Zone and the elusiveness of the term
“approach”. Subsequently, the Critical Clearance Zone methodology has been removed from the Standard. The SDT also agrees that the main purpose
of the imminent threat requirement is to enhance the responsible control center’s situational awareness of the power system’s status. Please also
note that the wording has been altered to change the “Transmission Operator” to the “responsible control center” to better identify the appropriate
responsible party. The SDT maintains that the salient requirement of this procedure is notification of the responsible operator of any imminent threat
to the power system. Beyond this, it is left to the Transmission Owner to develop an imminent threat procedure that best fits its system.
SERC Vegetation Management
Subcommittee (VMS)
Disagree
The Requirement as written is too prescriptive and is open to interpretation, from an audit perspective, with use
of the term “immediate” communication and a partial list of activities. Many conditions or threats, requiring
immediate removal, would not require communication with the Transmission Operator, who is not an applicable
entity for this standard. The SERC VMS recommends that R1.4 be deleted. Since this is a "zero tolerance"
standard any Transmission Owner will remove any discovered threats to prevent outages. If R1.4 is not deleted,
the SERC VMS believes that imminent threats should be a defined term. The definition should be as follows:
?Imminent Threat: A vegetation condition which, if not addressed, will place a transmission line at a significant
risk of a Sustained Outage.?
Response: Thank you for your comment. We agree that an imminent threat can exist in many different forms. Part of your concern has been addressed
by the removal of the term “immediate”. However, the SDT does not agree with removing the imminent threat requirement. The main purpose of the
imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system. Please
note that the requirement wording has also been altered to change the designation “Transmission Operator” to the “responsible control center” to
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Question 7 Comment
better identify the appropriate party. The salient requirement of the imminent threat procedure is notification of the responsible operator of any
imminent threat to the power system. Beyond this, it is left to the Transmission Owner to develop an imminent threat procedure that best fits its
system.
Progress Energy Florida
Disagree
Progress Energy agrees with the need for a Transmission Owner to have an Imminent Threat Procedure and
that the Transmission Operator should be immediately notified of imminent threats but only when it is appropriate
as defined by the Transmission Owner's imminent threat procedure. We disagree with the requirement to
immediately communicate with the Transmission Operator whenever the Critical Clearance Zone is approached.
Not every scenario is an issue that requires action by the Transmission Operator: It is possible that the Critical
Clearance Zone is being approached by vegetation at the lowest point of the Critical Clearance Zone whereas
the conductor may be at its highest point in the Critical Clearance Zone (potentially 30 feet away from the
vegetation) -- This typical situation does not merit notification to the Transmission Operator (which is required by
FAC-003-2 as currently written).
Response: Thank you for your comment. We agree with your comments concerning the Critical Clearance Zone methodology. Subsequently, the
Critical Clearance Zone methodology has been removed from the Standard. The SDT also agrees that the main purpose of the imminent threat
requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system. Please also note that the
requirement wording has been altered to change the “Transmission Operator” to the “responsible control center”. The SDT feels this better identifies
the appropriate party. The SDT maintains that the salient requirement of R1.4 is notifying the responsible operator of any imminent threat to the
power system.
Progress Energy Carolinas
Disagree
Progress Energy agrees with the need for a Transmission Owner to have an Imminent Threat Procedure and
that the Transmission Operator should be immediately notified of imminent threats but only when it is appropriate
as defined by the Transmission Owner's imminent threat procedure. We disagree with the requirement to
immediately communicate with the Transmission Operator whenever the Critical Clearance Zone is approached.
Not every scenario is an issue that requires action by the Transmission Operator: It is possible that the Critical
Clearance Zone is being approached by vegetation at the lowest point of the Critical Clearance Zone whereas
the conductor may be at its highest point in the Critical Clearance Zone (potentially 30 feet away from the
vegetation) -- This typical situation does not merit notification to the Transmission Operator (which is required by
FAC-003-2 as currently written).
Response: Thank you for your comment. We agree with your comments concerning the Critical Clearance Zone methodology. Subsequently, the
Critical Clearance Zone methodology has been removed from the Standard. The SDT also agrees that the main purpose of the imminent threat
requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system. Please also note that the
requirement wording has been altered to change the “Transmission Operator” to the “responsible control center”. The SDT feels this better identifies
the appropriate party. The SDT maintains that the salient requirement of R1.4 is notifying the responsible operator of any imminent threat to the power
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Question 7 Comment
system.
SERC OC Standards Review
Group
Disagree
The Requirement as written is too prescriptive and is open to interpretation from an audit perspective with use of
the term “immediate” communication and a partial list of activities. Due to limitations of communication
capabilities in the field, "immediate" may not be practical. While the White Paper provides insight into what is
acceptable communications to the Transmission Operator, the standard is less prescriptive in describing what is
an acceptable communication path to the Transmission Operator. We recommend better descriptions in VSLs,
measures and the Reliability Standard Audit Worksheet as to what is acceptable. Many conditions or threats,
requiring immediate removal, would not require communication with the Transmission Operator, who is not an
applicable entity for this standard. The SERC OCSRG recommends that R1.4 be deleted. Since this is a "zero
tolerance" standard any Transmission Owner will remove any discovered threats to prevent outages. If R1.4 is
not deleted, the SERC OCSRG believes that imminent threats should be a defined term. The definition should
be as follows: “Imminent Threat: A vegetation condition which, if not addressed, will place a transmission line at
an immediate risk of a Sustained Outage.”
Response: Thank you for your comment. Part of your concern has been addressed by the removal of the term “immediate”. However, the SDT does
not agree with removing the imminent threat requirement. The main purpose of the imminent threat requirement is to enhance the responsible control
center’s situational awareness of reliability dangers to the power system. Please note that this requirement’s wording has also been altered to change
the designation “Transmission Operator” to the “responsible control center” to better identify the appropriate party. The salient requirement of the
imminent threat procedure is notification of the responsible operator of any imminent threat to the power system. Beyond this, it is left to the
Transmission Owner to develop an imminent threat procedure that best fits its system and field communication capabilities. The SDT also feels that it
is important for the aspects of the imminent threat procedure and the triggers be defined by the Transmission Owner. The Violation Severity Levels
for this requirement are now binary and self explanatory. The SDT is prepared to provide input in the revision of RSAWs, but under current practice,
RSAWs are not developed by standard drafting teams.
Florida Power & Light
Disagree
The definition of Imminent Threat procedure should be included in the Standard. As FERC has stated with
regard to the definition of sabotage, the industry should come up with a standard definition and it should not vary
from company-to-company. FPL further disagrees with defining Imminent Threat only in a white paper as
proposed by some. The Standard should not refer to other reference documents, especially when it is to add
clarity and should define the Imminent Threat procedure as well as its requirements within the body of the
Standard.
Response: Thank you for your comment. The SDT disagrees with your comments. We feel that the Transmission Owner should have the flexibility to
not only develop the imminent threat procedure but also define the triggers needed for its particular system. The main purpose of the imminent threat
requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system. The notification
requirement is a mandatory requirement for all Transmission Owners. Please note that this requirement’s wording has also been altered to change the
designation “Transmission Operator” to the “responsible control center” to better identify the appropriate party. Beyond this, it is left to the
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Question 7 Comment
Transmission Owner to develop all other imminent threat procedure components.
Southern Company
Disagree
The standard requirement, as written, requires the "immediate notification" of the operator. This standard
requirement could be interpreted to mandate that this notification take place prior to any other action. There
could be times that this communication would take up valuable time needed to relieve the immediate threat. The
requirement should be modified to list examples of appropriate actions that could be taken. The Transmisison
Owner should be allowed the flexibility of developing a communication process that ensures timely notification of
a threat and the proper channels of communication that will be utilized in making the notification. The present
wording in the standard alone suggests the individual observing the threat in the field is directly responsible for
communicating with the Transmission Operator while the whitepaper tends to be more flexible. The
Transmission Owner may wish to have the vegetation contractor notify the Transmisison Owner's forester who in
turn will notify the Transmission Operator. While the whitepaper does an adequate job describing acceptable
responses, the standard does not. It is recommend the standard, VSL, and Reliability Standard Audit Worksheet
better explain what is an acceptable response to the Transmission OwnerP. The requirement then goes on to
address specific actions the operator "may" take in response to the notification. The imminent threat processes
should be limited to the steps taken to notify the Transmission Operator in a timely manner. FAC-003 is not the
appropriate place to address Transmission Operator decisions resulting from notification of a threat to the
system.
Response: Thank you for your comment. Part of your concern has been addressed by the removal of the term “immediate”. We agree that the main
purpose of this requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system. Further,
please note that the requirement wording has also been altered to change the designation “Transmission Operator” to the “responsible control center”
to better identify the appropriate party. Beyond this, it is left to the Transmission Owner to develop an imminent threat procedure that best fits its
system and field communication capabilities. The Violation Severity Levels for this requirement are now binary and self explanatory. The SDT is
prepared to provide input in the revision of RSAWs, but under current practice, RSAWs are not developed by standard drafting teams.
E.ON U.S.
Disagree
The Requirement as written is too prescriptive and is open to interpretation, from an audit perspective, with use
of the term “immediate” communication and a partial list of activities. Many conditions or threats, requiring
immediate removal, would not require communication with the Transmission Operator, who is not an applicable
entity for this standard. We suggest that R1.4 be deleted. Since this is a "zero tolerance" standard any
Transmission Owner will remove any discovered threats to prevent outages. If R1.4 is not deleted, we believe
that imminent threats should be a defined term. The definition should be as follows: “Imminent Threat: A
vegetation condition which, if not addressed, will place a transmission line at a significant risk of a Sustained
Outage.”
Response: Thank you for your comment. We agree that an imminent threat can exist in many different forms. Part of your concern has been
addressed by the removal of the term “immediate”. However, the SDT does not agree with removing the imminent threat requirement. The main
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purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power
system. Please note that the requirement wording has also been altered to change the designation “Transmission Operator” to the “responsible
control center” to better identify the appropriate party. The salient requirement of this procedure is notification of the responsible operator of any
imminent threat to the power system. Beyond this, it is left to the Transmission Owner to develop an imminent threat procedure that best fits its
system.
Midwest ISO Stakeholders
Standards Collaborators
Disagree
Transmission Owners should have a Vegetation Imminent Threat Procedure, and "Vegetation Imminent Threat"
should be a defined term, defined as: "Vegetation observed in the field encroaching upon a conductor within a
distance that is twice the Gallet clearance distances referenced in Table I of the draft standard FAC-003-2." In
this case, the threat would require an immediate response and would include communication to the
Transmission Operator. From there, the actions that the operator decides to take will be dependent on the
incident and system conditions. We do not need to be prescriptive with this requirement but rather allow the
Transmission Operator and appropriate field personnel the flexibility to make the right decisions to safely,
promptly and appropriately remove the vegetation threat. From a Transmission Owner's perspective, many
situations can constitute an imminent threat but this approach will clearly define a "Vegetation Imminent Threat"
as it relates to the Purpose of this standard. See our related comment on #11 below.
Response: Thank you for your comment. We agree that many situations can constitute an imminent threat. While we do not agree that an imminent
threat should be defined in the Standard, we do agree that the Transmission Owner should have the flexibility to develop an imminent threat procedure
that allows the appropriate decisions to address the vegetation threat. This requirement allows the Transmission Owner to develop an imminent threat
procedure that best fits its system. The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational
awareness of reliability dangers to the power system. Please note that the requirement’s wording has also been altered to change the designation
“Transmission Operator” to the “responsible control center” to better identify the appropriate party. The SDT feels this is a better approach than to
have a rigid definition of an imminent threat procedure.
SERC Compliance Staff
Disagree
SERC staff agrees with the concept of an imminent threat procedure, but disagrees with this requirement in its
current form. The use of the word "immediate" is ambiguous. There are many conditions or threats that may
require immediate removal, but would not require communication with the Transmission Operator and may
require communication with another entity. SERC staff suggests that the proper communication paths be
outlined by the Transmission Owner. Imminent threats should be a defined term, however SERC staff has not
developed an objective, unambiguous definition.
Response: Thank you for your comment. Part of your concern has been addressed by the removal of the term “immediate”. We agree that the main
purpose of the imminent threat requirement is the timely communication of a threat to the responsible operator. Therefore, the requirement wording
has been altered to change the designation “Transmission Operator” to the “responsible control center”. The main purpose of this requirement is to
enhance the responsible control center’s situational awareness of reliability dangers to the power system. While we do agree that the Transmission
Owner should outline the proper communication paths, we do not agree that an imminent threat should be defined in the Standard. The SDT feels the
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Transmission Owner should have the flexibility to develop an imminent threat procedure that best fits its system.
ITC HOLDINGS
Disagree
Agree & Disagree with the question: Agree with the need to have an Imminent Threat Procedure and upon
discovery of an IT, the Transmission Operations (Transmission Owner) should be notified. We Disagree
however, with the requirement as written as its too prescriptive and is open to interpretation, from an audit
perspective, with use of the term “immediate” communication and a partial list of activities that the Transmission
Owner may consider. Decisions on what specific system operating actions that could be taken are beyond the
responsibility of the vegetation management personnel. Disagree with the need to implement the imminent threat
procedure merely because a Critical Clearance Zone is being approached. It is possible that the Critical
Clearance Zone is being approached by vegetation at the lowest point of the Critical Clearance Zone where
the conductor may be at its highest point in the Critical Clearance Zone , (potentially 20 or 30 feet from
vegetation) and wouldn’t necessitate notification to the Transmission Owner. Is there a desired distance from the
Critical Clearance Zone where this procedure must be implemented since all vegetation within a Right-of-Way
will approach the Critical Clearance Zone as it grows? R1.4 should be changed to ?Require a process for
response to vegetation related imminent threat to applicable lines and not the Critical Clearance Zone
Response: Thank you for your comment. We agree with your comments concerning the Critical Clearance Zone and the elusiveness of the terms
“approach” and “immediate”. Subsequently, the Critical Clearance Zone methodology has been removed from the Standard. Also, the term
“immediate” has been removed. The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational
awareness of the power system’s status. Please also note that the wording has been altered to change the “Transmission Operator” to the
“responsible control center” to better identify the appropriate responsible party. The SDT maintains that the salient requirement of the imminent
threat procedure is notification of the responsible operator of any imminent threat to the power system. Beyond this, it is left to the Transmission
Owner to develop an imminent threat procedure that best fits its system.
Tennessee Valley Authority
Disagree
TVA recommends that R1.4 and R2 both be removed from this Standard. This is a "zero tolerance" Standard
with significant penalties for outage violations. These penalty conditions are the necessary and sufficient
conditions for the Transmission Owner to immediately react to any discovered threats to prevent potential
outages.
Response: Thank you for your comments. While the drafting team does agree that the penalties for the “zero tolerance” aspect of the Standard
certainly provide a strong incentive, we still feel that a requirement for an imminent threat procedure should be included in the Standard. The main
purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power
system. Please note that this requirement’s wording has been altered to change the designation “Transmission Operator” to the “responsible control
center” to better identify the appropriate party. The salient part of this procedure is notification of the responsible operator of any imminent threat to
the power system. Beyond this, the Transmission Owner should develop all other components of the imminent threat procedure to best fit its system.
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American Electric Power (AEP)
Agree?
Disagree
Question 7 Comment
AEP agrees with the need for a Transmission Owner to have an Imminent Threat Procedure and that the
Transmission Operator should be immediately notified of imminent threats. However, AEP disagrees with the
requirement that the Transmission Operator be notified merely because the Cricitical Clearance Zone (Critical
Clearance Zone ) has been approached. It is possible that the Critical Clearance Zone is encroached by
vegetation at the lowest point of the Critical Clearance Zone whereas the conductor may be at its highest point
in the Critical Clearance Zone (potentially 20 or 30 feet away from the vegetation). This situation does not merit
notification to the Transmission Operator. Please also refer to our comments regarding Critical Clearance Zone
in AEP's responses to Questions 15 and 18.
Response: Thank you for your comment. We agree with your comments concerning the Critical Clearance Zone and the elusiveness of the term
“approach”. Subsequently, the Critical Clearance Zone methodology has been removed from the Standard. The SDT feels that the main purpose of the
imminent threat requirement is to enhance the responsible control center’s situational awareness of the power system’s status. Please also note that
the wording has been altered to change the “Transmission Operator” to the “responsible control center” to better identify the appropriate responsible
party. The SDT maintains that the salient requirement of this procedure is notification of the responsible operator of any imminent threat to the power
system. Beyond this, it is left to the Transmission Owner to develop an imminent threat procedure that best fits its system.
Tampa Electric Company
Disagree
TECO aggres with the need for the Imminent Threat Procedure. However, the use of the new Critical Clearance
Zone could create a "fill in the blank" standard. We need to lock these clearances down as an industry so as to
define what is an imminent threat and what the Critical Clearance Zone is in terms of specific distances.
Response: Thank you for your comments. The SDT agrees with your concern of having a standard with “fill in the blank” requirements. We have
made some major changes to this requirement due to the overwhelming response from industry that the imminent threat requirement was needed but
should not be overly prescriptive. The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational
awareness of reliability dangers to the power system. Please note that the requirement wording has also been altered to change the designation
“Transmission Operator” to the “responsible control center” to better identify the appropriate party. The salient part of the imminent threat procedure
is notification of the responsible operator of any imminent threat to the power system.
Using the Critical Clearance Zone as an undefined “trigger” for implementing the imminent threat process has been removed from the Standard. The
Critical Clearance Zone methodology has been deleted from the Standard.
Orange and Rockland Utilities
Inc.
September 8, 2009
Disagree
While we agree that the imminent threat procedure should be included in the Transmission Vegetation
Management Program, the requirement is overly prescriptive and should be revised to allow Transmission
Owners flexibility to develop imminent threat procedures which best fit their systems and protocols. We
recommend that R1.4 be reworded as follows: "Require a process or procedure for response to vegetationrelated imminent threats to applicable lines. The imminent threat procedure shall require action to eliminate
vegetation-related imminent threats, and shall be implemented upon discovery of such conditions". In addition,
the definition of "Imminent Threat" should be defined. We suggest the following: "A condition which places a
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transmission line at significant risk of an outage in the very near term". An example of a vegetation-related
imminent threat would be an uprooted tree leaning precariously toward a conductor which is certain to make
contact with the conductor as the tree falls. Many Transmission Operators have imminent threat procedures in
place to address all imminent threats to their transmission systems, not just imminent threats due to vegetation.
In many cases it would make sense for Transmission Owners to have one imminent threat process that covers
all imminent threat conditions. The flexibility being recommended would facilitate this.
Response: Thank you for your comment. The SDT agrees that the requirement was overly prescriptive. The requirement has been revised to focus on
the main purpose of the imminent threat requirement; which is to enhance the responsible control center’s situational awareness of reliability dangers
to the power system. Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the
“responsible control center” to better identify the appropriate party. The salient part of this procedure is notification of the responsible operator of any
imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and procedures that best
fit its systems and protocols; thereby providing for the flexibility that you have suggested. Along with this line of reasoning, we do not agree that an
imminent threat should be defined in the Standard. Again, the SDT feels that the Transmission Owner should have the flexibility to define what
constitutes an imminent threat to its individual power system. This flexibility also allows the Transmission Owner to have one imminent threat process
in place to cover all imminent threats to its transmission systems, not just imminent threats due to vegetation as you have noted.
American Transmission
Company
Disagree
We agree that entities should have a Vegetation Imminent Threat Procedure, but that the term should be
defined. Also see related comments to Question #11.
Response: Thank you for your comment. We have made some major changes to this requirement due to the overwhelming response from industry
that the imminent threat requirement was needed, as long as it was not an overly prescriptive requirement. We do not agree that an imminent threat
should be defined in the Standard. The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational
awareness of reliability dangers to the power system. Please note that the requirement wording has also been altered to change the designation
“Transmission Operator” to the “responsible control center” to better identify the appropriate party. The salient requirement of an imminent threat
procedure is notification of the responsible operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to
determine the follow up activities and procedures that best fit its system. The SDT feels this is a better approach than to have a rigid definition of an
imminent threat procedure.
Nebraska Public Power District
Disagree
NPPD agrees that a Transmission Owner should have an imminent threat procedure and the Transmission
Owner be immediately notified of any threats. NPPD disagrees with prescribing what needs to be done as a
result of the threat. This is condition based and staff can make the right decision as to what corrective actions
are necessary.
Response: Thank you for your comment. The SDT agrees that prescribing what needs to be done as a result of the threat should not be included as
part of the Standard requirement. This language has been removed from the text as you have suggested. The SDT also agrees that the main purpose
of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system.
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Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible control
center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible operator of
any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and procedures that
best fit its system.
Consumers Energy Company
Disagree
Consumers Energy believes that each Transmission Owner/Operator should have a Vegetation Imminent Threat
Procedure. We disagree with this requirement because "vegetation imminent threat" is not defined in the
standard. As interpreted, the "vegetation imminent threat" is only what is needed to avoid violating the Gallet
formula minimum distance which would allow vegetation approaching close to 3 feet of separation on 345 kV
conductors. At this distance, removal of the tree cannot occur without removing the line from service per OSHA
rules. Therefore, the tree can "cause" an outage but be acceptable under this standard. Consumers Energy
believes that vegetation must be maintained so that extraordinary measures needed to remove the vegetation
threat do not have to occur in order to complete the work. Thus, the minimum distance to "trigger" an imminent
threat must be greater than the OSHA minimum working distance and therefore the Gallet formula does not
provide the protection that FERC demands. During high load periods options a system operator may have to
mitigate the vegetation threat may not be available; you may not be able to remove the line from service, derate
the line, etc., so the operator must "hope" to get through the high load period without the vegetation causing a
outage. Allowing vegetation to approach the Gallet formula distance is unacceptable and severely decreases
the reliability of the system.
Response: Thank you for your comment. The SDT does not agree that a vegetation imminent threat should be defined in the Standard. The Critical
Clearance Zone methodology has been removed from the Standard. We feel that the Transmission Owner should have the flexibility to not only
develop the imminent threat procedure but also define the triggers needed for its particular system. The main purpose of the imminent threat
requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system. The notification
requirement is a mandatory requirement for all Transmission Owners. Please note that this requirement’s wording has also been altered to change the
designation “Transmission Operator” to the “responsible control center” to better identify the appropriate party. The SDT maintains that the salient
requirement of an imminent threat procedure is notification of the responsible operator of any imminent threat to the power system. Beyond this, it is
left to the Transmission Owner to determine the follow up activities and procedures that best fit its system. Aside from the negative economic and
operational impacts associated with unscheduled facility outages, failures by the Transmission Owner to effectively execute follow up activities and
procedures will most likely lead to a violation(s) of other requirements related to Minimum Vegetation Clearance Distance (MVCD) encroachment or
sustained outages.
Ameren
September 8, 2009
Disagree
Transmission Owners should have a Vegetation Imminent Threat Procedure, and "Vegetation Imminent Threat"
should be a defined term, defined as: "Vegetation observed in the field encroaching upon a conductor within a
distance defined in the Vegetation Management plan." In this case, the threat would require an immediate
response and would include communication to the Transmission Operator. From there, the actions that the
operator decides to take will be dependent on the incident and system conditions. We do not need to be
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prescriptive with this requirement but rather allow the Transmission Operator and appropriate field personnel the
flexibility to make the right decisions to safely, promptly and appropriately remove the vegetation threat. From a
Transmission Owner's perspective, many situations can constitute an imminent threat but this approach will
clearly define a "Vegetation Imminent Threat" as it relates to the Purpose of this standard. While a definition of
"Vegetation Imminent Threat - Vegetation observed in the field encroaching upon a conductor within a distance
that is twice the Gallet clearance distances referenced in Table I of the draft standard FAC-003-2" would be
acceptable and far superior to that which is proposed, it will still be difficult for field personnel to identify, at each
foot of a transmission circuit, wherein twice the Gallet distance would be found. See comment on #11 below.
Response: Thank you for your comment. We agree with your assessment that the Standard needs an imminent threat requirement, but as it was
written, the requirement was overly prescriptive. As a result, and because much of the industry agreed with you, we have made some major changes
to this requirement. The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of
reliability dangers to the power system. Please note that the requirement wording has also been altered to change the designation “Transmission
Operator” to the “responsible control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is
notification of the responsible operator of any imminent threat to the power system.
We further agree that many situations can constitute an imminent threat, distance from the vegetation to the conductor being only one of such
situations, so the references to the Critical Clearance Zone methodology as a defined “trigger” for implementing the imminent threat process has been
removed from the Standard. For that matter, the Critical Clearance Zone methodology has been deleted from the Standard. While we do not agree that
an imminent threat should be defined in the Standard, we do agree that the Transmission Owner should have the flexibility to develop an imminent
threat procedure that allows the appropriate decisions to address the vegetation threat. The requirement, as it has been reworded, allows the
Transmission Owner to develop an imminent threat procedure that best fits its system. The SDT feels this is a better approach than to have a rigid
definition of an imminent threat procedure.
Consolidated Edison Company
of New York (CECONY)
Disagree
CECONY currently has procedures that mandate response to imminent threats. The Standard should be made
more general and not identify the specific actions that shall be taken in the procedure. The second sentence of
R1.4 should be deleted and the first sentence should read, 'Require a process or procedure to respond to
vegetation-related imminent threats." This adds the necessary flexibility that utilities require and avoids additional
redundant processes or procedures from being developed.
Response: Thank you for your comment. The SDT agrees that the requirement should be more general and has revised the requirement to focus on
the main purpose of the imminent threat requirement; which is, to enhance the responsible control center’s situational awareness of reliability dangers
to the power system. Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the
“responsible control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the
responsible operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up
activities and procedures that best fit its systems and protocols, thereby providing for the flexibility that you have suggested.
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Duke Energy Corporation
Agree?
Disagree
Question 7 Comment
Duke believes that Transmission Owners should have a Vegetation Imminent Threat Procedure, and "Vegetation
Imminent Threat" should be a defined term, defined as: "Vegetation observed in the field encroaching upon a
conductor within a distance that is twice the Gallet clearance distances referenced in Table I of the draft
standard FAC-003-2." In this case, the threat would require an immediate response and would include
communication to the Transmission Operator. From there, the actions that the operator decides to take will be
dependent on the incident and system conditions. We do not need to be prescriptive with this requirement but
rather allow the Transmission Operator and appropriate field personnel the flexibility to make the right decisions
to safely, promptly and appropriately remove the vegetation threat. From a Transmission Owner's perspective,
many situations can constitute an imminent threat but this approach will clearly define a "Vegetation Imminent
Threat" as it relates to the Purpose of this standard. See our related comment on #11 below.
Response: Thank you for your comment. While we do not agree that an imminent threat should be defined in the Standard, we do agree with your
assessment that the Standard needs an imminent threat requirement, but as it was written, the requirement was overly prescriptive. As a result, and
because much of the industry agreed with you, we have made some major changes to this requirement. The Critical Clearance Zone methodology has
been deleted from the Standard. The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational
awareness of reliability dangers to the power system. Please note that the requirement wording has also been altered to change the designation
“Transmission Operator” to the “responsible control center” to better identify the appropriate party. The salient requirement of an imminent threat
procedure is notification of the responsible operator of any potential threat to the power system. Beyond this, it is left to the Transmission Owner to
determine the “triggers”, follow up activities, and procedures that best fit its system; thereby providing for the flexibility that you have suggested.
The SDT feels this is a better approach than to have a rigid definition of an imminent threat procedure.
Entergy Services
Disagree
1. The requirement should state that each Transmission Owner will be responsible for creating and maintaining
a Vegetation Imminent Threat Process. This process will clearly define how the Transmission Owner defines a
vegetation imminent threat.
2. The requirement needs to state that only vegetation conditions identified, to the Transmission Owner, by
regular field inspections, including aerial inspections, and other internal and external verifiable reports of
vegetation imminent threats will be managed through this process.
3. If the standard requires a process to mitigate potential immediate threats to the system, the term ?vegetation
imminent threat? must be defined. This definition must not delineate the precise steps that are required to be
taken to allow experts as many options as necessary to address each vegetation condition specifically.
4. The list of possible mitigating actions should be removed from the standard since it is not an all inclusive list.
Listing these actions in the standard may imply that the entity must do one or all of the actions to be in
compliance. The entity must have sufficient latitude to evaluate each possible vegetation condition and apply
the most appropriate mitigation steps, up to and including the removal of the identified vegetation.
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Response: Thank you for your comments.
1. The SDT prefers to allow the verbiage “an imminent threat of a vegetation-related Sustained Outage” to stand without further definition. The SDT
agrees that the Standard needs an imminent threat requirement. However, as it was written for the initial posting, the requirement was overly
prescriptive. As a result, and because much of the industry agreed with you, the SDT has made some changes to this requirement. The main purpose
of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system.
Please note that the requirement wording has also been altered to change the designation “Transmission Operator” to the “responsible control center”
to permit communication with the relevant entity for the Transmission Owner. The salient requirement of an imminent threat procedure is notification
of the responsible operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the “triggers”,
follow up activities, and procedures that best fit its system, thereby providing for the flexibility that you have suggested. The SDT feels this is a better
approach than to have a rigid definition of an imminent threat procedure.
2. See response 1 above.
3. See response 1 above.
4. See response 1 above.
Salt River Project
Disagree
Agree with R1.4, however with the suggested change: Remove the language "?and may include actions such as
a temporary reduction in line Rating, switching lines out of service, or other actions.". Any standard should not
contain advisory-type language, it should be declarative in tone. The suggested actions are not the
responsibility of the vegetation management program.
Response: Thank you for your comment. The advisory type language has been removed from the requirement as you have suggested. The SDT also
agrees that these “advisory” actions could fall outside the responsibility of some utilities’ Transmission Vegetation Management Program. The main
purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power
system. Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible
control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible
operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and
procedures that best fit its situation.
Northeast Utilities
September 8, 2009
Disagree
Agree with the need to have and implement when necessary an imminent threat procedure. Disagree with the
need to implement the imminent threat procedure merely because a Critical Clearance Zone is being
approached, as required by R2. Is there a desired distance from the Critical Clearance Zone where this
procedure must be implemented, since all vegetation within a right-of-way will "approach" the Critical Clearance
Zone as it grows? How will time of year and operating conditions be factored in, which may change the
requirements to perform control during periods of low temperature or low load? It would not be necessary to
perform all the requirements of an imminent threat procedure when there is adequate clearance to schedule the
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work without jeopardizing the reliability of the system. For example, in mid winter a line is 8 feet from a tree there is little chance of the line reacing maximum sag at that time of year and the present condition does not
constitute an imminent threat at that time. Also, disagree with the requirement for the imminent threat procedure
to include actions that could be taken by the Transmission OwnerP (reduction in line rating, switching). The
requirement should be limited to notifications to the Transmission OwnerP, since decisions on what specific
system operating actions to take are beyond the responsibility of the Transmission Owner. The decision on what
actions to take needs to be performed either by the Transmission OwnerP, or by the Transmission OwnerP in
conjunction with the Transmission Owner.
Response: Thank you for your comments. We agree with your comments concerning the Critical Clearance Zone and the elusiveness of the term
“approach”. Subsequently, the Critical Clearance Zone methodology as it refers to the imminent threat process has been removed from the Standard.
The SDT also agrees that the main purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of
the power system’s status. . Please also note that the wording has been altered to change the “Transmission Operator” to the “responsible control
center” to better identify the appropriate responsible party. The salient requirement of an imminent threat procedure is notification of the responsible
operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to develop an imminent threat procedure that
best fits its system, and allows the Transmission Owner to make appropriate decisions on follow up actions.
Hydro-Quebec Transenergie
(HQT)
September 8, 2009
Disagree
While we strongly agree that an imminent threat procedure should be required in the Transmission Vegetation
Management Program, we disagree with some specific wording in R1.4. R1.4 requires immediate
communication of an imminent threat to the Transmission Operator, which we would normally agree with. R2
however requires that the imminent threat procedure be implemented when the Critical Clearance Zone (Critical
Clearance Zone ) is approached by vegetation. "Approached" is not defined as a specific distance, so this part
of the requirement is left up to the individual's interpretation. In cases where the Critical Clearance Zone is
approached by vegetation no threat to the system is possible if the vegetation is removed before it actually
grows into the Critical Clearance Zone . In many cases the vegetation can be removed without taking clearance
outages because the Critical Clearance Zone is large, and the conductor and vegetation are still relatively far
apart. In such cases there is no need to notify the Transmission Operator, although there is a need to remove
the vegetation immediately. We recognize that the opposite is also true, and that in some cases it will be
necessary to notify the Transmission Operator because a clearance outage or line de-rating may be required to
remove the vegetation. We therefore suggest a simple change to the wording of the second sentence of R1.4.
Change "?. specify actions which shall include immediate communication of the threat to the Transmission
Operator, and may include actions such as a temporary reduction in line Rating, switching lines out of service, or
other actions" to ".. specify actions which may include immediate communication of the threat to the
Transmission Operator, a temporary reduction in line Rating, switching lines out of service, or other actions".
This change will address the issue which is described above and will allow each Transmission Operator to
develop an imminent threat procedure that best fits their system. It should also be noted that many Transmission
Operators have imminent threat procedures in place to address all imminent threats to their transmission system,
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not just threats due to vegetation. It makes sense for Transmission Owners to have only one imminent threat
process; therefore the flexibility that can be achieved in the context of this standard would be helpful.
Response: Thank you for your comments. We agree with your comments concerning the Critical Clearance Zone and the elusiveness of the term
“approach”. Subsequently, the Critical Clearance Zone methodology has been removed from the Standard. The SDT feels that the main purpose of the
imminent threat requirement is to enhance the responsible control center’s situational awareness of the power system’s status. The wording about
other follow up actions that could be taken has been removed from the requirement. Please also note that the wording has been altered to change
the “Transmission Operator” to the “responsible control center” to better identify the appropriate responsible party. The SDT maintains that the
salient requirement of an imminent threat procedure is notification of the responsible operator of any imminent threat to the power system. Beyond
this, it is left to the Transmission Owner to develop an imminent threat procedure that best fits its system.
Pepco Holdings, Inc
Disagree
While an imminent threat procedure is prudent and reasonable, it does not need to consider a Critical Clearance
Zone as addressed in our comments on other questions. In fact, one can quickly provide examples of imminent
threats when the threat is not even on the right of way. The Transmission Owner should simply have an
imminent threat procedure to address identified imminent or potential imminent threats.
Response: Thank you for your comment. We agree with your comments concerning the Critical Clearance Zone methodology. Subsequently, the
Critical Clearance Zone methodology has been removed from the Standard. The SDT feels that the main purpose of the imminent threat requirement is
to enhance the responsible control center’s situational awareness of the power system’s status. Please also note that the requirement wording has
been altered to change the “Transmission Operator” to the “responsible control center” to better identify the appropriate responsible party. The SDT
maintains that the salient requirement of an imminent threat procedure is notification of the responsible operator of any imminent threat to the power
system. Beyond this, the SDT agrees that it should be left to the Transmission Owner to develop an imminent threat procedure that best fits its
system.
Southern California Edison
Company
Agree
Q7: SCE agrees in part with the content of R1.4 because of its similarity to existing requirement R1.5 in FAC003-1. However, we disagree with the drafter’s inclusion of peripheral information following the first sentence.
We also note that the second sentence of proposed R1.4 includes both a requirement and a recommendation.
SCE believes this and similar recommendations are best suited for the supporting technical paper. SCE
respectfully suggests that R1.4 be revised to read: "Specify a process or procedure for communicating an
impending vegetation-to-line contact that may result in a sustained outage and the appropriate response
measures.”
Response: Thank you for your comment. The SDT feels that the main purpose of the imminent threat requirement is to enhance the responsible
control center’s situational awareness of the power system’s status. We agree with your suggestions to exclude some of the peripheral language
included in this requirement. Thus, the SDT has removed references to the Critical Clearance Zone, the word “immediate”, and the wording referring
to other actions that may be taken by the responsible operator. Please also note that the wording has been altered to change the “Transmission
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Operator” to the “responsible control center” to better identify the appropriate responsible party.
Western Utility Arborists
Agree
We agree with 1.4, with the following qualification: Any standard that is developed should not contain advisorytype language” it should be declarative in tone. For example, in R1.4, the ending clause that begins “and may
include actions” should be removed because it is advisory in nature. The suggested actions are not even the
responsibility of the vegetation management program.
Response: Thank you for your comments. The advisory type language has been removed from the requirement as you have suggested. The SDT also
agrees that these “advisory” actions could fall outside the responsibility of some utilities’ Transmission Vegetation Management Program. The main
purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power
system. Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible
control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible
operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and
procedures that best fit its situation.
Bonneville Power Administration
Agree
BPA agrees with 1.4, with the following change. The ending phrase: "and may include actions such as a
temporary reduction in line Rating, switching lines out of service, or other actions" should be eliminated. Not
only does BPA feel it is inappropriate to use advisory-type rather than declarative language in a Standard, BPA
feels it is also questionable to give examples of imminent response actions that are often not within the direct
capability of a vegetation program to enact. Eliminating the reference to these possible actions leaves it up to
the Transmission Operator to decide what the eminent threat response is.
Response: Thank you for your comment. The advisory type language has been removed from the requirement as you have suggested. The SDT also
agrees that these “advisory” actions could fall outside the direct capability of some utilities’ Transmission Vegetation Management Program. The main
purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power
system. Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible
control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible
operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and
procedures that best fit its situation.
FirstEnergy
Agree
The safety of the personnel required to remove a tree or vegetation on or near an energized conductor must be
considered when implementing the imminent threat procedure. Although this is a reliability standard, the safety
of the personnel may be one "trigger" to implement the imminent threat procedure. That being said, the workers
on site, in their judgment, are not able to remove the vegetation safely then the imminent threat procedure would
be implemented. See comments for Critical Clearance Zone .
Response: Thank you for your comment. The SDT also believes human safety must be major consideration in this requirement. The Transmission
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Owner may include in its Imminent Threat procedure appropriate considerations for personnel safety as a trigger. The main purpose of the imminent
threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system. The SDT made
major changes to make the requirement less prescriptive. Also, the wording has been altered to change the designation “Transmission Operator” to
the “responsible control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the
responsible operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up
activities and procedures that best fit its situation. The Critical Clearance Zone methodology has been removed from the Standard.
MRO NERC Standards Review
Subcommittee
Agree
The MRO agrees and believes that it is very important for the applicable entities to posses a Imminent Threat
Procedure. The MRO also believes that the term "Imminent Threat" is subjective an should be defined.
Response: Thank you for your comment. We have made some major changes to this requirement due to the overwhelming response from industry
that the imminent threat requirement was needed, as long as it was not an overly prescriptive requirement. We do not agree that an imminent threat
should be defined in the Standard. The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational
awareness of reliability dangers to the power system. Please note that the requirement wording has also been altered to change the designation
“Transmission Operator” to the “responsible control center” to better identify the appropriate party. The salient requirement of an imminent threat
procedure is notification of the responsible operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to
determine the follow up activities and procedures that best fit its system. The SDT feels this is a better approach than to have a rigid definition of an
imminent threat procedure.
Western Area Power
Administration, Rocky Mountain
Region
Agree
The Technical Reference document could be expanded to explain that a well rounded Imminent Threat
Procedure should contain many mitigation alternatives to appropriately address a wide range of field situations,
including a "no immediate field action is required" option. For example, further investigation of a potential
imminent threat situation may reveal that the situation has been erroneously reported or incorrectly measured
and therefore no immediate vegetation removal actions are required. A utility's Imminent Threat Procedure may
also address situations beyond just vegetation related incidents.
Response: Thank you for your comment. The SDT agrees that many situations can constitute an imminent threat beyond just vegetation related
incidents. The requirement has been rewritten to focus on the main purpose of the imminent threat requirement; which is to enhance the responsible
control center’s situational awareness of reliability dangers to the power system. Please note that this requirement’s wording has also been altered to
change the designation “Transmission Operator” to the “responsible control center” to better identify the appropriate party. The salient requirement of
an imminent threat procedure is notification of the responsible operator of any potential threat to the power system. Beyond this, it is left to the
Transmission Owner to determine the follow up activities and procedures that best fit the wide range of field situations that are possible to encounter.
Platte River Power Authority
September 8, 2009
Agree
Imminent threat is not a defined term in the NERC Glossary of Terms so it could be construed as a fill-in-theblank requirement by FERC as each Transmission Owner could define Imminent Threat differently. Imminent
threat should be defined or the requirement should be reworded to define what types of situations would require
a procedure. Also, the language, "and may include actions such as a temporary reduction in line rating, switching
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lines out of service, or other actions" should be removed from the standard but could be included in the imminent
threat procedure or definition.
Response: The SDT has made some major changes to this requirement due to the overwhelming response from industry that the imminent threat
requirement was needed, as long as it was not an overly prescriptive requirement. For instance, we agree that the wording referring to other follow up
actions that may be taken by the operator is too prescriptive and has been removed from this requirement.
The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the
power system. Please note that the requirement wording has also been altered to change the designation “Transmission Operator” to the
“responsible control center” to better identify the appropriate party. The SDT feels this is a better approach than to have a rigid definition of an
imminent threat procedure. The salient requirement of an imminent threat procedure is notification of the responsible operator of any imminent threat
to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and procedures that best fit the wide range
of field situations that are possible to encounter.
USDA Forest Service,
Southwestern Region, Regional
Office for AZ and NM
Agree
The USFS would be expecting the Transmission Owner to be documenting the imminent threat procedures in an
operating plan or corridor management plan that would be approved by the designated USFS decision maker. If
such procedures are documented in the Transmission Owner's Transmission Vegetation Management Program
and are compatible with USFS resource management direction, then the imminent threat procedures could be
incorporated in the agency-approved operating plan by reference. If the Transmission Owner disputes any
restrictions that are placed by the USFS on the imminent threat procedures, the USFS has an administrative
appeals process which the Transmission Owner can use, but those procedures can be time-consuming and
probably would not be perceived by the Transmission Owner as being neutral for negotiation purposes. It might
help if a third federal party like NERC could help resolve disputes between the Transmission Owner and the
USFS on the imminent threat procedures. Although the USFS would object to unreasonable intrusion of NERC
into normal USFS land management prerogatives, imminent threat procedures would seem to be a topic for
which NERC should take a very strong position, especially with a standard that identifies minimum vegetation
clearances as related to prevention of arcing potential, or in other words, vegetation that should be considered
hazardous and in immediate need of treatment.
Response: Thank you for your comments. The SDT developed this standard to apply to Transmission Owners in support of bulk electric system
reliability. While there may be similar areas of regulation between the purview of NERC and the USFS, this standard is not intended to be incompatible
with any USFS resource management direction. That being said, any NERC standard approved by the FERC does not need to be incorporated into “the
agency-approved operating plan”. In regard to the suggestion that NERC assist in resolving disputes between USFS and Transmission Owners, this
would be beyond the scope of NERC.
The SDT suggests that USFS and affected Transmission Owners review language in permits and change that language to allow perpetual ingress and
egress and vegetation maintenance without case-by-case application and review. Such a change would prevent current problems where it takes
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upwards of one year before vegetation maintenance is allowed to proceed.
The SDT has made some major changes to this requirement due to the overwhelming response from industry that the imminent threat requirement was
needed, as long as it was not an overly prescriptive requirement. For instance, we agree that the wording referring to other follow up actions that may
be taken by the operator is too prescriptive and has been removed from this requirement.
The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the
power system. Please note that the requirement wording has also been altered to change the designation “Transmission Operator” to the
“responsible control center” to better identify the appropriate party. The SDT feels this is a better approach than to have a rigid definition of an
imminent threat procedure. The salient requirement of an imminent threat procedure is notification of the responsible operator of any imminent threat
to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and procedures that best fit the wide range
of field situations that are possible to encounter.
Manitoba Hydro
Agree
Suggest removing, "and may include actions such as a temporary reduction in line rating, switching lines out of
service, or other actions", as this is outside the scope of a vegetation management program.
Response: Thank you for your comment. The language you mention has been removed from the requirement as you have suggested. The SDT agrees
that these actions could fall outside the scope of some utilities’ Transmission Vegetation Management Program. The main purpose of the imminent
threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system. Please note that
this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible control center” to better
identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible operator of any imminent
threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and procedures that best fit its
situation.
Pacific Gas & Electric Co.
Agree
PG&E agrees an imminent threat procedure is a critical component of the standard and should be contained in
the Transmission Vegetation Management Program. See additional comments for Q11.
Response: Thank you for your comment. See the responses to comments on Q11.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Agree
We agree with 1.4, with the following qualification: Any standard that is developed should not contain advisorytype language? it should be declarative in tone. For example, in R1.4, the ending clause that begins “and may
include actions” should be removed because it is advisory in nature. The suggested actions are not even
applicable under the scope of a vegetation management program.
Response: Thank you for your comment. The advisory type language has been removed from the requirement as you have suggested. The SDT also
agrees that these “advisory” actions could fall outside the scope of some utilities’ Transmission Vegetation Management Program. The main purpose
of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system.
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Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible control
center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible operator of
any potential threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and procedures that
best fit its situation
San Diego Gas & Electric
Agree
We recommend that any advisory language be removed, and replaced with a declaration to the utilities.
Response: Thank you for your comment. The advisory type language has been removed from the requirement as you have suggested, The remaining
declaratory language addresses the main purpose of the imminent threat requirement which is to enhance the responsible control center’s situational
awareness of reliability dangers to the power system. Please note that this requirement’s wording has also been altered to change the designation
“Transmission Operator” to the “responsible control center” to better identify the appropriate party. The salient requirement of an imminent threat
procedure is notification of the responsible operator of any potential threat to the power system. Beyond this, it is left to the Transmission Owner to
determine the follow up activities and procedures that best fit its situation
WECC
Agree
But for clarity, "Imminent Threat Procedure" should be replaced with "Vegetation Imminent Threat Procedure".
Response: Thank you for your comment. The SDT believes that the context is sufficiently clear.
Arizona Public Service Company Agree
APS agrees with 1.4, with the following qualification: Any standard that is developed should not contain advisorytype language? it should be declarative in tone. For example, in R1.4, the ending clause that begins “and may
include actions” should be removed because it is advisory in nature. The suggested actions are not even the
responsibility of the vegetation management program.
Response: Thank you for your comment. The advisory type language has been removed from the requirement as you have suggested. The SDT also
agrees that these “advisory” actions could fall outside the responsibility of some utilities’ Transmission Vegetation Management Program. The main
purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power
system. Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible
control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible
operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and
procedures that best fit its situation.
Baltimore Gas & Electric
Company
September 8, 2009
Agree
This requirement references Danger trees which according to ANSI A-300, Part 7 is any tree that could fall on
the conductor. Should this more appropriately be changed to Hazard tree which is a structurally unsound tree?
It might be helpful if an imminent threat were defined, e.g. trees that are presently encroaching in or near the
Critical Clearance Zone , or trees that by virtue of their hazardous condition appear to be likely to fall into or
near the Critical Clearance Zone in the near future. (or just leave the explanation to the White Paper)
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Response: Thank you for your comment. We agree with most of your comments and have made some major changes to this requirement due to the
overwhelming response from industry that the imminent threat requirement was needed, as long as it was not an overly prescriptive requirement.
Many situations can constitute an imminent threat, “danger” or “hazard” trees being only one of those situations. Further, due to the undefined
“triggers” associated with the Critical Clearance Zone methodology, this approach has been removed from the Standard.
The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the
power system. Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the
“responsible control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the
responsible operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the “triggers”, follow
up activities, and procedures that best fit its situation. The SDT feels this is a better approach than to have a rigid definition of an imminent threat.
JEA
Agree
It is appropriate to require procedures to respond to "emergency” conditions; however Imminent Vegetation
Threat should be a defined term.
Response: Thank you for your comment. The SDT prefers to allow the verbiage “an imminent threat of a vegetation-related Sustained Outage” to stand
without further definition.
BCTC
Agree
We agree with 1.4, with the following qualification: Any standard that is developed should not contain advisorytype language—it should be declarative in tone. For example, in R1.4, the ending clause that begins “…and may
include actions…” should be removed because it is advisory in nature. The suggested actions are not even the
responsibility of the vegetation management program.
Response: Thank you for your comment. The advisory type language has been removed from the requirement as you have suggested. The SDT also
agrees that these “advisory” actions could fall outside the responsibility of some utilities’ Transmission Vegetation Management Program. The main
purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power
system. Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible
control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible
operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and
procedures that best fit its situation.
Great River Energy
Agree
GRE agrees and believes that it is very important for the applicable entities to posses an Imminent Threat
Procedure. GRE recommends that the Imminent Threat procedure be renamed "Vegetation Imminent Threat
Procedure" so as to clearly identify the procedure in the event that a company has imminent threat procedures
for more than one situation.
Response: Thank you for your comment. We agree that many situations can constitute an imminent threat; however, the SDT did not rename the
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overall procedure as you have suggested. It is acceptable to have the imminent threat procedure for this standard included in a larger corporate
procedure or set of procedures that address a wider array of threats. Instead the requirement has been rewritten to focus on the main purpose of the
imminent threat requirement; which is to enhance the responsible control center’s situational awareness of reliability dangers to the power system.
Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible control
center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible operator of
any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and procedures that
best fit its situation. The SDT feels that this approach allows the Transmission Owner the flexibility to have imminent threat procedures for more than
one situation which remain outside the specific requirements of the vegetation Standards.
Santee Cooper
Agree
Exelon
Agree
Central Maine Power Company
Agree
WECC Reliability Coordination
Agree
Western Area Power
Administration, Upper Great
Plains Region
Agree
Kansas City Power & Light
Agree
City of Tallahassee
Agree
Northern California Power
Agency (NCPA)
Agree
Northern Indiana Public Service
Company
Agree
Long Island power Authority
Agree
National Grid
Agree
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Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
CenterPoint Energy
Agree
Buckeye Power, Inc.
Agree
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8. Requirement 1 section R1.5 replaces Version 1 sub-requirement R1.4. This section is now referred to as interim
corrective action process. This process addresses situations where vegetation maintenance activities cannot be
performed as planned. The term corrective action plan is used in lieu of mitigation plan to avoid confusion with other
uses in NERC of “mitigation plan”. Do you agree with R1.5? If not, please explain.
Summary Consideration: Many of the stakeholders asked about the use of the word “interim” in R1.5 and what a constraint
is. The SDT explains that 1.3 of the version 2 standard is intended to allow Transmission Owners to adjust the annual work plan
to reflect such changes as a long term fix. Part 1.5 is intended to address an interim constraint such as customer refusals,
governmental agency imposed restrictions, etc. To help clarify, the SDT added the word “temporarily” to the language noted in
requirement R1.5. The SDT also added a new requirement R1.6 to address long term strategies.
1.5
Specify an interim corrective action process for use when the Transmission Owner is temporarily constrained from
performing vegetation maintenance as planned.
1.6
Specify the maintenance strategies used (such as minimum vegetation-to-conductor distance or maximum vegetation
height) to ensure that Table 1 clearances in Attachment 1 are never violated. The maintenance strategies shall consider
the sag and sway of the conductor throughout its operating range under rated conditions.
Organization
Agree?
Question 8 Comment
The specifics of a "plan" as required by R1.4 in version 1 of the Standards has been replaced with the
generalities of a "process" required by R1.5 in version 2 of the Standards. At the time of an audit, the adequacy
of a general process is harder to measure than the adequacy of the specific mitigation measures that were
previously required by R1.4 in version 1 of the Standards. It is unclear what an auditor will be looking for to
determine compliance with R1.5 - will the auditor be looking for generalities or specifics? Further, if a utility has
documented their interim corrective action process, but it is not followed, is this a violation of the Standards?
Western Area Power
Administration, Rocky Mountain
Region
Response: Thank you for your comments. The SDT intended to require a documented process for Transmission Owners to develop plans which
address instances such as customer refusals, government agency imposed constraints, etc. It is not intended solely for situations where initial desired
clearances could not be achieved (as in requirement R1.4 of version 1 of FAC-003). The measure for Interim Corrective Action requires it be included in
the Transmission Vegetation Management Program and failure to do so would be a violation.
City of Tallahassee
September 8, 2009
Disagree
The use of the term "interim corrective action" implies that a permanent solution or return to the original plan
must be pursued. I would change this to "alternate maintenance" process to prevent non-compliance if the
Transmission Owner is constrained and has reached an agreement with the land owner that works to maintain
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the reliability of the line.
Response: Thank you for your comment. Requirement R1, Part 1.5 requires the Transmission Owner to specify a process in its Transmission
Vegetation Management Program that the Transmission Owner may use when vegetation maintenance work is temporarily constrained. Constraints
may include temporary situations such as caused by customer refusals, governmental agency imposed restrictions, etc. If a Transmission Owner
reaches an agreement for “alternate maintenance” in these situations, Requirement R1,Part 1.3.3 allows for adjustment of the annual work plan.
Alternative maintenance actions as suggested are now addressed in new Requirement R1,Part 1.6 as noted above in the consideration of comments to
address long term maintenance strategies to ensure Table 1 clearance distances are never violated.
Northern Indiana Public Service Disagree
Company
The existing R1.4 is focused on identifying where vegetation clearance objectives cannot be met at the time UVM
work is performed due to restrictions outside of the Transmission Owner's immediate control. The proposed
revised standard is focused on situations where work scheduled in the annual plan cannot be performed as
planned for any reason. Can a constraint on planned work be internal such as budget related? Why bother with a
corrective process for constrained planned work if the work not completed as planned poses no risk of causing
an outage? I strongly believe that the sole focus of this provision must specifically address individual locations
where, due to restrictions outside of the Transmission Owner owner's control, vegetation clearances specified in
the Transmission Vegetation Management Program cannot be obtained. This section of the standard should be
about trees being closer to conductors than they should be due to factors beyond the Transmission Owner's
control, rather than whether or not planned work was performed.
Response: Thank you for your comments. Interim corrective actions are intended to address situations such as customer refusals, governmental
agency imposed constraints, etc. Requirement R1, Part 1.3 requires that the annual work plan shall be documented and Requirement R1, Part 1.3.3
permits adjustments to the annual work plan. A Requirement R1, Part 1.6 was added to address long term maintenance strategies to ensure Table 1
clearance distances are never violated.
Tampa Electric Company
Disagree
The phrasing above references a "corrective action plan". However, the standard as written is stated as an
"interim corrective action process". These are not one and the same. Interim implies a truly temporary condition.
As described on page 21 of the Technical reference, however, some of these operational issues may not be
"interim".
Response: Thanks for your comments. The SDT agree that “interim” should have been included in the question. The Technical Reference document
does not appear to be in conflict with this. To add clarity the SDT added the word temporarily to Requirement R1, Part 1.5 and long term strategies are
addressed in new Requirement R1, Part 1.6 a to address long term maintenance strategies to ensure Table 1 clearance distances are never violated.
Manitoba Hydro
September 8, 2009
Disagree
Agree with the change in terminology - but would suggest that wording clarify that this is not only for situations
where the utility is unexpectedly prevented from implementing its annual plan - but also for areas where it is
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unable to implement its clearance requirements due to property rights limitations.
Response: Thank you for your comment. Requirement R1, Part 1.5 requires the Transmission Owner to specify a process in its Transmission
Vegetation Management Program that the Transmission Owner may use when vegetation maintenance work is temporarily constrained. Constraints
may include temporary situations such as caused by customer refusals, governmental agency imposed restrictions, etc. Requirement R1, Part 1.6 was
added to address long term maintenance strategies to ensure Table 1 clearance distances are never violated.
National Grid
Disagree
National Grid agrees replacing mitigation plan with corrective action process. However, National Grid questions
the use of "interim" for a corrective action process in R1.5, and suggests striking "interim".
Response: Thank you for your comment. Requirement R1, Part 1.5 requires the Transmission Owner to specify a process in its Transmission
Vegetation Management Program that the Transmission Owner may use when vegetation maintenance work is temporarily constrained. Constraints
may include temporary situations such as caused by customer refusals, governmental agency imposed restrictions, etc. To add clarity the SDT added
the word “temporarily” to Requirement R1, Part 1.5.
CenterPoint Energy
Disagree
Since there is no longer a reference to defined clearances in the Standard, it is unclear under what specific
"constrained" conditions R1.5 applies. R1.5 does not have a sister requirement for implementation within the
Standard which implies it has a diminished value. R1.5 and M1.5 should be deleted as a requirement and
measure, but should be footnoted as best practice as was ANSI A300 in R1.1.
Response: Thank you for your comments. The SDT intended to require a documented process for Transmission Owners to develop plans which
address instances such as customer refusals, government agency imposed constraints, etc. It is not intended solely for situations where initial desired
clearances could not be achieved (as in requirement R1.4 of version 1 of FAC-003). A new Requirement R1, Part1.6 was added to address long term
maintenance strategies to ensure Table 1 clearance distances are never violated.
American Transmission
Company
Agree
ATC agrees with the concept but disagrees with the proposed language. ATC believes the term "interim" should
be removed from R 1.5. In some cases, a corrective action can end up being a long term/normal fix. Proposed
Language: Specify a corrective action process that will be used when established clearances or methodologies
are altered.
Response: Requirement R1, Part 1.3 requires that the annual work plan shall be documented. Requirement R1, Part 1.3.3 permits adjustments to the
annual work plan. A long term fix would be an adjustment to the annual work plan. In Requirement R1, Part 1.5, the SDT intended to require a
documented process for Transmission Owners to develop plans which address instances such as customer refusals, government agency imposed
constraints, etc. It is not intended solely for situations where initial desired clearances could not be achieved (as in requirement R1.4 of version 1 of
FAC-003). To add clarity the SDT added the word “temporarily” to Requirement R1, Part 1.5. Long term strategies are addressed in new requirement
R1.6 as noted above in the consideration of comments to address long term maintenance strategies to ensure Table 1 clearance distances are never
September 8, 2009
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Organization
Agree?
Question 8 Comment
violated.
Southern California Edison
Company
Agree
Q8: SCE agrees in part with the revisions to R1.5, including the proposed phrase "corrective action process".
However, we do not believe it is necessary to include the term "Transmission Owner" in the sentence because
the entire standard is clearly applicable to Transmission Owners. SCE respectfully suggests that proposed R1.5
be revised to read: "Specify an interim corrective action process for use when planned vegetation maintenance is
deterred."
Response: Thank you for your comment. The SDT considered your suggested language and feels the language used in the draft standard is
appropriate in order to maintain consistency with other parts of the standard.
Western Utility Arborists
Agree
Yes, we agree.
Response: Thank you for your participation.
FirstEnergy
Agree
We agree with the concept of a corrective action plan. However, it is not clear what flexibility the Transmission
Owner is afforded in making adjustments to the work plan that may carry over from one calendar year to the next.
Legal issues with property owners or other factors may prevent the utility from carrying out the work plan as
scheduled. Also, we question the use of the term "constrained". It should be clear as to what constitutes
appropriate or valid constraints.
Response: Thank you for your comments. Requirement R1, Part 1.3.3 permits adjustments to the annual work plan. As to your next concern,
Requirement R1, Part 1.5 requires the Transmission Owner to specify a process in its Transmission Vegetation Management Program that the
Transmission Owner may use when vegetation maintenance work is temporarily constrained. Constraints may include temporary situations such as
caused by customer refusals, governmental agency imposed restrictions, etc. Refer to the Technical Reference document for additional information.
MRO NERC Standards Review
Subcommittee
Agree
The MRO believes that the term "interim" should be removed from R1.5. The term Interim is subjective.
Response: Thank you for your comment. The SDT uses “interim” to convey the temporary nature of these situations. To add clarity the SDT added the
word “temporarily” to Requirement R1. Part 1.5 and a new Requirement R1, Part 1.6 was added to address long term maintenance strategies to ensure
Table 1 clearance distances are never violated.
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 8
Response: Thank you for your participation.
September 8, 2009
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Organization
Platte River Power Authority
Agree?
Agree
Question 8 Comment
The term corrective action plan adds clarity.
Response: Thank you for your participation.
USDA Forest Service,
Agree
Southwestern Region, Regional
Office for AZ and NM
In my opinion, problems between the Transmission Owner and the USFS over the Transmission Vegetation
Management Program should be worked out before a Transmission Vegetation Management Program is ever
finalized. A dispute resolution process outside the control of either party would be very helpful and would
probably facilitate quicker solutions than if the Transmission Owner and the USFS are left to work out problems
on their own. If a Transmission Vegetation Management Program is prepared in a vacuum, the problems may not
come to light until some kind of outage actually occurs. It would be much better to flush any disagreements and
deal with them before any outages actually occur.
Response: Thank you for your comment. We agree with the sentiment of collaboration and cooperation expressed. We are somewhat constrained by
the types of entities that must be subject to this standard. The USFS, as a government agency, is not under the purview of the FERC and is not
compelled to comply with this standard however well intended. The SDT would support a dispute resolution process that resolves potential
disagreements consistent with the purpose of this standard.
BCTC
Agree
Yes, we agree.
Response: Thank you for your participation.
Great River Energy
Agree
GRE believes that the term "interim" should be removed from R1.5. The term Interim is subjective.
Response: Thank you for your comment. Requirement R1, Part 1.5 requires the Transmission Owner to specify a process in its Transmission
Vegetation Management Program that the Transmission Owner may use when vegetation maintenance work is temporarily constrained. Constraints
may include temporary situations such as caused by customer refusals, governmental agency imposed restrictions, etc. To add clarity the SDT added
the word temporarily to Requirement R1, Part 1.5 and long term strategies are addressed in new Requirement R1, Part1.6 to address long term
maintenance strategies to ensure Table 1 clearance distances are never violated.
Progress Energy Carolinas
Agree
Associated Electric Cooperative Agree
Inc.
NPCC
Agree
September 8, 2009
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Organization
Agree?
WECC Reliability Coordination
Agree
Western Area Power
Administration, Upper Great
Plains Region
Agree
SERC Vegetation Management
Subcommittee (VMS)
Agree
Progress Energy Florida
Agree
Kansas City Power & Light
Agree
SERC OC Standards Review
Group
Agree
Florida Power & Light
Agree
Santee Cooper
Agree
Southern Company
Agree
E.ON U.S.
Agree
Bonneville Power
Administration
Agree
Midwest ISO Stakeholders
Standards Collaborators
Agree
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
September 8, 2009
Question 8 Comment
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Organization
Agree?
Exelon
Agree
Central Maine Power Company
Agree
American Electric Power (AEP)
Agree
Northern California Power
Agency (NCPA)
Agree
Orange and Rockland Utilities
Inc.
Agree
Ameren
Agree
Nebraska Public Power District
Agree
Long Island power Authority
Agree
Consumers Energy Company
Agree
Pacific Gas & Electric Co.
Agree
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Agree
San Diego Gas & Electric
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
Consolidated Edison Company
of New York (CECONY)
Agree
September 8, 2009
Question 8 Comment
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Organization
Agree?
WECC
Agree
Arizona Public Service
Company
Agree
Baltimore Gas & Electric
Company
Agree
Duke Energy Corporation
Agree
Entergy Services
Agree
Pepco Holdings, Inc
Agree
JEA
Agree
Independent Electricity System
Operator
Agree
Salt River Project
Agree
Northeast Utilities
Agree
Hydro-Quebec Transenergie
(HQT)
Agree
Buckeye Power, Inc.
Agree
September 8, 2009
Question 8 Comment
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9. Clearance 1 in Version 1 was a “fill-in-the-blank” requirement and was removed from the standard. Do you agree? If
not, please explain.
Summary Consideration: Most of the industry comments are in favor of removing the “fill-in-the-blank” requirement. Some
disagreed, citing the benefit of having perceived leverage that a Clearance 1 afforded them. The SDT points out that ANSI A300
remains a “best practice” referenced in the proposed standard and may be useful in dealing with public and private parties. In
addition, the SDT added Requirement R1.6:
1.6
Specify the maintenance strategies used (such as minimum vegetation-to-conductor distance or maximum vegetation
height) to ensure that Table 1 clearances in Attachment 1 are never violated. The maintenance strategies shall consider
the sag and sway of the conductor throughout its operating range under rated conditions.
The SDT believes that Clearance 1 may be unnecessarily restrictive in stipulating conductor-to-vegetation distances (as some
commenters have done to comply) and therefore removed Clearance 1 in favor of Requirement R1, Part 1.6. which specifically
allows for vegetation-to-ground distances to be used while at the same time accounting for the sag and sway of the conductor
throughout its operating range under rated conditions.
Organization
Agree?
Florida Power & Light
Question 9 Comment
FPL neither agrees or disagrees with this removal but provides the following comment. FPL's experience
regarding Clearance 1 is that it was an effective way of demonstrating a measurable requirement for compliance
when dealing with public entities. The use of a corrective action process to mitigate instances where this
clearance was not met before violations occurred is also very effective in promoting reliability and safety in the
Standard.
Response: Thank you for your comment. The SDT team acknowledges the comment with regard to the usefulness of Clearance 1 in dealing with public
entities and has attempted to retain that capability in Requirement R1, Part 1.6. Furthermore the use of a corrective action process is retained in this
latest version but is renamed as an “interim correction action” in lieu of “Mitigation Plan” to avoid confusion with a Compliance Program term.
Western Utility Arborists
September 8, 2009
Disagree
The Western Utilities do not agree with the removal of Clearance 1. We recommend adding it back to the
document, but reworded and moved to include it as a measurement (M), rather than a requirement (R) under the
new standard. Many utilities feel that Clearance 1 provides justification and leverage for operational clearances
when dealing with organizations such as municipalities. Without Clearance 1, utilities could be mandated in
specific situations to clear so that the vegetation is just beyond the Critical Clearance Zone at all times. This
could result in pruning at six month intervals, which is not feasible or cost-effective.
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Organization
Agree?
Question 9 Comment
Response: Thank you for your comment. The SDT notes that information contained in a Measure would not be mandatory nor enforceable and
therefore has minimal usefulness as leverage. The SDT points out that ANSI A300 remains a “best practice” referenced in the proposed standard and
may be useful in dealing with the public and private parties. The addition of Requirement R1, Part 1.6 allows for vegetation-to-ground working
distances to be used while at the same time accounting for the sag and sway of the conductor throughout its operating range under rated conditions.
The SDT believes this is superior to Clearance 1 as this gives Transmission Owners more flexibility in how they can achieve the reliability objective of
Requirement R1.
Bonneville Power Administration
Disagree
BPA opposes removal of Clearance 1. Clearance 1 provides a regulatory justification for a Transmission Owner
to apply and extend proactive vegetation threat prevention programs on its rights of way easements across
municipal, state, tribal, other federal and private properties. In many cases, without the regulatory leverage of a
Clearance 1 requirement, Transmission Owners would be limited to maintaining less effective and higher risk
vegetation management practices where it has legal restrictions, then it presently can implement under the
present version of FAC 003-01. BPA recommends that Clearance 1 be placed back into the document, but as a
Measure and not a Requirement.
Response: Thank you for your comment. The SDT notes that information contained in a Measure would not be mandatory nor enforceable and
therefore has minimal usefulness as leverage. The SDT points out that ANSI A300 remains a ”best practice” referenced in the proposed standard and
may be useful in dealing with the public and private parties. The addition of Requirement R1, Part 1.6 allows for vegetation-to-ground working
distances to be used while at the same time accounting for the sag and sway of the conductor throughout its operating range under rated conditions.
The SDT believes this is superior to Clearance 1 as this gives Transmission Owners more flexibility in how they can achieve the reliability objective of
Requirement R1.
Exelon
Disagree
We do not understand the reference to "fill in the blank" requirement for clearance 1. As commonly understood,
a "fill in the blank" standard /requirement is one that was assigned to the RRO. Clearance 1 in FAC-003-1 is a
Transmission Owner requirement. The reference to a clearing zone should be retained, as each Transmission
Owner will need to define this in their program so as to avoid encroachments into the Critical Clearance Zone .
Response: Thank you for your comment. The choice of a Clearance 1 distance is left to each Transmission Owner and as such is characterized as a
fill-in-the blank style requirement. The SDT team believes each Transmission Owner is free to set any working distances it deems appropriate in order
to accomplish its Transmission Vegetation Management Program objectives.
Central Maine Power Company
September 8, 2009
Disagree
Central Maine Power Company disagrees with removal of clearance 1. The clearance 1 was included so that
professional arborists could establish the clearance necessary for a transmission owner to reduce the risk of a
tree caused power outage. The transmission owner should use ANSI- Standard A300, including PART 7, and
other publications to develop best management practices which include clearances at time of maintenance.
Clearance 1 provides leverage for Transmission Owners to achieve the clearances stated in their Transmission
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Organization
Agree?
Question 9 Comment
Vegetation Management Program.
Response: Thank you for your comment. The SDT notes that information contained in a Measure would not be mandatory nor enforceable and
therefore has minimal usefulness as leverage. The SDT points out that ANSI A300 remains a ”best practice” referenced in the proposed standard and
may be useful in dealing with the public and private parties. The addition Requirement R1, Part 1.6 allows for vegetation-to-ground working distances
to be used while at the same time accounting for the sag and sway of the conductor throughout its operating range under rated conditions. The SDT
believes this is superior to Clearance 1 as this gives Transmission Owners more flexibility in how they can achieve the reliability objective of
Requirement R1.
USDA Forest Service,
Southwestern Region, Regional
Office for AZ and NM
Disagree
If it is possible for NERC to identify minimum clearance standards as related to arcing potential for hazardous
vegetation, it would definitely help USFS field administrators to have some kind of hard and fast standards. If
that kind of approach is not reasonable in light of the need to adjust standards for various load conditions and
vegetation growth rates, then a prescribed formula for calculating minimum clearances would be the next best
thing.
Response: Thank you for your comment. The SDT proposes the table of Minimum Vegetation Clearance Distances in this revised version of the
standard in Requirement R4, which prohibits vegetation encroachment inside minimum vegetation clearance distances that are developed with Gallet
equations for flashover (arcing).
National Grid
Disagree
National Grid takes exception to the term "fill-in-the-blank". National Grid disagrees with the elimination of
Clearance 1. The Clearance 1 requirement in FAC-003-1 was meant to allow a Transmission Owner to
establish clearances to be achieved at the time of vegetation management work, and be sensitive to local and
regional conditions. National Grid believes that Clearance 1 is needed for public education and safety reasons.
Clearance 1 standards allow utilities to specify a cyclic programmatic approach, and gives the utility leverage
with local and state regulators and the public to achieve significantly larger than minimal clearances.
Response: Thank you for your comment. The choice of a Clearance 1 distance is left to each Transmission Owner and as such is characterized as a
fill-in-the blank style requirement. The SDT team believes each Transmission Owner is free to set any working distances it deems appropriate in order
to accomplish its Transmission Vegetation Management Program objectives. The SDT points out that ANSI A300 remains a ”best practice” referenced
in the proposed standard and may continue to be useful in dealing with the public and private parties. The addition of Requirement R1, Part 1.6 allows
for vegetation-to-ground working distances which can be larger than minimal clearances to be used while at the same time accounting for the sag and
sway of the conductor throughout its operating range under rated conditions. The SDT believes this is superior to Clearance 1 as this gives
Transmission Owners more flexibility in how they can achieve the reliability objective of Requirement R1.
September 8, 2009
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Platte River Power Authority
Agree?
Disagree
Question 9 Comment
Clearance 1 could be defined in the standard in tables developed using IEEE Standards for various voltages,
line spans and altitudes. Clearance 1 provides justification and leverage for operational clearances when dealing
with organizations such as municipalities. Without Clearance 1, utilities could be mandated in specific situations
to clear so that the vegetation is just beyond the Critical Clearance Zone at all times. This could result in
pruning at six month intervals, which is not feasible or cost-effective.
Response: Thank you for your comment. The SDT proposes the table of Minimum Vegetation Clearance Distances in this revised version of the
standard in Requirement R4, which prohibits vegetation encroachment inside minimum vegetation clearance distances that are developed with Gallet
equations for flashover (arcing). The SDT points out that the ANSI A300 remains a ”best practice” referenced in the proposed standard and may be
useful in dealing with the public such as municipalities and private parties. The addition of Requirement R1, Part 1.6 allows for vegetation-to-ground
working distances to be used while at the same time accounting for the sag and sway of the conductor throughout its operating range under rated
conditions. The SDT believes this is superior to Clearance 1 as this gives Transmission Owners more flexibility in how they can achieve the reliability
objective of Requirement R1.
Northern Indiana Public Service
Company
Disagree
I am strongly opposed to the removal of Clearance 1 from the standard. Being able to point to this provision has
been invaluable to internal communications with upper management and external discussions with land owners
and the public concerning UVM. In fact, other than the patrol/inspection requirements, no other provision in the
standard has been as essential to preventing grow-in tree contacts than Clearance 1. It has forced
Transmission Owner's across the country to re-claim overgrown ROW and re-commit to consistent UVM
practices. We all know how easy it is for Transmission Owner's to get weak in the knees in the face of public
opposition to proper and prudent UVM work even when it is clear what needs to be done. This dynamic is what
led us to the 2003 blackout to begin with. I would like to see the drafting team consider expanding upon the
existing model and create three clearances:
1. A clearance at the time work is performed,
2. An action threshold clearance which would trigger the Transmission Owner would take immediate action to
clear encroaching vegetation posing an unacceptable outage risk, and
3. A no closer than clearance in which vegetation would never be allowed to encroach in order to prevent
flashover.
Response: Thank you for your comment. The SDT team acknowledges the comment with regard to the usefulness of Clearance 1 to internal
communications and in dealing with public entities and has attempted to retain that capability Requirement R1. Part 1.6. The addition of Requirement
R1, Part 1.6 allows for vegetation-to-ground working distances to be used while at the same time accounting for the sag and sway of the conductor
throughout its operating range under rated conditions. The SDT believes this is superior to Clearance 1 as this gives Transmission Owners more
flexibility in how they can achieve the reliability objective of Requirement R1.
September 8, 2009
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Organization
Agree?
Question 9 Comment
In regard to working distances or as you put it , each Transmission Owner continues to able to set any working distances it deems appropriate in order
to accomplish its Transmission Vegetation Management Program objectives when complying with Requirement R1, Part 1.6.
With respect to your 3rd comment, the proposed version of the standard has Requirement R4, which prohibits vegetation encroachment inside
Minimum Vegetation Clearance Distances that are developed with Gallet equations for flashover.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Disagree
We do not agree with the removal of Clearance 1. We recommend adding it back to the document, but reworded
and moved to include it as a measurement (M), rather than a requirement (R) under the new standard. Many
utilities feel that Clearance 1 provides justification and leverage for operational clearances when dealing with
organizations such as municipalities. Without Clearance 1, utilities could be mandated in specific situations to
clear so that the vegetation is just beyond the Critical Clearance Zone at all times. This could result in pruning
at six month intervals, which is not feasible or cost-effective.
Response: Thank you for your comment. The SDT notes that information contained in a Measure would not be mandatory nor enforceable and
therefore has minimal usefulness as leverage. The SDT points out that ANSI A300 remains a “Best Practice” referenced in the proposed standard and
may be useful in dealing with the public and private parties. The addition of Requirement R1, Part 1.6 allows for vegetation-to-ground working
distances to be used while at the same time accounting for the sag and sway of the conductor throughout its operating range under rated conditions.
The SDT believes this is superior to Clearance 1 as this gives Transmission Owners more flexibility in how they can achieve the reliability objective of
Requirement R1.
San Diego Gas & Electric
Disagree
We do not agree with the removal of Clearance 1. We recommend that it be added back into the document, but
reworded and moved so it be included as a measurement, rather than a requirement. Without Clearance 1,
utilities could be mandated in specific situations to clear so that vegetation is just beyond the Critical Clearance
Zone at all times, which is not feasible or cost effective.
Response: Thank you for your comment. The SDT notes that information contained in a Measure would not be mandatory nor enforceable and
therefore has minimal usefulness as leverage. The SDT points out that ANSI A300 remains a “Best Practice” referenced in the proposed standard and
may be useful in dealing with the public and private parties. The addition of Requirement R1, Paart 1.6 allows for vegetation-to-ground working
distances to be used while at the same time accounting for the sag and sway of the conductor throughout its operating range under rated conditions.
The SDT believes this is superior to Clearance 1 as this gives Transmission Owners more flexibility in how they can achieve the reliability objective of
Requirement R1.
Hydro One Networks Inc.
September 8, 2009
Disagree
We would agree only if the standard is revised to include the removal of incompatible vegetation as outlined in
our response to question 3 above. If not, then added direction or requirements are needed to introduce the
elements that combine (to a greater degree than exists under the revised standard) reliability and vegetation
management. Clearance 1 accomplished this to some degree.
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Organization
Agree?
Question 9 Comment
Response: Thank you for your comment. The SDT considered the insertion of the phrase “incompatible vegetation” however decided against it
because incompatibility may be arguable and add to disagreement among interested parties. The SDT agrees with the commenter that all vegetation
that is identified by the annual work plans and maintenance strategies should be targeted for removal. Each Transmission Owner is free to use any
effective approach it deems appropriate in order to accomplish its Transmission Vegetation Management Program objectives. The proposed version
of the standard has Requirement R4, which prohibits vegetation encroachment inside Minimum Vegetation Clearance Distances that are developed
with Gallet equations for flashover.
Arizona Public Service Company
Disagree
APS disagrees with removal of clearance one. Clearance one should be achieved at time of maintenance which
is part of the vegetation program. This gives leverage with dealing with state and federal agencies, tribal and
private landowners. This isn't a fill in the blank requirement, however it should be based on sound science in
regards to vegetation management. A professional arborist/forester can determine the appropriate amount of
vegetation that needs to be obtained at the time of maintenance. APS suggest the following language change
for clearance 1. The Transmission Owner shall maintain ROW on Federal, State, Tribal and Private lands in
accordance with ANSI-Standard A300 (Part 1)-2001 and (Part 7)-2006 in consultation with companion
publication Best Management Practices: Integrated Vegetation Management, 2007. If all utilities followed this
standard this would increase the reliability of the bulk electric system and reduce the risk of vegetation outages.
Response: Thank you for your comment. The SDT agrees that any requirement must be based on sound science and believes the Transmission Owner
will continue to able to set any working distances it deems appropriate in order to accomplish its Transmission Vegetation Management Program
objectives when complying with Requirement R1, Part 1.6. The stipulation that the Standard applies to Federal, State, Tribal and Private Lands is
contained in the Applicability section. The SDT points out that ANSI A300 remains a “best practice” referenced in this standard and as such may be
useful in dealing with state and federal agencies, tribal and private landowners, etc.
BCTC
Disagree
BCTC do not agree with the removal of Clearance 1. We recommend adding it back to the document, but
reworded and moved to include it as a measurement (M), rather than a requirement (R) under the new standard.
Many utilities feel that Clearance 1 provides justification and leverage for operational clearances when dealing
with organizations such as municipalities. Without Clearance 1, utilities could be mandated in specific situations
to clear so that the vegetation is just beyond the Critical Clearance Zone at all times. This could result in
pruning at six month intervals, which is not feasible or cost-effective.
Response: Thank you for your comment. The SDT notes that information contained in a Measure would not be mandatory nor enforceable and
therefore has minimal usefulness as leverage. The SDT points out that ANSI A300 remains a ”best practice” referenced in the proposed standard and
may be useful in dealing with the public and private parties. The addition of Requirement R1, Part 1.6 allows for vegetation-to-ground working
distances to be used while at the same time accounting for the sag and sway of the conductor throughout its operating range under rated conditions.
The SDT believes this is superior to Clearance 1 as this gives Transmission Owners more flexibility in how they can achieve the reliability objective of
Requirement R1.
September 8, 2009
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Organization
Salt River Project
Agree?
Disagree
Question 9 Comment
Recommend adding it back to the document, however, only if it is changed to become a measurement (M)
rather than a requirement (R). Leaving it in as a measurement provides justification and leverage for operational
clearances when dealing with landowners. Without Clearance 1 landowners may only allow vegetation
clearance just at the Critical Clearance Zone at all times, which is not a feasible, cost-effective, or responsible
way for utilities to manage vegetation clearance.
Response: Thank you for your comment. The SDT notes that information contained in a Measure would not be mandatory nor enforceable and
therefore has minimal usefulness as leverage. The SDT points out that ANSI A300 remains a “best practice” referenced in the proposed standard and
may be useful in dealing with the public and private parties. The addition of Requirement R1, Part 1.6 allows for vegetation-to-ground working
distances to be used while at the same time accounting for the sag and sway of the conductor throughout its operating range under rated conditions.
The SDT believes this is superior to Clearance 1 as this gives Transmission Owners more flexibility in how they can achieve the reliability objective of
Requirement R1.
American Electric Power (AEP)
Agree
AEP agrees with the removal of Clearance 1 from the Standard.
Response: Thank you for your comment.
NPCC
Agree
We agree but believe that the Transmission Vegetation Management Program should target removal of all
incompatible vegetation on the Active Right of Way as described in the response to question 3.
Response: Thank you for your comment. The SDT agrees with the commenter that any vegetation located within the Active Transmission Line ROW
should be targeted for removal using means and strategies described in its Transmission Vegetation Management Program.
Western Area Power
Administration, Upper Great
Plains Region
Agree
While Western (UGPR) agrees with the removal of Clearance 1, we believe it is advantageous for Transmission
Owners to have a "trigger distance" in order to have some additional time to plan and schedule vegetation work.
The trigger distance is advantageous only if the Regulators do NOT interpret it to be an extended Critical
Clearance Zone and do NOT enforce based on "trigger distance" instead of the Critical Clearance Zone .
Response: Thank you for your comment. The SDT team believes the addition of Requirement R1, Part 1.6 continues to allow each Transmission Owner
to set any working distances it deems appropriate in order to accomplish the objectives with this Standard. This Requirement 1 Part 1.6 is superior to
Clearance 1 as it gives Transmission Owners more flexibility in how they can achieve the reliability objective of Requirement R1.
MRO NERC Standards Review
Subcommittee
September 8, 2009
Agree
The MRO agrees and fully supports the removal of Clearance 1. The MRO believes that the Gallet equation is a
more effective way of determining the required clearances.
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Organization
Agree?
Question 9 Comment
Response: Thank you for your comment.
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 9
Response: Thank you for your comment.
Orange and Rockland Utilities
Inc.
Agree
We generally agree, however please see comments included in question 18.
Response: Thank you for your comment.
Baltimore Gas & Electric
Company
Agree
While I may agree with the removal of this requirement strictly for reasons of simplification and selfdetermination, the current requirement forced utilities to structure their Transmission Vegetation Management
Program to develop safeguards to keep trees from encroaching into the Clearance 2 envelope. The proposed
change will leave the clearance issue beyond the Critical Clearance Zone unaddressed. Responsible utilities
will take the appropriate measures and other utilities will not.
Response: Thank you for your comment. Each Transmission Owner is free to use any effective approach it deems appropriate in order to accomplish
its Transmission Vegetation Management Program objectives. The SDT believes there are significant disincentives against the behavior you warn
about in the revised version.
CenterPoint Energy
Agree
Designation of Clearance 1 is not required to meet the purpose of the Standard.
Response: Thank you for your comment.
Hydro-Quebec Transenergie
(HQT)
Agree
We agree but believe that the Transmission Vegetation Management Program should target removal of all
incompatible vegetation on the Active Right of Way as described in the response to question 3.
Response: Thank you for your comment. The SDT agrees with the commenter that any vegetation that are located within the Active Transmission Line
ROW should be targeted for removal using means and strategies described in its Transmission Vegetation Management Program.
Great River Energy
Agree
GRE agrees and fully supports the removal of Clearance 1. GRE believes that the Gallet equation is a more
effective way of determining the required clearances.
Response: Thank you for your comment.
September 8, 2009
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Organization
Agree?
Southern California Edison
Company
Agree
Associated Electric Cooperative
Inc.
Agree
WECC Reliability Coordination
Agree
SERC Vegetation Management
Subcommittee (VMS)
Agree
Progress Energy Florida
Agree
Kansas City Power & Light
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Progress Energy Carolinas
Agree
SERC OC Standards Review
Group
Agree
Santee Cooper
Agree
Southern Company
Agree
E.ON U.S.
Agree
FirstEnergy
Agree
Midwest ISO Stakeholders
Standards Collaborators
Agree
September 8, 2009
Question 9 Comment
Q9: No comments.
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
City of Tallahassee
Agree
Northern California Power
Agency (NCPA)
Agree
Tampa Electric Company
Agree
Question 9 Comment
American Transmission Company Agree
Ameren
Agree
Nebraska Public Power District
Agree
Long Island power Authority
Agree
Manitoba Hydro
Agree
Consumers Energy Company
Agree
Pacific Gas & Electric Co.
Agree
Edison Electric Institute
Agree
Consolidated Edison Company of
New York (CECONY)
Agree
WECC
Agree
Entergy Services
Agree
September 8, 2009
119
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Pepco Holdings, Inc
Agree
JEA
Agree
Northeast Utilities
Agree
Independent Electricity System
Operator
Agree
Duke Energy Corporation
Agree
Buckeye Power, Inc.
Agree
September 8, 2009
Question 9 Comment
120
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
10. Personnel Qualifications in R1.3 in Version 1 was a “fill-in-the-blank” requirement and was removed from Version 2 of
the standard. Do you agree? If not please explain.
Summary Consideration: Most commenters agree with the deletion of R1.3 from the approved standard. The” fill in the
blank” requirement that was included in version 1 allowed the Transmission Owner to set its own standard for personnel
qualifications rather than require the same set of qualifications for personnel in all entities. The SDT recommended removing
the requirement as it is not enforceable and recommended against replacing the “fill-in-the-blank” element with a continentwide set of personnel qualifications. The SDT believes that any set of personnel qualifications enforced on a continent-wide
basis would result in a set of “lowest common denominator” qualifications that would be too stringent for some entities, and too
lax for others – with no apparent reliability benefit. Instead, the SDT recommended letting entities set their own internal
personnel qualifications to best meet their own needs.
Organization
Central Maine Power Company
Agree?
Disagree
Question 10 Comment
Central Maine Power Company disagrees with the removal of the qualification statement. The individual
responsible for this critical program must be qualified through experience, training, and education. The
International Society of Arboriculture has a certification program that can help with guidelines for qualified
arborists.
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
Northern Indiana Public Service
Company
Disagree
If the standard continues to allow T.O.’s to design and implement their own TVMPs and expect them to use
BMPs, ANSI A300, develop methods and practices, adapt schedules and plans to changing conditions, etc.,
then it is reasonable to expect that T.O. personnel responsible for the TVMP to be experts in the field of utility
vegetation management with appropriate training, certifications, licenses and credentials. I do not agree with
eliminating this requirement. Quite the opposite, I believe that the requirement needs to be more specific as to
minimum qualifications key personnel must meet. There are more requirements & qualifications to drive a
semi-truck than to design and implement a program (UVM) critical to the operation of the nation’s electric grid.
Does that make sense?
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
USDA Forest Service,
Southwestern Region, Regional
September 8, 2009
Disagree
Perhaps standard M8 could be expanded or clarified to require the Transmission Owner to describe how
employees, especially field supervisors, are trained to implement the plan and to prove that the training was
121
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Organization
Agree?
Office for AZ and NM
Question 10 Comment
actually provided. Some problems have arisen in the USFS Southwestern Region because some Transmission
Owners are not providing adequate supervision of field work.
Response: The SDT thanks you for your comment. The requirement that was dropped between the version 1 and version 2 spoke to the qualifications
of development and implementation of the TVMP and not the adequacy of the field supervision. This does not relieve the TO from providing adequate
field supervision.
National Grid
Disagree
National Grid takes exception to the term “fill-in-the-blank”. National Grid would like Personnel Qualifications
to remain in Standard FAC-003-2.
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
San Diego Gas & Electric
Disagree
We feel there must be appropriate knowledge to do the work, and that Transmission Owners must at least
have internal standards related to personnel qualifications.
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
Arizona Public Service
Company
Disagree
APS disagrees with the removal of personnel qualifications. The person responsible for vegetation
management program should have experience and training in vegetation management and system operations.
The International Society of Arboriculture has an ISA Certified Arborist and Utility Specialist certification. This
requires the credential holder to have minimal qualifications before sitting for the certification and on going
training to maintain the credential. The industry has already responded by providing the information as part of
the current standard FAC-003-1. It makes no sense to remove personnel qualifications from the revision.
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
British Columbia Transmission
Corp.
Disagree
BCTC does not agree with the elimination of this requirement. We feel strongly there must be appropriate
knowledge to do the work, and that Transmission Owners must have internal standards related to personnel
qualifications. We understand that several utilities would like this requirement removed because it created
problems in the auditing process. It is unfortunate that this important requirement for an effective vegetation
management program has been removed due misapplication of the intent during audits.
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
September 8, 2009
122
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Organization
Agree?
Question 10 Comment
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
Central Maine Power Company
Disagree
Central Maine Power Company disagrees with the removal of the qualification statement. The individual
responsible for this critical program must be qualified through experience, training, and education. The
International Society of Arboriculture has a certification program that can help with guidelines for qualified
arborists.
Response: The SDT thanks you for your response. While we agree that the International Society of Arboriculture certifications are credible
qualifications for a large work force, these same programs may be too stringent and unnecessary for utilities only needing a very small work force.
It is unknown if certification by ISA or similar organizations has impacted reliability for any Transmission Owner.
Northern Indiana Public Service
Company
Disagree
If the standard continues to allow T.O.’s to design and implement their own Transmission Vegetation
Management Programs and expect them to use BMPs, ANSI A300, develop methods and practices, adapt
schedules and plans to changing conditions, etc., then it is reasonable to expect that T.O. personnel
responsible for the Transmission Vegetation Management Program to be experts in the field of utility
vegetation management with appropriate training, certifications, licenses and credentials. I do not agree with
eliminating this requirement. Quite the opposite, I believe that the requirement needs to be more specific as to
minimum qualifications key personnel must meet. There are more requirements & qualifications to drive a
semi-truck than to design and implement a program (UVM) critical to the operation of the nation’s electric grid.
Does that make sense?
Response: The SDT thanks you for your response. The SDT concurs that some Transmission Vegetation Management Programs are highly complex
and would require highly trained arborists and vegetation management personnel to develop such programs. However, there are many programs that
are substantially less complex and do not require that level of expertise. We feel that utilities with complex programs would by nature acquire
appropriately trained personnel to implement their programs.
USDA Forest Service,
Southwestern Region, Regional
Office for AZ and NM
Disagree
Perhaps standard M8 could be expanded or clarified to require the Transmission Owner to describe how
employees, especially field supervisors, are trained to implement the plan and to prove that the training was
actually provided. Some problems have arisen in the USFS Southwestern Region because some Transmission
Owners are not providing adequate supervision of field work.
Response: The SDT thanks you for your comment. The requirement that was dropped between the version 1 and version 2 spoke to the qualifications
of development and implementation of the Transmission Vegetation Management Program and not the adequacy of the field supervision.
National Grid
September 8, 2009
Disagree
National Grid takes exception to the term “fill-in-the-blank”. National Grid would like Personnel Qualifications
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Organization
Agree?
Question 10 Comment
to remain in Standard FAC-003-2.
Response: The SDT thanks you for your response. A” fill in the blank” requirement as stated in version 1 allowed the Transmission Owner to set its
own standard and does not substantively add to the effectiveness of the Standard.
British Columbia Transmission
Corp.
Disagree
BCTC does not agree with the elimination of this requirement. We feel strongly there must be appropriate
knowledge to do the work, and that Transmission Owners must have internal standards related to personnel
qualifications. We understand that several utilities would like this requirement removed because it created
problems in the auditing process. It is unfortunate that this important requirement for an effective vegetation
management program has been removed due misapplication of the intent during audits.
Response: The SDT thanks you for your response. A” fill in the blank” requirement as stated in version 1 allowed the Transmission Owner to set its
own standard and does not substantively add to the effectiveness of the Standard.
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 10
Response: The SDT thanks you for your response.
Exelon
Agree
Agree but same comment as above, we do not understand the reference to “fill in the blank” requirement for
R1.3. As commonly understood, a “fill in the blank” standard /requirement is one that was assigned to the
RRO.
Response: The SDT thanks you for your response. A” fill in the blank” requirement as stated in version 1 allowed the TO to set its own standard as
opposed to RRO. In either case the concept of a “fill in the blank requirement” does not substantively add to the effectiveness of the Standard.
Tampa Electric Company
Agree
While we agree with the removal of “fill-in the blank” requirements, we recommend the inclusion of professional
qualifications for staff involved in this Standard. Reading the 42 page technical reference and the attached
comment form, all involved need to really understand the Standard as well as industry practices.
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
Baltimore Gas & Electric
Company
September 8, 2009
Agree
Similar to the response to no. 9, the end result is what counts and each utility will be responsible and
accountable for their actions. Qualifications unlike clearance requirements, are far-removed from results and
can easily be left unaddressed in the new std.
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Organization
Agree?
Question 10 Comment
Response: The SDT thanks you for your response.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Agree
We are in agreement with the elimination of this requirement, but not without some qualifications. We feel
strongly there must be appropriate knowledge to do the work, and that Transmission Owners must at least
have internal standards related to personnel qualifications. It is unfortunate that this important requirement for
an effective vegetation management program has been removed due to concerns with the auditing program.
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
CenterPoint Energy
Agree
Designation of Personnel Qualifications are not required to meet the purpose of the Standard.
Response: The SDT thanks you for your response.
American Electric Power (AEP)
Agree
AEP agrees that the Standard should not stipulate or require personnel qualifications.
Response: The SDT thanks you for your response.
Platte River Power Authority
Agree
The requirement should be removed because it is a “fill-in-the-blank” requirement. Defining the proper amount
of personnel qualifications and training would be too prescriptive for utilities with small vegetation management
programs and not prescriptive enough for utilities with large vegetation management programs.
Response: The SDT thanks you for your comments.
Western Utility Arborists
Agree
The Western Utilities are in agreement with the elimination of this requirement. However, we feel strongly there
must be appropriate knowledge to do the work, and that Transmission Owners must at least have internal
standards related to personnel qualifications.
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
Southern California Edison
Company
Agree
SERC OC Standards Review
Agree
September 8, 2009
Q10: No comments.
125
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 10 Comment
Group
Florida Power & Light
Agree
Santee Cooper
Agree
Progress Energy Carolinas
Agree
SERC Vegetation Management
Subcommittee (VMS)
Agree
Progress Energy Florida
Agree
Kansas City Power & Light
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
City of Tallahassee
Agree
Northern California Power
Agency (NCPA)
Agree
Long Island power Authority
Agree
Manitoba Hydro
Agree
Consumers Energy Company
Agree
Pacific Gas & Electric Co.
Agree
Duke Energy Corporation
Agree
Associated Electric Cooperative Agree
September 8, 2009
126
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 10 Comment
Inc.
NPCC
Agree
WECC Reliability Coordination
Agree
Western Area Power
Administration, Upper Great
Plains Region
Agree
Orange and Rockland Utilities
Inc.
Agree
American Transmission
Company
Agree
Ameren
Agree
Nebraska Public Power District
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
Consolidated Edison Company
of New York (CECONY)
Agree
WECC
Agree
Entergy Services
Agree
Pepco Holdings, Inc
Agree
JEA
Agree
September 8, 2009
127
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Independent Electricity System
Operator
Agree
Salt River Project
Agree
Northeast Utilities
Agree
Hydro-Quebec Transenergie
(HQT)
Agree
Buckeye Power, Inc.
Agree
Great River Energy
Agree
Southern Company
Agree
E.ON U.S.
Agree
Bonneville Power
Administration
Agree
FirstEnergy
Agree
MRO NERC Standards Review
Subcommittee
Agree
Midwest ISO Stakeholders
Standards Collaborators
Agree
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
September 8, 2009
Question 10 Comment
128
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
11. The IEEE 516 standard distances were replaced with the Gallet equation distances. Clearance 2 was replaced by the
Critical Clearance Zone. The Critical Clearance Zone is defined as the zone of all possible positions of the conductor
at the line’s designed operating ratings including wind factors. (Please refer to pages 22-32 in the Technical
Reference Document on the Critical Clearance Zone for further background for this question.) The imminent threat
procedure, R2, requires action to be taken to prevent an outage when the Critical Clearance Zone is approached. Do
you agree with R2? If not please explain.
Summary Consideration: The majority of responders (61%) disagreed with the concept of the imminent threat procedure
being associated with the Critical Clearance Zone (CCZ). The key concerns that commenters raised were associated with the
Critical Clearance Zone and included the following:
•
It is a good concept but is theoretical and difficult to administer in the field
•
Respondents preferred a more defined distance that is real-time and measurable
•
The word "approach" caused concern due to being vague and open to interpretation
Although there was no clear minority view, a number of respondents recommended eliminating R2 or R4 because of practical
difficulties associated with the CCZ and their belief that R5, R6, and R7 were sufficient to achieve reliability
In response, the SDT modified R2 so that it does not use the CCZ to trigger the imminent threat procedure implementation. R2
now requires the Transmission Owner to implement its imminent threat procedure when it has knowledge of such a threat
obtained through normal operating procedures. The SDT decided not to be prescriptive in the definition of a vegetation
imminent threat. Rather, the Transmission Owner should have the flexibility of defining its own procedure per the TVMP. In
addition R4 has been modified and now requires the Transmission Owner to prevent vegetation encroachment of the Minimum
Vegetation Clearance Distances (MVCD) as observed in real time and eliminates the use of the CCZ for this purpose.
R2. Each Transmission Owner shall implement its imminent threat procedure when the Transmission Owner has actual knowledge of
such a threat, obtained through normal operating practices.
Organization
BCTC
Agree?
Formatted: Indent: Left: 0",
Pattern: Clear (Custom
Color(RGB(211,220,233)))
Question 11 Comment
BCTC feels that changing to the Gallet equation will not have a large impact on its vegetation management
operations, so we have no concerns.
We agree with R2, but feel that this clause makes R4 redundant, as per our discussion under Comment # 15
below. We recommend the removal of R4 entirely from the standard.
September 8, 2009
Deleted: or notification from others,
that the Critical Clearance Zone is
approached by vegetation to prevent an
encroachment of the Critical Clearance
Zone.
129
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Organization
Agree?
Question 11 Comment
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
Western Utility Arborists
The Western Utilities feel that changing to the Gallet equation will not have a large impact on its vegetation
management operations, so we have no concerns. We agree with R2, but feel that this clause makes R4
redundant, as per our discussion under Comment # 15 below. We recommend the removal of R4 entirely from
the standard.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat upon discovery of such a threat. The Critical Clearance Zone has been replaced with Minimum Vegetation
Clearance Distance (MCVD) in R4.
Associated Electric
Cooperative Inc.
Disagree
The phrase “Critical Clearance Zone is approached” in R2 is nebulous and probably unenforceable. The
determination and visualization of the Critical Clearance Zone and approaching vegetation encroachment,
under field conditions, is a practice in application of theoretical conductor locations in real time. Would the
Transmission Owner be found in noncompliance if evidence showed vegetation had “approached” within 20
feet, 2 feet, 2 inches or some other arbitrary distance of the CCZ and the TO failed to implement its imminent
threat procedure?
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
Western Area Power
Administration, Upper Great
Plains Region
September 8, 2009
Disagree
The CCZ as defined would very specifically outline a zone that needs to remain clear of vegetation to avoid a
violation, but that specificity could be an overly burdensome concept to implement and/or monitor.
Theoretically, there could be an infinite number of allowable vertical and horizontal (for outside phases)
clearances depending on your location within each span. Theoretically, you may need to clear cut at midspan (depending on retreatment intervals, growth rate, etc.) while allowing a 40 foot tree closer to the
structure, along with everything in between depending on your location within the span. To fully comply with
the CCZ as defined, each Transmission Owner would have to have a table of allowable vertical and horizontal
clearances for every few feet on every available span length within each line section. Producing such tables
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Organization
Agree?
Question 11 Comment
would be a significant burden to each Transmission Owner, but without them, the Transmission Owner could
not verify that vegetation had not encroached within the CCZ. In order to produce the tables outlined above,
the Transmission Owner would need to identify what design parameter(s) are applicable for the "correct"
CCZ? We remain concerned that weather conditions in excess of those parameters could lead to a
vegetation contact/outage and proving that weather conditions were in excess of design criteria would be
extremely difficult or impossible for all spans on a lengthy transmission line. It is not uncommon to have
weather stations 50 or more miles away from points on our transmission system. In order to certify/verify
compliance, the Transmission Owner would have to physically take their table to the field and verify vertical
and horizontal clearances from the edge of the theoretical envelope (not the actual conductor position) for all
vegetation within the span. This would be a time-consuming, burdensome, cumbersome process if
Regulators are going to require specific evidence in order for the Transmission Owner to document their
annual certification.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat upon discovery of such a threat. The Critical Clearance Zone
has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
SERC Vegetation
Management Subcommittee
(VMS)
Disagree
The SERC VMS recommends that R2 be deleted. Since this is a "zero tolerance" standard any Transmission
Owner will remove any discovered threats to prevent outages. While we agree that the implementation of an
imminent threat procedure may be a valid concept, visualization of the Critical Clearance Zone (CCZ) and
determining an approaching encroachment is a practice in application of theoretical conductor locations in real
time.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
Progress Energy Florida
Disagree
The Critical Clearance Zone as currently defined is too academic. Implementation of R2 would require field
operations staff to determine the theoretical position of the line during inspections to decide whether to
engage the imminent threat procedures. The academic/theoretical aspects of the Critical Clearance Zone
definition are not practical or enforceable. The criteria for a violation needs to be limited to the position of the
conductor in real time.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat upon discovery of such a
threat. The Critical Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
September 8, 2009
131
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Organization
Western Area Power
Administration, Rocky
Mountain Region
Agree?
Disagree
Question 11 Comment
As discussed in the Technical Reference document, the CCZ is a complicated theoretical envelope
surrounding all rated operating positions of the conductor. Its dynamic shape is constantly changing and is
contingent upon location within the span. Calculation of the size and shape of CCZ is based, in part, upon the
design parameters of the transmission facility. However, as-built or long term maintenance conditions can
often diverge from the original design requirements over time. Ground elevations can also change as a result
of man made or natural causes from the original design elevations recorded on plan and profile engineering
drawings. Consequently, precise field measurement of the as-built CCZ is extremely problematic and
strategies that utilize the calculation of allowable right-of-way tree heights can be hindered by unrecorded
deviations from the original design criteria. Allowable tree height strategies also become increasingly more
difficult and impractical with increasing extremes in terrain. While the CCZ is a very important concept for an
effective vegetation management program it is far to theoretical, dynamic, and impractical to field measure for
use as a clear and precise boundary for regulatory purposes. In addition, the R2 requirement for action when
the imprecise and theoretical CCZ boundary is "approached" by vegetation is an even more subjective and
unmeasurable. The "rate of approach" is really the key issue of concern. The rate of vegetation approach is
a function of many variables including species type and site specific growing conditions. For example, a
Century Plant which can grow six inches a day is obviously a much greater concern than a Lodgepole Pine on
a dry mountain top which grows only a few inches a year. As such, there is no practical way to define or
measure for regulatory purposes those "approach" situations that legitimately require immediate action from
those "approach" situations that do not. The wording and concepts of R2 are therefore to imprecise to be
used as clear requirements for Standards compliance.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat upon discovery of such a threat. The Critical Clearance Zone
has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
Progress Energy Carolinas
Disagree
The Critical Clearance Zone as currently defined is too academic. Implementation of R2 would require field
operations staff to determine the theoretical position of the line during inspections to decide whether to
engage the imminent threat procedures. The academic/theoretical aspects of the Critical Clearance Zone
definition are not practical or enforceable. The criteria for a violation needs to be limited to the position of the
conductor in real time.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat upon discovery of such a threat. The Critical Clearance Zone
has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
SERC OC Standards Review
September 8, 2009
Disagree
The SERC OCSRG recommends that R2 be deleted. Since this is a "zero tolerance" standard any
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Organization
Agree?
Group
Question 11 Comment
Transmission Owner will remove any discovered threats to prevent outages. While we agree that the
implementation of an imminent threat procedure may be a valid concept, visualization of the Critical Clearance
Zone and determining an approaching encroachment is a practice in application of theoretical conductor
locations in real time.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
Florida Power & Light
Disagree
FPL agrees that the Gallet equation is a better method to determine a Critical Clearance Zone. However, FPL
does not agree with the application of the zone for several reasons outlined below. ? There are many
environmental and engineering variables and assumptions included in the calculation of the Critical Clearance
Zone. ? These assumptions are not clearly defined in the standard. ? Unless there is a significant
intrusion into the Critical Clearance Zone, an engineer and surveyor would be necessary at all times to
determine a violation. ? The success of this standard lies with a standard the field personnel can
implement. When making actual trimming or removal decisions, the field personnel are not adequately skilled
to do much more than make a rough guess at the Critical Clearance Zone. This standard must establish
measurable and auditable parameters for field operations. ? In Requirement R2, determination of when to
activate the Imminent Threat Procedure becomes unclear due to the difficulty in determining when the Critical
Clearance Zone is encroached.
? As written, off ROW trees falling through the Critical Clearance Zone
become a violation of Requirement R4. Unless an outage occurred, how would the utility determine that a
violation occurred? In FAC 003-1 an outage of this nature is defined as Category 3 and is not a violation.
Since fall-in tree interruptions have never been contributors to cascading events or blackouts they should not
be a violation of a NERC standard. Consequently, as written, it is highly questionable whether this Standard is
sufficiently specific and clear to be enforceable. The many questions and levels of confusion introduced with
the application of the Critical Clearance Zone concept suggests that neither the industry nor NERC will ever
know if compliance is met. Such a high level of ambiguity requires that the Critical Clearance Zone concept
be revisited and most likely replaced with a measure that is workable for both the industry and NERC. To
further this effort, FPL has outlined some alternative suggestions described in the answer to question 18.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
September 8, 2009
133
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Organization
Southern Company
Agree?
Disagree
Question 11 Comment
As written, R2 requires activation of the imminent threat process when the Critical Clearance Zone (CCZ) is
"approached" by vegetation. The term "approach" is vague and open to interpretation. Since vegetation is
dynamic in nature, it is constantly "approaching" any pre-defined zone. There could also be many examples
given of encroachments into the theoretical CCZ that would neither threaten the transmission line conductor
nor cause a reduction in the capacity of the transmission line. This concept would be better suited to be a
“trigger point” that, if found, would be incentive for the Transmission Owner to take immediate action or ensure
future action occurs on schedule. This action may be as urgent as implementation of the immediate threat
procedure or as non-urgent as making sure that the upcoming maintenance on that line is scheduled
appropriately. We are concerned this revision of FAC-003 continues to take a zero tolerance approach to
compliance, which is contrary to the philosophy utilized in other NERC standards. A state of non-compliance
should not exist simply because vegetation encroached within a pre-defined zone by a fractional inch, but only
when an event, such as a sustained outage, occurs due to the Transmission Owner's failure to maintain
adequate clearance between conductors and vegetation.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
E.ON U.S.
Disagree
E.ON U.S. suggests that R2 be deleted. Since this is a "zero tolerance" standard any Transmission Owner will
remove any discovered threats to prevent outages. While we agree that the implementation of an imminent
threat procedure may be a valid concept, visualization of the Critical Clearance Zone and determining an
approaching encroachment is a practice in application of theoretical conductor locations in real time.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
FirstEnergy
September 8, 2009
Disagree
The CCZ is not equal to Clearance 2 in FAC-003-1. Per requirement R4, any encroachment into the CCZ is a
violation of the standard even if an outage does not occur. This is too strict because it refers to a "0"
tolerance even for encroachments that do not affect reliability. This can be an extremely costly standard to
comply with that may or may not improve reliability. The CCZ distance is a difficult to determine from one
moment to the next based upon the description and calculations outlined. The conditions on the right of way
are dynamic and ever changing. It would be more proactive for the TO to focus on implementing the TVMP
rather than expending time and money trying to determine if the CCZ has been violated. A better approach
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Agree?
Question 11 Comment
would be to establish a minimum clearance at all times rather than to monitor encroachment to a theoretical
CCZ.
Response: Thank you for your comment. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response,
the SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the
Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced
with Minimum Vegetation Clearance Distance (MCVD) in R4.
Midwest ISO Stakeholders
Standards Collaborators
Disagree
he CCZ is a good theoretical concept to aid industry in understanding the overall movement of conductors, but
it is an impractical concept for field application. Due to the variability in the size of the CCZ as you move along
a conductor, as well as changes from span to span or even line to line due to design parameters, loading or
weather-related issues, the CCZ concept should not be tied to an imminent threat procedure. Vegetation
approaching the CCZ does not constitute an imminent threat. It may be months to years before this
vegetation ever gets to a proximity distance from the conductor to be within a "spark-over" distance as defined
by the Gallet equations. Requirement R2 should support the purpose of this standard by requiring
implementation of the Vegetation Imminent Threat Procedure when the Transmission Owner has visual, field
knowledge that vegetation is encroaching upon a conductor within some specific distance that is a multiple of
the Gallet distances referenced in Table I of FAC-003-2 (to be conservative we suggest two to three times the
Gallet distances). Failure to implement the Vegetation Imminent Threat Procedure in such instances would
be a violation of R2.As R2 is currently stated, a Transmission Owner cannot comply with R2 unless the
imminent threat procedure is continuously being implemented, because vegetation that is growing is always
approaching the CCZ. "Approaching the CCZ" cannot be the trigger for implementation of the Vegetation
Imminent threat Procedure. Instead, the trigger should be an encroachment within some observed field
distance. Requirement R2 could be reworded as follows: ?Each Transmission Owner shall implement its
Vegetation Imminent Threat Procedure when the Transmission Owner has knowledge, obtained through
normal operating practices or notification from others, that vegetation is encroaching upon a conductor within
a distance that is twice the Gallet clearance distances referenced in Table I." Using a multiple of the Gallet
distances provides a safety factor. Assessing a violation for failure to appropriately implement the Vegetation
Imminent Threat Procedure or for a sustained vegetation-related outage incents the proper behavior.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4. The proposed standard revision specifies the MVCD as a starting point and TOs may apply multiples at
its own discretion in order to achieve its TVMP objectives and adhere to applicable safety standards.
September 8, 2009
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SERC Compliance Staff
Agree?
Disagree
Question 11 Comment
SERC staff agrees that the implementation of an imminent threat procedure may be a valid concept; however
visualization of the Critical Clearance Zone and determining an approaching encroachment will be difficult
from a practical matter. There also needs to be definition of what is meant by "approaching" if this is used.
While it may be a technically sound approach to designate the clearance zone to be tied to the conductor
movement envelope as found in the NESC, this results in a banana-shaped zone that is difficult to
substantiate in the field by entity and compliance personnel. It may be better, and more reasonable to define
a constant zone around a conductor that would be the same throughout the span. The clearance zone should
not include the limitation that the zone cannot extend outside the active right of way.
Response: Thank you for your comment. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response,
the SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the
Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced
with Minimum Vegetation Clearance Distance (MCVD) in R4.
ITC HOLDINGS
Disagree
Just because vegetation is approaching the CCZ doesn't represent an imminent threat and should not be set
to an imminent threat procedure. Implementation of R2 would require field personnel to determine the
speculative position of the line during inspections to decide whether to engage the imminent threat
procedures. While we agree that an imminent threat procedure should be implemented to address vegetation
related imminent threats as soon as they are identified, we believe that an approach of the CCZ should not be
used to generate implementation. The term "approached" does not identify a specific distance, so it’s not clear
to what extend vegetation would have to approach the CCZ to require implementation of the imminent threat
process. ITC agrees that the implementation of an imminent threat procedure may be a valid concept, but
visualization of the CCZ and determining approaching vegetation is a practice in hypothetical conductor
locations in real time. This may be a good imaginary concept in understanding conductor movement but it's
impractical for field applications.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
Tennessee Valley Authority
Disagree
TVA recommends that R2 be removed from this standard. Since this is a "zero tolerance" standard there is a
very significant incentive for the Transmission Owner to inspect and plan maintenance to prevent potential
outages. The Gallet Equations should be kept within the white paper solely for the TO to reference for
developing maintenance and inspection cycles.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
September 8, 2009
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Agree?
Question 11 Comment
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
Exelon
Disagree
Comments: 1) In spite of the rigor associated with the Gallet equations, the definition of CCZ is imprecise as
the Ratings to be used are not specified. In addition, Exelon is concerned that it will be difficult to determine
the CCZ for each span under all possible operating conditions. Implementing an imminent threat procedure
(R2) in combination with the CCZ may be unworkable under actual field conditions. 2) We are concerned that
CCZ is only fully defined in the Technical Reference documentation and not in the standard itself. As stated in
the NERC Standards Process Manual, Elements of a Reliability Standard, "Supporting documents to aid in the
implementation of a standard may be referenced by the standard but are not part of the standard itself." There
needs to be enough specificity as to the definition of CCZ in FAC-003-2 so that adequate documentation and
evidence of compliance can be developed.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
American Electric Power (AEP) Disagree
AEP agrees with the need for a TO to have an Imminent Threat Procedure and that the Transmission
Operator should be immediately notified of imminent threats. However, AEP disagrees with the requirement
that the Transmission Operator be notified merely because the CCZ has been approached. Vegetation
approaching the CCZ does not necessarily constitute an imminent threat. It is possible that the CCZ is
encroached by vegetation at the lowest point of the CCZ whereas the conductor may be at its highest point in
the CCZ (potentially 20 or 30 feet away from the vegetation). This situation does not merit notification to the
Transmission Operator. Please also refer to our comments regarding CCZ in AEP's responses to Questions
15 and 18.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
September 8, 2009
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Platte River Power Authority
Agree?
Disagree
Question 11 Comment
Changing to the Gallet equation will not have a large impact on vegetation management operations, keeping
Clearance 1 and 2 with tables developed using IEEE Standards for various voltages, line spans and altitudes
is preferable. Actions should be taken to prevent an outage when vegetation encroaches Clearance 2.
Response: Thank you for your comment. The SDT chose to use Gallet equations over IEEE primarily because Gallet is more appropriate for
determining the probability of flashover. The IEEE standard was developed for human safety purposes.
Northern Indiana Public
Service Company
Disagree
While I agree with the argument that the Gallet equatiion is a better technical or scientific method than IEEE
516 for determining realistic conductor to tree flashover distances, I do not agree that the new proposed
clearance tables serve any useful purpose as a vegetation clearance standard from an operational
perspective. The FAC-003-2 Technical Reference itself points to this fact when it states, "even if the exact
size and shape of the C.C.Z. is known, it becomes nearly impossible in the field to correlate and accurately
superimpose the C.C.Z. around the conductor." The Tech. Ref. goes on to say that "it is anticipated that
many T.O.s will establish a work trigger well outside the C.C.Z." I agree wholeheartedly with that concept and
believe that the Gallet clearance tables should be used by TO's to develop the more important "work trigger"
or "action threshold" clearances. This revision is overly focused on C.C.A.'s that have no practical operational
application while being silent to the more critical to reliability issue of "work trigger/action threshold"
clearances. This needs to be addressed if we hope to be successful at achieving the goal of zero preventable
tree related outages.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
Tampa Electric Company
Disagree
This is a good start. The Critical Clearance Zone (CCZ) is a very real and practical concept; however, it is not
transferable to field conditions. This could result in a "fill in the blank" standard relative to what the Critical
Clearance Zone will be in terms of distance. As I read this, it will be a sliding scale from insulator to mid span
and back for each designated line voltage. The max wind speed to be used and other assumptions behind the
determination of this zone may be as involved a Gallet's formula. This will lead to complications during
operational inspection and verification of these clearances.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
September 8, 2009
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Organization
Agree?
Question 11 Comment
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
Orange and Rockland Utilities
Inc.
Disagree
While we agree that the imminent threat procedure should be implemented to address vegetation-related
imminent threats as soon as they are identified, we believe that an "approach" of the CCZ should not be used
to trigger implementation. The term "approached" does not identify a specific distance, so it is not clear to
what extent vegetation would have to approach the CCZ in order to require implementation of the imminent
threat process. This is left to the discretion of individual interpretation, is confusing to field personnel, and
presents compliance and auditing problems. Imminent threats which are based on vegetation clearances
should be identified based on specific clearances, not undefined approach distances. In practical field
application the CCZ is an invisible area that changes shape and size along the length of the conductor. It is
impossible to readily identify in the field without engineering calculations and precise measurements or the
use of technology such as Aerial Laser Survey (ALS) using Light, Detection and Ranging (LIDAR) technology.
Therefore under normal circumstances the location, size, and shape of the CCZ and vegetation
encroachments of the CCZ can only be roughly estimated. Even with the use of ALS, which is relatively
accurate, information is often not available for months after the survey flight. We believe that under normal
circumstances imminent threats which are based on vegetation clearances should be identified in terms of
specific distances from the conductor. While it is not possible for an inspector to readily identify a vegetation
encroachment of the CCZ in the field, an inspector could more easily estimate a specified short distance
between a conductor and vegetation in real time and initiate implementation of the imminent threat procedure
based on that assessment. This assessment would be significantly more accurate than attempting to measure
the distance between vegetation and the CCZ, which is not visible and constantly changes size and shape
throughout the span. In cases where the Transmission Owner chooses to deploy ALS, the CCZ rather than
the conductor could be used as the reference because in most cases the CCZ could be identified relative to
approaching vegetation with a reliable degree of accuracy. Still a specific distance should be used to trigger
implementation of the imminent threat procedure because of the issues previously raised with the use of the
word "approached".
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
American Transmission
Company
September 8, 2009
Disagree
ATC believes that the Critical Clearance Zone (CCZ) is a good theoretical concept to aid industry in
understanding the overall movement of conductors, but it is an impractical concept for field application. Due to
the variability in the size of the CCZ as you move along a conductor, as well as changes from span to span or
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Agree?
Question 11 Comment
even line to line due to design parameters, loading or weather-related issues, the CCZ concept should not be
tied to an imminent threat procedure. Vegetation approaching the CCZ does not constitute an imminent
threat. It may be months to years before this vegetation ever gets to a proximity distance from the conductor
to be within a "spark-over" distance as defined by the Gallet equations. Requirement R2 should support the
purpose of this standard by requiring implementation of the Vegetation Imminent Threat Procedure when the
Transmission Owner has visual, field knowledge that vegetation is encroaching upon a conductor within some
specific distance that is a multiple of the Gallet distances referenced in Table I of FAC-003-2 (to be
conservative we suggest two to three times the Gallet distances). Failure to implement the Vegetation
Imminent Threat Procedure in such instances would be a violation of R2.As R2 is currently written, a
Transmission Owner cannot comply with R2 unless the imminent threat procedure is continuously being
implemented or monitored, because vegetation that is growing is always approaching the CCZ. "Approaching
the CCZ" cannot be the trigger for implementation of the Vegetation Imminent threat Procedure. Instead, the
trigger should be an encroachment within some observed field distance. Requirement R2 could be rewritten
as follows: ?Each Transmission Owner shall implement its Vegetation Imminent Threat Procedure when the
Transmission Owner has knowledge, obtained through normal operating practices or notification from others,
that vegetation is encroaching upon a conductor within a distance that is twice the Gallet clearance distances
referenced in Table I." Using a multiple of the Gallet distances provides a safety factor. Assessing a violation
for failure to appropriately implement the Vegetation Imminent Threat Procedure or for a sustained vegetationrelated outage would promote the proper behavior.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4. The proposed standard revision specifies the MVCD as a starting point and TOs may apply multiples at
its own discretion in order to achieve its TVMP objectives and adhere to applicable safety standards.
Ameren
September 8, 2009
Disagree
The CCZ is a good theoretical concept to aid industry in understanding the overall movement of conductors,
but it is an impractical concept for field application. Due to the variability in the size of the CCZ as you move
along a conductor, as well as changes from span to span or even line to line due to design parameters,
loading or weather-related issues, the CCZ concept should not be tied to an imminent threat procedure.
Vegetation "approaching" the CCZ does not constitute an imminent threat. In fact, the moment after
vegetation is cut, it begins again to "approach" this zone. It may be months to years before this vegetation
ever gets to a proximity distance from the conductor to be within a "spark-over" distance as defined by the
Gallet equations. Requirement R2 should support the purpose of this standard by requiring implementation of
the Vegetation Imminent Threat Procedure when the Transmission Owner has visual, field knowledge that
vegetation is encroaching upon a conductor within some specific distance. As R2 is currently stated, a
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Organization
Agree?
Question 11 Comment
Transmission Owner cannot comply with R2 unless the imminent threat procedure is continuously being
implemented, because vegetation that is growing is always approaching the CCZ. "Approaching the CCZ"
cannot be the trigger for implementation of the Vegetation Imminent threat Procedure. Instead, the trigger
should be an encroachment within some observed field distance.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
Nebraska Public Power District Disagree
The CCZ is a good concept to explain the flight path of a conductor under all conditions but it would be
impractical to use in the field. There are too many variables to consider and an encroachment does not
constitute an immediate threat.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
Manitoba Hydro
Disagree
The imminent threat process trigger should be well defined, and the vague "approaching" terminology needs
to be changed. Imminent threat implies and that an elevated risk of contact exists. That is not the case if the
vegetation is merely approaching the CCZ. The objective of the overall Vegetation Management program is to
prevent an encroachment. The imminent threat procedure should be triggered by discovery of an
encroachment into the CCZ. Even when an actual encroachment into the CCZ occurs - while the odds of an
outage event have increased - the likelihood of a contact is still minimal, as other environmental factors still
need to be in place (i.e. high temperature and/or high wind conditions).If this approach to an imminent threat
process trigger, then the violation of this requirement implies a violation of R4, which prohibits the
encroachment of the CCZ, and therefore either R2 or R4 could be removed, or they could be combined into
one requirement.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
The Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
Consumers Energy Company
September 8, 2009
Disagree
Absolutely disagree! The Gallet formula distances do not provide adequate protection of the system. The
"Critical Clearance Zone" concept is not workable in the field. Every foot of every span would have a different
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Question 11 Comment
CCZ that cannot be measured in the field without survey type equipment and knowledge of current line
loadings. The clearance requirement needs to be uniform along the span for field crews to effectively achieve
compliance. It appears that the drafting team hopes to minimize violations of vegetation violating FAC-003-1
Clearance 2 distances by decreasing the clearance distance between the conductor and vegetation using the
Gallet formula. If NERC believes that FAC-003-1 Clearance 2 distances are too conservative, then the Gallet
formula distance needs to be increased by some multiplier (2 or3) to achieve adequate safeguard for growing
vegetation. Most trees in the United States in the size range that could exist beneath conductors achieve
height growth of 3 feet or more annually. A tree in May may have adequate clearance per the proposed CCZ
and in July violate that clearance causing an outage. Therefore, if the CCZ is to remain as is then the
transmission owner/operator must have a defined imminent threat distance considerably greater than the CCZ
and must be great enough that field personnel can safely remove the threat without de-energizing or de-rating
the line.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4. The proposed standard revision specifies the MVCD as a starting point and TOs may apply multiples at
its own discretion in order to achieve its TVMP objectives and adhere to applicable safety standards.
Pacific Gas & Electric Co.
Disagree
PG&E agrees the Gallet equation is superior to IEEE 516 and the imminent threat procedure is a critical
component of the standard but disagrees that initiation of the procedure be based on such ambiguous
language as "approaching the CCZ". Approaching could be any and all vegetation that is live and growing
and CCZ is a theoretical calculation not a real time event. As written, the standard would require the TO to
initiate an emergency action when such action may not be warranted or necessary to prevent an outage.
PG&E recommends using a clearly defined and measureable threshold to determine when the imminent
threat procedure must be initiated. A reasonable threshold would be 3 times the Gallet clearance distances
referred to in Table 1 or when vegetation is threatening to fall into or otherwise impact a line.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4. The proposed standard revision specifies the MVCD as a starting point and TOs may apply multiples at
its own discretion in order to achieve its TVMP objectives.
September 8, 2009
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San Diego Gas & Electric
Agree?
Disagree
Question 11 Comment
We do not agree with replacing Clearance Zone 2 with the Critical Clearance Zone. We recommend the
removal of R4 entirely from the standard.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
Consolidated Edison Company Disagree
of New York (CECONY)
CECONY is in favor of using the Gallet equations as they provide a more realistic clearance distance for
vegetation. We understand and agree that establishing a Critical Clearance Zone (CCZ) would provide the
specific area that a conductor could possibly travel through during various field and weather conditions but we
do not agree that this is the most practical approach. The main issue is that the wording '...the Critical
Clearance Zone is approached by vegetation.....' is very vague and left open to wide interpretation which
causes inconsistency and confusion throughout the industry. The CCZ changes throughout the length of each
conductor in each span so a field inspector's job and an auditor's job become much more complicated when
trying to confirm compliance when vegetation is present in the Actiove ROW. We feel that the time spent
trying to measure and calculate the CCZ and then confirm compliance would be better spent initiating a
response plan to safely remove the vegetation. The imminent threat procedure would only be implemented if
vegetation encroaches beyond a specific distance from the conductor, not as it approaches the theoretical
CCZ. Advanced technology would be required if a vegetation approach distance to the CCZ was to be
calculated in the field. This is a very costly and time consuming requirement and does not efficiently meet the
Standard's goal of ensuring reliability.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
Duke Energy Corporation
September 8, 2009
Disagree
No. Duke believes that the CCZ is a good theoretical concept to aid industry in understanding the overall
movement of conductors, but it is an impractical concept for field application. Due to the variability in the size
of the CCZ as you move along a conductor, as well as changes from span to span or even line to line due to
design parameters, loading or weather-related issues, the CCZ concept should not be tied to an imminent
threat procedure. Vegetation approaching the CCZ does not constitute an imminent threat. It may be years
before this vegetation ever gets to a proximity distance from the conductor to be within a "spark-over" distance
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Question 11 Comment
as defined by the Gallet equations. Requirement R2 should support the purpose of this standard by requiring
implementation of the Vegetation Imminent Threat Procedure when the Transmission Owner has visual, field
knowledge that vegetation is encroaching upon a conductor within some specific distance that is a multiple of
the Gallet distances referenced in Table I of FAC-003-2 (to be conservative we suggest two times the Gallet
distances). Failure to implement the Vegetation Imminent Threat Procedure in such instances would be a
violation of R2.As R2 is currently stated, a Transmission Owner cannot comply with R2 unless the imminent
threat procedure is continuously being implemented, because vegetation that is growing is always
approaching the CCZ. "Approaching the CCZ" cannot be the trigger for implementation of the Vegetation
Imminent threat Procedure. Instead, the trigger should be an encroachment within an observed distance from
vegetation to conductor that is twice the Gallet distances in Table I. Requirement R2 could be reworded as
follows: ?Each Transmission Owner shall implement its Vegetation Imminent Threat Procedure when the
Transmission Owner has knowledge, obtained through normal operating practices or notification from others,
that vegetation is encroaching upon a conductor within a distance that is twice the Gallet clearance distances
referenced in Table I." Using a multiple of the Gallet distances provides a safety factor. Assessing a violation
for failure to appropriately implement the Vegetation Imminent Threat Procedure or for a sustained vegetationrelated outage incents the proper behavior.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
The proposed standard revision specifies the MVCD as a starting point and TOs may apply multiples at its own discretion in order to achieve its TVMP
objectives and adhere to applicable safety standards.
Entergy Services
Disagree
: 1. Entergy suggests that the requirement for activation of the vegetation imminent threat process should not
be tied to the Critical Clearance Zone and that the each entity should define the activation of their vegetation
imminent threat process. Tying the activation of the imminent threat process to the Critical Clearance Zone is
limited in that this criterion does not address the possibilities of vegetation falling into the line or Critical
Clearance Zone.
2. In the sentence “Critical Clearance Zone approached by vegetation” the use of “approached” is subjective
and not specifically quantifiable. Effective, uniform activation of the imminent threat process will require
objective measurement criteria.
3. The standard needs to include a clear statement to the effect that when the Transmission Operator is
notified of a potential vegetation problem, obtained by normal operations and inspections, the entity will
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Question 11 Comment
activate the Vegetation Imminent Threat Process.
4) This requirement, as stated, is redundant. The requirements for maintaining the Critical Clearance Zones
and / or avoiding vegetation outages, and the associated Violation Risk Factors and Violation Severity Levels,
already reinforce the desired behavior of the entity to identify and mitigate any potential issues before the
possibility of vegetation causing an outage.
Response: Thank you for your comment.
1) The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT modified R2 to remove the
use of the CCZ to trigger Imminent Threat procedure implementation. The Critical Clearance Zone has been replaced with Minimum Vegetation
Clearance Distance (MCVD) in R4. These changes may address your concerns.
2) Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The word,
“approached” is not used in the revised standard.
3) Requirement R1 Part 1.4 specifies the TVMP have an Imminent Threat procedure that includes notification of the responsible control center.
4) The SDT believes that having to implement an Imminent Threat procedure is proactive behavior and is in support of prevention of outages.
Pepco Holdings, Inc
Disagree
R5, R6 and R7 make this requirement redundant and unnecessary - it should be deleted. It is largely
unenforceable and does not make the standard clear, specific and regulatory enforceable. Further, PHI
believes the concept of enforcing no encroachment into the Critical Clearance Zone is a flawed approach.
Response: Thank you for your comment. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response,
the SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the
Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced
with Minimum Vegetation Clearance Distance (MCVD) in R4.
The SDT believes that having to implement an Imminent Threat procedure is proactive behavior and is in support of prevention of outages.
JEA
Disagree
The use of Gallet equations is not practical either for field use or for demonstrating compliance.
Response: Thank you for your comment. The SDT chose to use Gallet equations over IEEE primarily because Gallet is more appropriate for
determining the probability of flashover and the SDT believes holds distinct advantages for use in vegetation management applications. IEEE 516 is
developed for human safety purposes.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
September 8, 2009
Agree
We feel that changing to the Gallet equation will not have a large impact on its vegetation management
operations, so we have no concerns. We agree with R2, but feel that this clause makes R4 redundant, as per
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Question 11 Comment
our discussion under Comment # 15 below. We recommend the removal of R4 entirely from the standard.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
WECC
Agree
Yes but the wording is ambiguous. Vegetation under a transmission line is always "approaching" or growing
towards the transmission line. Entities should define a specific distance greater than the Critical Clearance
Zone when they are required to implement their Imminent Threat Procedures.
Response: Thank you for your comment. The proposed standard revision specifies a “Minimum Vegetation Clearance Distance” as a starting point
and TOs may apply greater distances at their discretion in order to trigger implementation of the Imminent Threat procedure. The word,
“approaching” is not used in the revised standard.
Baltimore Gas & Electric
Company
Agree
Again, each utility is responsible and accountable for it's actions. The Gallet clearances are a much better
approximation of a true spark gap than the present requirement. Without a clearance one requirement, the
closer tolerance produced by the Gallet equation will leave little room for error when a line is at or approaching
it's max. engineered sag. When vegetation gets in the new CCZ (if adopted), it will be likely that an outage
will be imminent. With the present clearance 1 and clearance 2 requirements, there is more of a buffer for
encroaching vegetation.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
The proposed standard revision specifies the MVCD as a starting point and TOs may apply multiples at its own discretion in order to achieve its TVMP
objectives and adhere to applicable safety standards.
CenterPoint Energy
September 8, 2009
Agree
We agree with replacing IEEE 516 standard distances with the Gallet equation standard distances. However,
the term "Critical Clearance Zone" refers to the "limits of the Active Transmission Line Right-of-way" which
has no specific definition as to its limits within the proposed revised Standard. (See comments to Q3 above.)
R2 should be reworded to coordinate with R1.4. (See comments to Q4 above.)
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Question 11 Comment
Response: Thank you for your comments. Please see our responses to Questions 3 and 4 comments as well as the summary consideration for this
question Based on stakeholder comments, the SDT made significant modifications to Requirement R2 and removed the concept of the CCZ.
Salt River Project
Agree
Although we agree that using the Gallet equation is more definitive than using IEEE 516, we still question from
an engineering prespective as to how and why this method was chosen. It is stated in the Technical
Reference paper that the Gallet Equation is a well known method of computing the required strike distance for
proper insulation coordination. It is our understanding it's purpose is for designing towers, to define the "tower
window" or opening inside of a tower under normal conditions. Because this is not a method designed
specifically for vegetation management, was there any physical testing involved in choosing this approach,
such as testing in both wet and dry conditions? We would recommend additional information to clarify this
method to use for vegetation management. See additional comments in Comment #18 below. In addition, we
feel this clause makes R4 redundant, as per our comments under Comment #15 below.
Response: Thank you for your comment. The Gallet equations indeed are useful in tower design; however it is not exclusively for that purpose. The
decision whether to use Gallet is not contingent upon testing and none were considered or conducted. No physical testing was utilized by the SDT;
however, the Gallet Equation method and its explanation in the White Paper do have their basis in physical testing in both laboratory and field
conditions. The Gallet Equation method is not solely applicable to tower structure design, but to any application requiring spark-over calculations.
The SDT believes that the Gallet Equation method holds distinct advantages over the IEEE 516 method for use in vegetation management
applications.
Southern California Edison
Company
September 8, 2009
Agree
Q11: SCE agrees in part with proposed R2. The use of the Gallet equation and the replacement of the
existing Clearance 2 requirement with the Critical Clearance Zone is acceptable. However, SCE strongly
disagrees with establishing a separate requirement for implementing an imminent threat procedure should
there be an encroachment of the Critical Clearance Zone because it forms the basis of an unnecessary zerotolerance enforcement policy. Read in context with corresponding Measure 2, R2 appears to require
Transmission Owners to prove that a Critical Clearance Zone encroachment did or did not occur and also
prove that that an imminent threat procedure was or was not properly invoked. Although SCE agrees that
CCZ encroachments should be addressed timely, we disagree with the notion and underlying assumption that
a CCZ incursion will always lead to a flash-over or a vegetation-to-line contact. If the goal of FAC-003-2 is to
prevent sustained outages (due to vegetation-to-line contacts) that could lead to Cascading, emphasizing
“prevention” is understandable, however, enforcing prevention measures is an entirely different matter. Under
the proposed requirements, a vegetation-to-line contact could conceivably represent two distinct violations of
FAC-003-2. SCE believes this type of regulatory double jeopardy is patently unfair and forcing Transmission
Owners to prove a CCZ encroachment did or did not occur is equally unfair and unenforceable. Because R1.4
adequately addresses the Transmission Owner’s responsibility regarding the implementation of an imminent
threat procedure, SCE respectfully recommends that proposed R2 and corresponding M2 be removed from
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Question 11 Comment
FAC-003-2.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat upon discovery of such a threat. The Critical Clearance Zone has been replaced with Minimum Vegetation
Clearance Distance (MCVD) in R4.
Buckeye Power, Inc.
Agree
I agree with R2. I like the language changes, but decreasing the clearances will not improve reliability.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
Great River Energy
Agree
GRE agrees and believes that the Gallet equation yields a less subjective measurement. GRE believes R2
should be modified to be more definitive. The imminent threat procedure should be implemented when
vegetation “enters” the Critical Clearance Zone (CCZ). It is GRE's opinion that approaching the CCZ is
subjective and as such very difficult to enforce.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure. The Critical Clearance Zone has been replaced with Minimum Vegetation Clearance Distance
(MCVD) in R4.
USDA Forest Service,
Southwestern Region,
Regional Office for AZ and NM
Agree
Attachment 1 is very conservative. I think that the clearance distances shown on the attachment should be
expanded to create, in effect, a standard that reflects maximum line loading and maximum line sag. I would
also like to see some flexibility built into the process so that the Transmission Owner and the USFS could
negotiate some consideration for vegetation growth rates. The end result would generate a standard that
would give the Transmission Owner the security of knowing that vegetation would not grow into the potential
arcing zone for some reasonable amount of time - some kind of entry cycle.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
September 8, 2009
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Question 11 Comment
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Measure M2 requires that the entity have evidence
showing dates and activities accomplished to meet the R2 implementation requirement. The SDT notes that the proposed standard revision does not
preclude the USFS and the TO from negotiating consideration for vegetation growth rates and in fact it is a good idea.
City of Tallahassee
Agree
As long as we do not have to have evidence of using the calculation! We should be able to use Table I as
provided.
Response: Thank you for your comment. Please see the summary response. Many commenters disagreed with this requirement and it has been
substantially modified.
Bonneville Power
Administration
Agree
BPA agrees with R2, but refer to comments submitted regarding R4 (please see our response to Question
#15) for related recommendations to R2.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
MRO NERC Standards Review Agree
Subcommittee
The MRO agrees and believes that the Gallet equation yields a less subjective measurement. The MRO
believes R2 should be modified to be more definitive. The imminent threat procedure should be implemented
when vegetation “enters” the critical clear zone. Fines and violations for approaching the zone is not
measurable or enforceable. The MRO believes that "approached" is subjective and not enforceable and
should be removed from the requirement.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
Northern California Power
Agency (NCPA)
Agree
Santee Cooper
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
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Arizona Public Service
Company
Agree?
Question 11 Comment
Agree
Independent Electricity System Agree
Operator
Northeast Utilities
Agree
Hydro-Quebec Transenergie
(HQT)
Agree
NPCC
Agree
WECC Reliability Coordination
Agree
Kansas City Power & Light
Agree
National Grid
Agree
Long Island power Authority
Agree
Central Maine Power Company
September 8, 2009
No comment
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12. The Standard Drafting Team revised the spark-over (also referred to as “flashover”) distance thresholds utilizing
technically-equivalent Gallet equations in lieu of IEEE 516 minimum air insulation distance (MAID) calculations that
were used in FAC-003-1. The rationale is that the minimum air insulation distances in IEEE 516 were safety
clearances developed under laboratory conditions and thus there exists concern these distances may be too
conservative to apply to lines operating in actual field conditions. Do you agree with this? If not, please explain.
Summary Consideration: The majority of responders (90%) agreed with this change. The minority view favored the
continued use of IEEE 516 and four responders advocating removing the tables from the standard.
After reviewing the industry comments, the SDT continues to support the merits of using the Gallet equations and maintaining
the tables in the standard. IEEE 516 values are safety clearances developed under laboratory conditions and thus these
distances are inappropriate for vegetation spark-over clearances associated with lines operating in actual field conditions. In
addition, IEEE Standards are subject to change which the SDT did not desire to have the Vegetation Reliability associated with
an IEEE Standard that may change without proper consideration of the impact to the Vegetation Reliability Standard.
By using the Gallet distances, the SDT feels this is a technically sound, independent value that represents a true spark-over
threshold distance. One must remember this is a minimum distance and the new requirement of 1.6 specifies the Transmission
Owner develop a maintenance strategy to ensure these clearances are never violated.
Organization
SERC Compliance Staff
Question 12
Disagree
Question 12 Comment
While the actual sparkover distance may be more correctly calculated using the Gallet equations, SERC staff
believes it is a less conservative approach to the goal of preventing vegetation related outages. If the concept
of the CCZ will remain in the standard, we suggest that the tables based on the Gallet equations be removed
from the standard and be kept in the technical white paper solely to assist in developing a common
understanding of the theory behind the establishment of a CCZ. However, the CCZ will continue to be a very
difficult, if not impossible, aspect of the standard to implement from the perspective of practical application and
compliance enforcement.
Response: The SDT thanks you for your response. The SDT feels that the tables are an important component and should be part of the standard. The
supporting documentation for the derivation of the tables resides in the technical reference document. The revised standard does not use the concept
of the CCZ.
Tennessee Valley Authority
September 8, 2009
Disagree
TVA agrees with this concept however as stated in Comment Question 11 response, this should be an element
of the White Paper and should not be in the Standard Requirement.
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Question 12
Question 12 Comment
Response: The SDT thanks you for your response. The SDT feels that the tables are an important component and should be part of the standard. The
supporting documentation for the derivation of the tables resides in the technical reference document.
Exelon
Disagree
Comments: By using the Gallet equations, the draft standard appears to support reducing the clearance
requirements as compared to IEEE 516. Given what we believe would be the difficulties in applying the
clearances as developed using the Gallet equation method, we question if dropping the IEEE 516 guidance
could have the unintended consequence of reducing reliability.
Response: The SDT thanks you for your response. The reduction in the clearance distances is due to applying smaller transient over-voltage factors
and not due to using the Gallet equations. The SDT feels that using the reduced over-voltage factors is a more realistic approach than using the
maximum factors in version 1. The Gallet equations are only one of the factors in developing clearances. The utility must also consider sag, sway,
growth, environmental conditions and other factors when developing an effective TVMP.
Northern Indiana Public Service
Company
Disagree
If T.O.'s are serious about public safety and potential electrical hazards or are required to comply with
NESC/IEEE safety standards, then the greater, more conservative clearance distances must apply. On an
complex issue where the aerial distances between live conductors and trees are dynamic and changing, I would
prefer to be on the side of caution and on the side of safety. Given the history of cascading blackouts due to
preventable tree contacts, there is a need to be conservative with the standards. I don't see it being in the
public interest to argue that established minimum air insulation distances are inappropriately restrictive when
applied to UVM.
Response: The SDT thanks you for your response. The Gallet equations are only one of the factors in developing clearances. The utility must also
consider sag, sway, growth, environmental conditions and other factors when developing an effective TVMP.
Consumers Energy Company
Disagree
The Gallet distances severely lessen the reliability of the transmission system since there is not a define
imminent threat distance and the Clearance 1 distances have been removed from this draft. The IEEE 516
distances provided a safety margin to allow for vegetation to grow and not be a reliability risk. A transmission
owner/operator of a moderate size could not effectively inspect often enough during the growing season to
protect lines from outages when trees are permitted to approach the Gallet formula distance and not be a
violation. Such close distances would permit utility management to severely cut vegetation management
budgets and allow trees to grow for 1-2 years beyond their scheduled maintenance cycle and not be in violation.
But, 2-3 years after the budget cut, the field operation would be faced with an insurmountable amount of trees
needing addressed and limited timeframes to complete the work. This is basically how the blackout occurred
and this standard decreases the requirements to allow this to happen again.
Response: The SDT thanks you for your response. The Gallet equations are only one of the factors in developing clearances. The utility must also
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Question 12
Question 12 Comment
consider sag, sway, growth, environmental conditions and other factors when developing an effective TVMP.
Baltimore Gas & Electric
Company
Disagree
As noted in 11 above, the Gallet equation would appear to be a much closer approximation of the actual spark
gap/flashover distance. It seems as though the new std. is making the protective zone around the conductors
smaller by replacing the Clearance 2 requirement with the CCZ, while at the same time eliminating any other
type of consideration for how much clearance needs to be achieved while trimming. All things being equal, if
the only demarcation for when vegetation is a threat to the lines is the clearance 2 or CCZ areas, it would make
sense to have this area be larger rather than smaller. Accordingly, I would recommend that the Clearance 2
value continue to be used instead of the Gallet equation-created CCZ.
Response: The SDT thanks you for your response. The Gallet equations are only one of the factors in developing clearances. The utility must also
consider sag, sway, growth, environmental conditions and other factors when developing an effective TVMP. Note that the revised standard does not
use the concept of the CCZ.
SERC Vegetation Management
Subcommittee (VMS)
Agree
Developing minimum sparkover distances in this standard is a superior approach for the stated reason in
question 12. In addition, referring to tables and values in another standard is problematic if the referenced
standard is revised and the tables are re-numbered or deleted altogether. We suggest that the tables based on
the Gallet equations be removed from the standard and be kept in the technical white paper solely to assist in
developing a common understanding of the threshold for taking actions.
Response: The SDT thanks you for your response. The SDT feels that the tables are an important component and should be part of the standard. The
supporting documentation for the derivation of the tables resides in the technical reference document.
SERC OC Standards Review
Group
Agree
Developing minimum sparkover distances in this standard is a superior approach for the stated reason in
question 12. In addition, referring to tables and values in another standard is problematic if the referenced
standard is revised and the tables are re- numbered or deleted altogether. The SERC OOCSRG suggests that
the tables based on the Gallet equations be removed from the standard and be kept in the technical white paper
solely to assist in developing a common understanding of the threshold for taking actions.
Response: The SDT thanks you for your response. The SDT feels that the tables are an important component and should be part of the standard. The
supporting documentation for the derivation of the tables resides in the technical reference document.
Western Utility Arborists
Agree
The Western Utilities feel that changing this will not have a large impact on its vegetation management
operations, so we have no concerns.
Response: The SDT thanks you for your response.
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American Electric Power (AEP)
Question 12
Agree
Question 12 Comment
AEP agrees that the Gallet Equation method is a reasonable and appropriate replacement for the IEEE 516
method.
Response: The SDT thanks you for your comments.
Platte River Power Authority
Agree
Changing this will not have a large impact on vegetation management operations, so we have no concerns.
Response: the SDT thanks you for your comments.
USDA Forest Service,
Southwestern Region, Regional
Office for AZ and NM
Agree
See comment for Question 11.
Response: The SDT thanks you for your response. The Gallet equations are only one of the factors in developing clearances. The utility must also
consider sag, sway, growth, environmental conditions and other factors when developing an effective TVMP.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Agree
We feel that changing this will not have a large impact on its vegetation management operations, so we have no
concerns.
Response: The SDT thanks you for your comments.
Salt River Project
Agree
As commented in Comment #11 above, although we agree that using the Gallet equation is more definitive than
using IEEE 516, we still question from an engineering prespective as to how and why this method was chosen.
It is stated in the Technical Reference paper that the Gallet Equation is a well known method of computing the
required strike distance for proper insulation coordination. It is our understanding it's purpose is for designing
towers, to define the "tower window" or opening inside of a tower under normal conditions. Because this is not
a method design specifically for vegetation management, was there any physical testing involved in choosing
this approach, such as testing in both wet and dry conditions? We would recommend additional information to
clarify this method to use for vegetation management. See additional comments in Comment #18 below.
Response: The SDT thanks you for your response. The SDT searched for a method other than the laboratory condition based IEEE 516 method to
determine minimum spark-over distances. The Gallet equations were derived for both wet and dry conditions and have been successfully used in many
design applications. The SDT feels that using these equations to derive these minimum distances is a conservative approach. We also expect that the
TO must also consider sag, sway, growth, environmental conditions and other factors when developing clearances for an effective TVMP.
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Buckeye Power, Inc.
Question 12
Agree
Question 12 Comment
I understand the reasoning for the change, but I do not see how decreasing clearances will increase reliability.
Response: The SDT thanks you for your response. The Gallet equations are only one of the factors in developing clearances. The utility must also
consider sag, sway, growth, environmental conditions and other factors when developing an effective TVMP.
British Columbia Transmission
Corp
Agree
BCTC feels that changing this will not have a large impact on its vegetation management operations, so we
have no concerns.
Response: The SDT thanks you for your response.
Associated Electric Cooperative
Inc.
Agree
NPCC
Agree
WECC Reliability Coordination
Agree
Western Area Power
Administration, Upper Great
Plains Region
Agree
Progress Energy Florida
Agree
Kansas City Power & Light
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Progress Energy Carolinas
Agree
Southern California Edison
Company
Agree
September 8, 2009
Q12: No comments.
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Question 12
Florida Power & Light
Agree
Santee Cooper
Agree
Southern Company
Agree
E.ON U.S.
Agree
Bonneville Power Administration
Agree
FirstEnergy
Agree
MRO NERC Standards Review
Subcommittee
Agree
Midwest ISO Stakeholders
Standards Collaborators
Agree
ITC HOLDINGS
Agree
Central Maine Power Company
Agree
City of Tallahassee
Agree
Northern California Power
Agency (NCPA)
Agree
Tampa Electric Company
Agree
Orange and Rockland Utilities
Inc.
Agree
Ameren
Agree
September 8, 2009
Question 12 Comment
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Question 12
Nebraska Public Power District
Agree
Long Island power Authority
Agree
Manitoba Hydro
Agree
National Grid
Agree
Pacific Gas & Electric Co.
Agree
San Diego Gas & Electric
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
Consolidated Edison Company of
New York (CECONY)
Agree
WECC
Agree
Arizona Public Service Company
Agree
Duke Energy Corporation
Agree
CenterPoint Energy
Agree
Entergy Services
Agree
Pepco Holdings, Inc
Agree
JEA
Agree
Independent Electricity System
Agree
September 8, 2009
Question 12 Comment
157
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Question 12
Question 12 Comment
Operator
Northeast Utilities
Agree
Hydro-Quebec Transenergie
(HQT)
Agree
Great River Energy
Agree
Formatted: Indent: Left: 0"
September 8, 2009
158
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
13. The Standard Drafting Team applied a transient overvoltage factor (T) of 1.4 and 2.0 for ac voltage classes of 345kV
and above and sub-345kV facilities, respectively. Version 1, using the IEEE 516 method, assumes a maximum
transient overvoltage value. The Standard Drafting Team asserts that in this application of steady-state flashovers
and due to the design attributes of higher voltage systems, a lower T factor is applicable. Do you agree with this? If
not, please explain.
Summary Consideration: The majority of responders (93%) agreed with this change. Two responders commented that they
use a more conservative transient over-voltage factor in their design.
The SDT chose its transient over-voltage factors (“T”) as being the most appropriate values for the industry as a whole. The
majority of industry stakeholder comments supported this decision. It is permissible to use more conservative values if the
Transmission Owner so desires.
Organization
Agree ?
BCTC
Question 13 Comment
BCTC feels that changing this will not have a large impact on its vegetation management operations, so we
have no concerns.
Response: The SDT thanks you for your response.
Tennessee Valley Authority
Disagree
TVA agrees with this concept however as stated in Comment Question 11 response, this should be an
element of the White Paper and should not be in the Standard Requirement.
Response: The SDT thanks you and refers you to the response to Question 11.
Exelon
Disagree
We disagree with the T factors that are proposed as our design is more conservative.
Response: The SDT thanks you and also acknowledges that various utilities may employ various T factors in their line designs. However, the SDT chose
this value as the most appropriate value for the industry as a whole. Individual Transmission Owners are free to establish larger zones around the
conductor than that established by the new MVCD. MVCD as currently drafted establishes a minimum value, not the only value.
Manitoba Hydro
September 8, 2009
Disagree
Manitoba Hydro has historically designed the ROW clearance requirements based on an operating limitation
of not switching during extreme wind conditions, therefore, beyond a wind pressure of 230 Pa, our design
does not account for switching surge over voltages. We do however, agree with the use of overvoltage factors
159
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree ?
Question 13 Comment
as described above for wind conditions of less than 230 Pa.
Response: The SDT thanks you for your comments. Industry as a whole. Individual Transmisssion Owners are free to establish larger zones around the
conductor than that established by the new MVCD. MVCD as currently drafted establishes a minimum value, not the only value.
National Grid
Disagree
No opinion.
Response: The SDT thanks you for your comments. The SDT believes that it has chosen an approach that is the most appropriate method for the industry
as a whole.
SERC Vegetation Management
Subcommittee (VMS)
Agree
See comments in #12 above.
Response: The SDT thanks you for your comments. See response to #12.
SERC OC Standards Review Group
Agree
See comments in #12 above.
Response: The SDT thanks you for your comments. See response to #12.
Salt River Project
Agree
As commented in Comments #11 & #12 above, although we agree that using the Gallet equation is more
definitive than using IEEE 516, we still question from an engineering prespective as to how and why this
method was chosen. It is stated in the Technical Reference paper that the Gallet Equation is a well known
method of computing the required strike distance for proper insulation coordination. It is our understanding it's
purpose is for designing towers, to define the "tower window" or opening inside of a tower under normal
conditions. Because this is not a method design specifically for vegetation management, was there any
physical testing involved in choosing this approach, such as testing in both wet and dry conditions? We would
recommend additional information to clarify this method to use for vegetation management. See additional
comments in Comment #18 below.
Response: The SDT thanks you for your comments. No physical testing was utilized by the SDT; however, the Gallet Equation method and its explanation
in the White Paper do have their basis in physical testing in both laboratory and field conditions. The Gallet Equation method is not solely applicable to
tower structure design, but to any application requiring spark-over calculations. The SDT believes that the Gallet Equation method holds distinct
advantages over the IEEE 516 method for use in vegetation management applications.
Western Utility Arborists
September 8, 2009
Agree
The Western Utilities feel that changing this will not have a large impact on its vegetation management
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree ?
Question 13 Comment
operations, so we have no concerns.
Response: The SDT thanks you for your comments.
American Electric Power (AEP)
Agree
AEP agrees that the choice of transient overvoltage factors is sufficiently sound.
Response: The SDT thanks you for your comments.
Platte River Power Authority
Agree
Changing this will not have a large impact on vegetation management operations, we have not concerns.
Response: The SDT thanks you for your comments.
City of Tallahassee
Agree
As long as we do not have to have evidence of using the calculation! We should be able to use Table I as
provided.
Response: The SDT thanks you for your comments.
NV Energy (fka Sierra Pacific / Nevada Agree
Power Co.)
We feel that changing this will not have a large impact on its vegetation management operations, so we have
no concerns.
Response: The SDT thanks you for your comments.
Southern California Edison Company
Agree
Associated Electric Cooperative Inc.
Agree
NPCC
Agree
WECC Reliability Coordination
Agree
Western Area Power Administration,
Upper Great Plains Region
Agree
Progress Energy Florida
Agree
September 8, 2009
Q13: No comments.
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Organization
Agree ?
Kansas City Power & Light
Agree
Western Area Power Administration,
Rocky Mountain Region
Agree
Progress Energy Carolinas
Agree
Florida Power & Light
Agree
Santee Cooper
Agree
Southern Company
Agree
E.ON U.S.
Agree
Bonneville Power Administration
Agree
FirstEnergy
Agree
MRO NERC Standards Review
Subcommittee
Agree
Midwest ISO Stakeholders Standards
Collaborators
Agree
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
Central Maine Power Company
Agree
Northern California Power Agency
(NCPA)
Agree
September 8, 2009
Question 13 Comment
162
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree ?
Tampa Electric Company
Agree
Orange and Rockland Utilities Inc.
Agree
Ameren
Agree
Nebraska Public Power District
Agree
Long Island power Authority
Agree
Consumers Energy Company
Agree
Pacific Gas & Electric Co.
Agree
San Diego Gas & Electric
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
Consolidated Edison Company of New
York (CECONY)
Agree
WECC
Agree
Arizona Public Service Company
Agree
Duke Energy Corporation
Agree
CenterPoint Energy
Agree
Entergy Services
Agree
Pepco Holdings, Inc
Agree
September 8, 2009
Question 13 Comment
163
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree ?
JEA
Agree
Independent Electricity System
Operator
Agree
Northeast Utilities
Agree
Hydro-Quebec Transenergie (HQT)
Agree
Buckeye Power, Inc.
Agree
Great River Energy
Agree
Question 13 Comment
Baltimore Gas & Electric Company
I have no expertise to respond to this question.
Northern Indiana Public Service
Company
No comment.
USDA Forest Service, Southwestern
Region, Regional Office for AZ and NM
Don't know!
September 8, 2009
164
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
14. R3 has been added to clarify that conduction of inspections is a separate requirement from specifying the frequency
that inspections will occur. Do you agree with R3? If not please explain.
Summary Consideration: The majority of commenters (85%) were in favor of the standard as written. There were minority
comments that wanted a reformatting of the standard to put documentation and implementation side by side. Following the
directives in FERC order 693 and the SAR to bring the standard in line with the Sanction Guidelines, the SDT created a separate
requirement, R3 that explicitly requires inspections be conducted. This is to differentiate R3 from Requirement 1, Part 1.2.
Addressing inspections separately allows for appropriate assignment of VRFs and VSLs.
Organization
Agree?
BCTC
Question 14 Comment
BCTC understands that it’s possible to have a schedule and not implement it. However, we feel that the document
itself would be easier to follow if it was re-organized so that the requirement to have the schedule is kept together
with the requirement to implement it.
Response: The SDT thanks you for your comment. The SDT considered other sequence options and suggest a new sequence for the industry to comment
upon. See related question in the second Comment Form.
Western Utility Arborists
The Western Utilities understands that it’s possible to have a schedule and not implement it. However, we feel
that the document itself would be easier to follow if it was re-organized so that the requirement to have the
schedule is kept together with the requirement to implement it.
Response: The SDT thanks you for your comment. The SDT considered other sequence options and suggest a new sequence for the industry to comment
upon. See related question in the second Comment Form.
Progress Energy Florida
Disagree
The standard has established a threshold of compliance. For consistency, compliance should be measured at the
threshold not a Registered Entities program requirement.
Response: The SDT thanks you for your comments. R3 clarifies that the inspections in the TVMP are to be conducted. The TVMP defines a Transmission
Operator’s standards. The general application of NERC standards is that a Transmission Operator is to adhere to the standards it establishes.
Progress Energy Carolinas
Disagree
The standard has established a threshold of compliance. For consistency, compliance should be measured at the
threshold not a Registered Entities program requirement.
Response: The SDT thanks you for your comments. R3 clarifies that the inspections in the TVMP are to be conducted. The TVMP defines a Transmission
September 8, 2009
165
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 14 Comment
Operator’s standards. The general application of NERC standards is that a Transmission Operator is to adhere to the standards it establishes.
Southern California Edison
Company
Disagree
Q14: SCE does not agree with the inclusion of proposed R3 and believes it should be replaced with a modified
version of proposed R8.SCE respectfully suggests that proposed R8 be revised to read: "Each Transmission
Owner shall implement and follow its Vegetation Management Program to the extent allowed by existing
easement and/or legal rights."
Response: The SDT thanks you for your comments. Inspections are a key element of an effective TVMP. The SDT therefore decided to explicitly require
that inspections be conducted in accordance with the Transmission Owners’ requirements. In addition, addressing inspections separately allows for
appropriate assignment of VRFs and VSLs.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Disagree
We understand that it is possible to have a schedule and not implement it. However, we feel that the document
itself would be easier to follow if it was re-organized so that the requirement to have the schedule is kept together
with the requirement to implement it.
Response: The SDT thanks you for your comment. The SDT decided to explicitly require that inspections be conducted in accordance with the
Transmission Owners’ requirements. Addressing inspections separately allows for appropriate assignment of VRFs and VSLs.
San Diego Gas & Electric
Disagree
The information should not be separated. It will be much easier to follow if the requirement to have the schedule
is kept together with the requirement to implement it.
Response: The SDT thanks you for your comment. The SDT decided to explicitly require that inspections be conducted in accordance with the
Transmission Owners’ requirements. Addressing inspections separately allows for appropriate assignment of VRFs and VSLs.
Edison Electric Institute
Disagree
Consistent with previous comments, NERC should respond to FERC Order No. 693 Paragraph 721 regarding
compliance audit procedures to identify appropriate inspection cycles.
Response: The SDT thanks you for your comment. The SDT decided to explicitly require that inspections be conducted in accordance with the
Transmission Owners’ requirements. Your comment has been forwarded to NERC staff. The Reliability Standard Audit Worksheet is where the FERC
Order is addressed with respect to compliance audit procedures to identify appropriate inspection cycles.
Baltimore Gas & Electric
Company
September 8, 2009
Disagree
If frequency of inspections are required to be specified, it is implied that the inspections will follow. I suggest that
R3 be eliminated and R1.2 be reworded to say: "Vegetation inspections shall occur at least once per year, or
more frequently as dictated by local and environmental factors. Specify the frequency of when vegetation
inspections will occur."
166
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 14 Comment
Response: The SDT thanks you for your comment. The SDT decided to explicitly require that inspections be conducted in accordance with the
Transmission Owners’ requirements. Addressing inspections separately allows for appropriate assignment of VRFs and VSLs. The STD believes that the
phrase “Specify a vegetation inspection frequency…” adequately requires the Transmission Operator to “. . . .specify the frequency…”
JEA
Disagree
See comment from #3.
Response: The SDT thanks you for your comment. This was addressed in the response to question 3.
Salt River Project
Disagree
The document would be easier to follow if the two elements would be kept together in the same requirement
(similar to comments stated in Comments #4 & #6 above). It makes the standard longer than necessary and
creates redundancy.
Response: The SDT thanks you for your comment. The SDT decided to explicitly require that inspections be conducted in accordance with the
Transmission Owners’ requirements. Addressing inspections separately allows for appropriate assignment of VRF and VSLs.
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 14
Response: The SDT thanks you for your comment.
American Electric Power (AEP) Agree
AEP agrees with this change.
Response: The SDT thanks you for your comment.
Platte River Power Authority
Agree
The separation allows lower sanctions and penalties to be assessed for a weak schedule and higher sanctions
and penalties to be assessed for not implementing schedules. However, we feel that the standard itself would be
easier to follow if it was re-organized so that the requirement to have the schedule is kept together with the
requirement to implement it.
Response: The SDT thanks you for your comment. The SDT decided to explicitly require that inspections be conducted in accordance with the
Transmission Owners’ requirements. Addressing inspections separately allows for appropriate assignment of VRFs and VSLs.
Arizona Public Service
Company
September 8, 2009
Agree
APS understands that it’s possible to have a schedule and not implement it. However, we feel that the document
itself would be easier to follow if it was re-organized so that the requirement to have the schedule is kept together
with the requirement to implement it.
167
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 14 Comment
Response: The SDT thanks you for your comment. The SDT decided to explicitly require that inspections be conducted in accordance with the
Transmission Owners’ requirements. Addressing inspections separately allows for appropriate assignment of VRFs and VSLs.
Associated Electric
Cooperative Inc.
Agree
NPCC
Agree
WECC Reliability Coordination
Agree
Western Area Power
Administration, Upper Great
Plains Region
Agree
SERC Vegetation
Management Subcommittee
(VMS)
Agree
Kansas City Power & Light
Agree
Western Area Power
Administration, Rocky
Mountain Region
Agree
SERC OC Standards Review
Group
Agree
Florida Power & Light
Agree
Santee Cooper
Agree
Southern Company
Agree
E.ON U.S.
Agree
September 8, 2009
168
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Organization
Agree?
Bonneville Power
Administration
Agree
FirstEnergy
Agree
Question 14 Comment
MRO NERC Standards Review Agree
Subcommittee
Midwest ISO Stakeholders
Standards Collaborators
Agree
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
Exelon
Agree
Central Maine Power
Company
Agree
City of Tallahassee
Agree
Northern California Power
Agency (NCPA)
Agree
Northern Indiana Public
Service Company
Agree
Tampa Electric Company
Agree
Orange and Rockland Utilities
Inc.
Agree
American Transmission
Agree
September 8, 2009
169
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 14 Comment
Company
Ameren
Agree
Nebraska Public Power District Agree
Long Island power Authority
Agree
USDA Forest Service,
Southwestern Region,
Regional Office for AZ and NM
Agree
Manitoba Hydro
Agree
Consumers Energy Company
Agree
National Grid
Agree
Pacific Gas & Electric Co.
Agree
Hydro One Networks Inc.
Agree
Consolidated Edison Company Agree
of New York (CECONY)
WECC
Agree
Duke Energy Corporation
Agree
CenterPoint Energy
Agree
Entergy Services
Agree
Pepco Holdings, Inc
Agree
September 8, 2009
170
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 14 Comment
Independent Electricity System Agree
Operator
Northeast Utilities
Agree
Hydro-Quebec Transenergie
(HQT)
Agree
Buckeye Power, Inc.
Agree
Great River Energy
Agree
September 8, 2009
171
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
15. Several alternatives to R4 were considered by the drafting team. The drafting team explored these significantly
different alternatives at length. They are outlined below to provide background to industry during this comment
period. (Please refer to pages 22-32 in the Technical Reference Document on the Critical Clearance Zone for further
background for this question.) Do you agree that R4 is written in the most effective way to achieve the purpose of the
standard? If not, what do you propose as an alternative to R4 that would ensure a level of reliability equal to or better
than FAC-003-1?
As written, R4, a new requirement, stipulates that the Transmission Owner is in violation if an encroachment of the Critical
Clearance Zone occurs at any time. If vegetation enters the Critical Clearance Zone, a violation will have occurred, regardless
of the actual proximity of the vegetation to the conductor at the time. Evidence will be required to prove that no
encroachments of the Critical Clearance Zone have occurred anywhere at any time during the annual compliance period. This
will require the time and effort to postpone vegetation maintenance to perform field investigations and document all possible
encroachments.
One alternative to R4 required immediate removal of the vegetation or immediate implementation of the imminent threat
procedure upon discovery of a possible encroachment of the Critical Clearance Zone, thereby proactively preventing an outage.
A violation would have occurred only if the imminent threat process was not successfully implemented.
Another alternative was a tiered approach. This tiered approach involved a “per thousand mile” metric to determine when a
violation had occurred and the severity of the violation. This metric was an attempt to equitably account for varying exposures
that exist due to widely ranging system sizes.
Summary Consideration: Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The Critical Clearance Zone has been replaced with the “Minimum
Vegetation Clearance Distances”, and Transmission Owners are required to prevent encroachment of vegetation into “Minimum
Vegetation Clearance Distances” as observed in real time.
Ninety-four percent of the commenters disagreed with the proposed alternatives. The SDT classified the comments into 44
different concepts with many commenters weighing in on several concepts. For 37 commenters the dominant concept was
“Measure M4 requires proof of no encroachments, i.e., "prove a negative", compliance certification is difficult.” Below is a
redlined version of R4. reflecting the changes that were made by the SDT.
R4.
Each Transmission Owner shall prevent encroachment of vegetation into the Minimum Vegetation Clearance Distances
(“MVCD”) listed in Attachment 1 for its applicable lines as observed in real-time operating between no-load and their
Rating with the following exceptions: [Violation Risk Factor VRF= Medium][Time Horizon – Real Time]
September 8, 2009
172
Deleted: within
Deleted: Critical
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Encroachment into the Minimum Vegetation Clearance Distances listed in Attachment 1 resulting from natural disasters.2
Encroachment into the Minimum Vegetation Clearance Distances listed in Attachment 1 resulting from human or animal
activity.3
Brief encroachment into the Minimum Vegetation Clearance Distances listed in Attachment 1 resulting from falling
vegetation.
Deleted: 1.
Formatted: Indent: Hanging: 0.25",
Pattern: Clear (Custom
Color(RGB(211,220,233))), Tabs: Not
at 0.5" + 1.03" + 1.8" + 2.25"
Deleted: 2.
Deleted: 3.
The SDT further weighed the NERC interpretation of the vegetation management standard during FERC’s consideration of
proposed FAC-003-1: A vegetation-related transmission line outage as a result of vegetation that has grown into the predefined clearance zone is a violation of the standard. The Commission adopted that interpretation when it approved NERC’s
proposed reliability standards. It stated, “FAC-003-1 requires sufficient clearances to prevent outages due to vegetation
management practices under all applicable conditions.”4
In reviewing the comments and the FERC opinion the SDT considered 4 options:
Re-word R4 and keep R4 the way it was originally intended (violation would only be if you had the outage)
of Question 15**) {implies that R5, R6, & R7 are retained}
Remove R2 and R4 from the standard. Keep the Critical Clearance Zone
Remove R4 from the standard and revise R2 to have a "trigger distance" for implementation of the imminent threat process.
Keep the Critical Clearance Zone concept in the white paper. Team would need to consider the true definition of an
imminent threat.
Return to the Clearance 2 concept. But define (somehow) that this is a "real time" violation only. Distance could be defined
as the Gallet distance or a multiple of the Gallet distance.
(Alternative B
concept in the white paper.
The SDT made the following changes in line with bullet 4.
R4.
Each Transmission Owner shall prevent encroachment of vegetation into the Minimum Vegetation Clearance Distances
(MVCD) listed in FAC-003-2 - Attachment 1 for its applicable lines as observed in real-time operating between no-load and
their Rating, with the following exceptions:
Deleted: within
Deleted: Critical
Deleted: Zone of
Deleted: 1.
4
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting from natural disasters.
Formatted: Font: 11 pt
Deleted: Encroachments of
Deleted: Critical
2
Examples include, but are not limited to, earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the
Transmission Owner or an applicable regulatory body, ice storms, and floods.
3
Examples include, but are not limited to, logging, animal severing tree, vehicle contact with tree, arboricultural activities or horticultural or agricultural
activities, or removal or digging of vegetation.
September 8, 2009
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting from human or animal activity.5
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting from falling vegetation.
Deleted: Encroachments of
Deleted: Critical
Formatted: Font: 11 pt
Organization
PJM Interconnection
Agree?
Formatted: No bullets or
numbering, Pattern: Clear (Custom
Color(RGB(211,220,233)))
Question 15 Comment
The current version of this standard, FAC-003-1, kept the subject of vegetation outside of the Rights of Way in the
standard. Why are outside of Rights of Way vegetation issues not mentioned in FAC-003-2, or some responsibility
for looking for outside of Rights of Way imminent threats or issues requiring corrective action plans not
addressed?
Response: The SDT thanks you for your comments. Trees outside of the right of way should be identified and removed as necessary as they are identified
as a threat to the reliability of the line. This function should be part of a vegetation management program as a follow up to the inspection process. Any
vegetation that could pose a threat to the reliability to the line found during the inspection process should be remedied. The purpose statement for FAC003-2 states that the standard is intended to improve the reliability of the electric transmission system by preventing vegetation related outages that could
lead to Cascading.
BCTC
The new requirement in R4 stipulates that the Transmission Owner is in violation if an encroachment of the CCZ
occurs at any time. However, the CCZ changes with each foot of the transmission line from the insulator to the
mid-span, depending on loading, actual operating temperature, wind loading, ice loading, maximum design rating,
maximum operating load, and so on. Further, Measure M4 requires that the Transmission Owner has evidence
demonstrating there were no vegetation encroachments into the CCZ. These requirements may result in having to
LIDAR the lines annually, to prove that trees have not encroached upon the CCZ. This would be an extremely
onerous and expensive requirement for utilities. BCTC strongly supports the alternative to R4 as recommended in
the Comment Form (#15), which is to require immediate removal of the vegetation or immediate implementation of
the imminent threat procedure upon discovery of a possible encroachment of the CCZ, thereby proactively
preventing an outage. This means a violation would occur only if the imminent threat process is not successfully
implemented. This alternative is essentially the same as R2. Therefore, BCTC recommends removing R4 from the
standard entirely.
4
Examples include, but are not limited to, earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the
Transmission Owner or an applicable regulatory body, ice storms, and floods.
5
Examples include, but are not limited to, logging, animal severing tree, vehicle contact with tree, arboricultural activities or horticultural or agricultural
activities, or removal or digging of vegetation.
September 8, 2009
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Organization
Agree?
Question 15 Comment
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Associated Electric Cooperative
Inc.
Disagree
Associated Electric Cooperative Inc believes this requirement, as written, is unreasonable since it would prevent
(or at least result in noncompliance) the intrusion within the Critical Clearance Zone (CCZ) of anything or anyone,
including qualified line workers and their tools. It is suggested the words “of vegetation” be added between
encroachment and within. The requirement would then read, “Each Transmission Owner shall prevent
encroachment of vegetation within the Critical Clearance Zone of its applicable lines with the following exceptions:”
The complexity of determining an encroachment into the Critical Clearance Zone is overly burdensome, requiring
engineering calculations and possibly the need for precision measurements. The Transmission Owner (TO)
cannot demonstrate compliance with the Requirement and its companion Measure, M4, since a negative cannot
be proven. Therefore, since the TO must demonstrate compliance (guilty until proven innocent), it is automatically
in violation of the Standard.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time. The
SDT, for clarity, did add the phrase “of Vegetation” as requested.
NPCC
Disagree
September 8, 2009
The purpose of the standard is "To improve the reliability of the Bulk Electric System by preventing vegetation
related outages that could lead to Cascading". We believe that R4 is not the most effective way to achieve this
purpose because it does not provide incentive for Transmission Owners to take advantage of modern technology,
such as aerial laser survey (ALS) using Light Detection and Ranging technology (LIDAR), that is capable of
accurately identifying vegetation which is approaching the CCZ or has encroached into it. In fact R4 provides an
incentive not to utilize this technology because Transmission Owners who identify encroachments would be in
violation of R4 for each identified encroachment. On the other hand, Transmission Owners who choose to be less
proactive often would not identify such encroachments because the CCZ and encroachments of it are generally
not easy to determine without taking precise measurements. Unless the line is heavily loaded or the vegetation is
significantly overgrown, encroachments of the CCZ would not be readily noticed. In most cases these
Transmission Owners would simply remove or cut back incompatible vegetation without taking measurements.
The threat to the line would have been eliminated with no encroachment having been identified.R4 presents a
dilemma for Transmission Owners that are considering making the significant investment in ALS technology. While
the technology would allow them to identify any potential grow-in or fall-in conditions, it would also expose them to
the risk of identifying violations of R4, that would otherwise not have been identified. Violation Risk Factors
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Organization
Agree?
Question 15 Comment
(VRFs), Violation Severity Levels (VSLs), and Time Horizons are not included in this Draft, but after making a
significant investment in ALS, Transmission Owners could be faced with significant additional cost in terms of
NERC penalties. In addition, even if the penalties were relatively low they would be exposing themselves to
violations that less proactive Transmission Owners would not be exposed to. In our view R4 as written would, in
some cases, have the opposite effect of what is intended because the business case for using ALS is more
difficult to make. This will result in less use of ALS and other emerging technology that is likely to be developed.
This would result in fewer problems being identified, a small percentage of which will not be discovered until they
result in a line trip. Still we believe that the concept of the CCZ is a good one and recommend that R4 be changed
so that Transmission Owners are provided with an incentive to invest in the best technology available in order to
ensure the highest level of reliability. The opportunity exists to develop the standard in a manner that encourages
the industry to take advantage of new technology and manage vegetation in a very proactive way. We recommend
that R4 be changed as follows: Modify R4 to require Transmission Owners to immediately implement the imminent
threat process defined in R1.4 when they identify instances where the CCZ is approached or encroached upon.
Failure to do so would be a violation of R4. Eliminate encroachment of the CCZ as a violation of R4. This would
eliminate R2 and incorporate implementation of the imminent threat process into R4.Require Transmission
Owners to report to the Regional Entity on a quarterly basis any instances where the imminent threat process was
implemented due to an encroachment of the CCZ. This would add a reporting requirement for Transmission
Operators. Require Transmission Owners to report to the Regional Entity on a quarterly basis any instances where
either a momentary or sustained outage was caused by grow-ins, Active Transmission Line Right of Way blow-ins,
or Active Transmission Line Right-of-Way fall-ins. This would add three additional reporting requirements for
Transmission Operators. Require Regional Entities to perform additional audits of Transmission Owners that
exceed metrics for violations of the CCZ . The metrics would be established in this Standard based upon 100
circuit miles of applicable lines. This would add an additional requirement for Regional Entities. This concept would
result in a more rigorous standard than FAC-003-01 because of the additional reporting and auditing requirements.
It would drive proactive behavior throughout the industry and provide a significant incentive for Transmisison
Owners to invest in new technology such as ALS that is capable of accurately identifying vegetation that has
approached or encroached upon the CCZ. We believe that this change would result in the identification of more
incipient vegetation-related problems and fewer vegetation-related outages as soon as it was implemented and
would best support the purpose of the Standard.
Response: The SDT thanks you for your comments. The SDT concurs that the use of ALS – LiDar technology, while expensive, could enhance reliability.
However several team members have made the investment and concur that the technology including interpertation software are not sufficiently mature to
be put in a standard. In addition in some cases it would not be cost justifiable over traditional methods of inspection. During the course of our
deliberations the team questioned both FERC and RE staff’s response to a utility finding encrochments with ALS technology and concluded the auditor
would not forgive encrochment even though the Transmission Owner went to extraordinary means to find the encrochment.
Initially the team approached the FERC staff in a meeting in Washington with a proposal that an encrochment not be a violation if the Transmission Owner
implemented the imminent threat procedure successfully before an interruption occurred. The concept was rebuffed by the FERC Staff as a step
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backwards from version 1.
The SDT very carefully and thoroughly examined the merits, disadvantages, ease and difficulties of assessing momentary outages as a violation. The
result of that effort led to the more precise and field observable aspects of R4. It should be noted that by their very nature the exact causes of “momentary
outages” are very challenging to determine and will vary widely from utility to utility. The SDT did not find that such variability was appropriate for a
reliability standard, and chose to address this issue with the language in R4.
Due to the industry impact that arises from zero tolerance for vegetation-related sustained outages, the Drafting Team tried several approaches but could
not find a mechanism in the standard development process to establish a non-zero threshold for outages that was acceptable to FERC staff because
Standard revisions to already approved standards may not lead to less emphasis on reliability.
Western Area Power
Administration, Upper Great
Plains Region
Disagree
R4 as proposed would do nothing to improve the reliability of the BES. In fact, we believe that R4 (as currently
proposed) would impose significantly more stringent requirements than most Transmission Owners have
interpreted FAC-003-1 to require. We believe that if the proposed interpretation would have been offered under
FAC-003-1 that there would have be a great backlash against that Standard. It is our believe that current annual
certifications of compliance for FAC-003-1 by Transmission Owners don't use "any infringement of the CCZ by any
piece of vegetation at any time" as their measure for compliance. It could be argued that this proposal would
actually do more to curtail accurate reporting of potential violations. We believe that making an infringement into
the CCZ a violation and having that violation carry a six (or seven) figure fine would do more to discourage
accurate reporting than any other system under discussion. Making the Transmission Owner prove that an
incursion into the CCZ didn't happen would force an inventory of every inch of the R/W which is a gigantic waste of
resources. Being tasked with proving that something didn't happen could be compared with our justice system
declaring suspects will be considered guilty until they are proven innocent. This is a flawed and blatantly unfair
concept and not a productive way of attaining the Purpose stated in this document. Western (UGPR) is
disappointed by the "zero tolerance" nature of this document and its interpretation that "any infringement of the
CCZ by any piece of vegetation at any time" constitutes a violation. We are not aware of any other NERC
standard that is zero tolerance and question why vegetation is singled out to bear the brunt when several other
factors could contribute to a system cascading event (i.e. relay problems, system configuration, operator issues,
etc). In summation, we believe that a zero tolerance document being applied with "guilty until proven innocent"
principles would do much to create an increasingly adversarial relationship between regulators and the industry.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
SERC Vegetation Management
Subcommittee (VMS)
September 8, 2009
Disagree
The concept of the CCZ is useful as a mental model to visualize required vegetation management work. While
this is a good conceptual tool to drive consistent terminology and proper vegetation management practices, it
remains theoretical in nature and impractical to measure on a span by span basis. The complexity of determining
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an encroachment into the CCZ is overly burdensome due to the need for survey accuracy measurements and
engineering evaluations. In addition, this complexity leads to questions about the ability to audit this requirement.
These complexities introduce reliability and audit issues when encroachments into this conceptual area are
defined as violations. The SERC VMS believes the Sustained Outage, as defined by other measures in this
standard, should be the non-compliance measure. We suggest that the CCZ concept be kept in the technical white
paper and that all references to the CCZ be removed from the body of the standard.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Progress Energy Florida
Disagree
The definition of Critical Clearance Zone includes too many academic and theoretical elements. It is impossible to
provide evidence that vegetation did not encroach into the Critical Clearance Zone during TVMP cycles.
Furthermore, the operations staff performing periodic ground and aerial inspections would need to determine the
CCZ for each foot of transmission line to assure compliance with the standard as it is currently written. The CCZ
concept can neither be implemented or enforced as written. The CCZ refers to Ratings which is defined in the
Glossary of Terms as "The operational limits of a transmission system element under a set of specified
conditions." This definition is too broad to be a consistently enforceable term from one utility or region to the next.
As it is currently written, no exemption exists for vegetation falling from outside the Active Transmission Line Right
of Way into, or lodging in, the theoretical CCZ.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Kansas City Power & Light
September 8, 2009
Disagree
As proposed, Requirement R4 and corresponding Measure M4 will be highly subjective and impractical for the
industry to implement. The determination of a violation due to encroachments into the Critical Clearance Zone will
be subjective in nature due to field judgments, is random and not initiated by a known system event. It also will
not be feasible for utilities to fulfill R4 requirements to ensure and provide evidence that any encroachments into
Critical Clearance Zones have not occurred on their system throughout the year. Requirement R4 is not required
since in the remaining requirements of FAC-003-2 contain the principal elements for compliance in ensuring the
reliability of the bulk power system related to vegetation management of the transmission system. Specifically, the
remaining requirements provide that a transmission vegetation plan be maintained, implemented and regularly
reviewed whereby utilities must perform the requisite vegetation clearance work in order to prevent any sustained
outages on the bulk power system. A sustained outage due to vegetation is a known, measurable event to which
a penalty sanction will be invoked and therefore provides the required impetus for adherence to standard FAC003-2.Requirement R4 and the associated measure M4 should therefore be removed from the proposed standard
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language.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Western Area Power
Administration, Rocky Mountain
Region
September 8, 2009
Disagree
As discussed in the Technical Reference document and question #11 above, the CCZ is a complicated theoretical
envelope surrounding all rated operating positions of the conductor. Its dynamic shape is constantly changing and
is contingent upon location within the span. Calculation of the size and shape of CCZ is based, in part, upon the
design parameters of the transmission facility. However, as-built or long term maintenance conditions can often
diverge from the original design requirements over time. Ground elevations can also change as a result of man
made or natural causes from the original design elevations recorded on plan and profile engineering drawings.
Consequently, accurate field measurement of the as-built CCZ is extremely problematic and strategies that utilize
the calculation of allowable right-of-way tree heights can be hindered by unrecorded deviations from the original
design criteria. Allowable tree height strategies also become increasingly more difficult and impractical with
increasing extremes in terrain. While the CCZ is a very important concept for an effective vegetation
management program it is far to theoretical, dynamic, and impractical to field measure for use as a clear and
precise boundary for regulatory purposes. As such, R4 as written should be deleted from the Standards. Further,
the requirement to provide evidence of something that has not occurred (no vegetation encroachments of the
CCZ) is also impractical. General industry interpretation of R1.2.2 in version 1 of the Standards is that the
specific Clearance 2 distance is the precise boundary that is not to be encroached verses the broader area that is
ultimately mapped out as the conductor moves through "all rated electrical operating conditions". Only the
Clearance 2 distance value is a clear, precise number that can be accurately observed and measured in the field.
If there is a persistence to retain the CCZ concept as a requirement within the Standards, the second bullet option
above regarding the initiation of the imminent threat process upon discovery of a possible encroachment is the
preferred option. Since a potential encroachment into the CCZ is not a violation under this option, exact
determination of the CCZ boundary is no longer as essential. Rather, the focus is on triggering mitigation to
vegetation problems to prevent outages. However, as with question #11 above, there is still no practical way to
determine for regulatory purposes those "potential encroachment" situations that legitimately require initiation of
the imminent threat process from those "potential encroachment" situations that do not. Under this option the
utility is really motivated to initiate the imminent threat process to avoid an impending outage. As such, the
occurrence of an outage becomes the only clear, precise and observable means to determine a Standards
violation. A proposed alternative to ensure a level of reliability equal to or better than FAC-003-1 is to retain the
Clearance 2 requirement (without the imprecise "all rated electrical operating conditions" language) in combination
with the sustained outage requirements of R5, R6 and R7. If an additional margin of safety is determined to be
required, industry performance can be adjusted to become more proactive by increasing the minimum Clearance 2
distance to a value greater than the proposed version 2 Gallet equation (table 1) values. Thinking in terms of the
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CCZ concept, it is obvious that a larger Clearance 2 value translates into a larger CCZ envelope. A larger CCZ
envelope in turn triggers mitigation for possible CCZ encroachments sooner.
Response: The SDT thanks you for your comments and proposed alternatives. Significant changes to R4 have been made to the current draft of the
Standard based upon substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance
Distances”, and Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed
in real time.
Progress Energy Carolinas
Disagree
The definition of Critical Clearance Zone includes too many academic and theoretical elements. It is impossible to
provide evidence that vegetation did not encroach into the Critical Clearance Zone during TVMP cycles.
Furthermore, the operations staff performing periodic ground and aerial inspections would need to determine the
CCZ for each foot of transmission line to assure compliance with the standard as it is currently written. The CCZ
concept can neither be implemented or enforced as written. The CCZ refers to Ratings which is defined in the
Glossary of Terms as "The operational limits of a transmission system element under a set of specified
conditions." This definition is too broad to be a consistently enforceable term from one utility or region to the next.
As it is currently written, no exemption exists for vegetation falling from outside the Active Transmission Line Right
of Way into, or lodging in, the theoretical CCZ.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Southern California Edison
Company
September 8, 2009
Disagree
Q15: SCE does not agree that proposed R4 was written in the most effective way because it establishes a zero
tolerance enforcement policy. SCE agrees that a CCZ incursion should be addressed promptly, but we do not
agree that a CCZ incursion is equivalent to a vegetation-to-line contact, or that a CCZ incursion represents an
imminent threat of flash-over. As written, proposed R4 would require Transmission Owners to prove that a Critical
Clearance Zone incursion has not occurred. Short of a daily ground or aerial inspection of every applicable
transmission line, it is clearly impossible for a Transmission Owner to monitor their active Right of Way on a
24/7/365 basis to ensure a CCZ incursion will not or has not occurred. Bearing in mind that even the most robust
of Transmission VM programs may occasionally identify an anomalous condition (in or outside the active ROW)
that left untreated could lead to a flash-over or vegetation-to-line contact, the identification of such conditions
typically occur during scheduled aerial or ground patrols and addressed timely. Of the two alternatives offered,
SCE finds the first option (second bullet item) to be the most palatable. However, even that option leaves
significant doubt as to practical enforcement, because a Transmission Owner could still be found in violation of two
separate requirements (R4 and R5, R4 and R6 or R4 and R7) should a vegetation-to-line contact (resulting in a
sustained outage) occur. This situation amounts to regulatory double jeopardy. SCE believes that by any
reasonable legal or regulatory measure, requiring a Transmission Owner to prove that a CCZ incursion did not
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occur is impractical and virtually impossible to enforce in a fair and impartial manner. Further, SCE believes that
proposed R4 and corresponding M4 detracts from the purported goal of FAC-003-2 and should be removed.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
SERC OC Standards Review
Group
Disagree
The requirement, as written, compels the Transmission Operator to allocate precious resources to ensuring that a
vegetation encroachment NEVER will occur on any transmission line, regardless of that line's true importance to
maintaining electric transmission system reliability. All lines are not created equal; only those that are involved in
IROLs should be held to a zero tolerance standard. R4, if retained, should begin with "Subject to its legal rights,"
and insert the word "vegetation" between prevent and encroachment. Vegetation, which falls through the Critical
Clearance Zone or falls to lodge within the Critical Clearance Zone, should not be included as violations of the
Critical Clearance Zone. The concept of the Critical Clearance Zone is useful as a mental model to visualize
required vegetation management work. While this is a good conceptual tool to drive consistent terminology and
proper vegetation management practices, it remains theoretical in nature and impractical to measure on a span by
span basis. The complexity of determining an encroachment into the Critical Clearance Zone is overly
burdensome due to the need for survey accuracy measurements and engineering evaluations. In addition, this
complexity leads to questions about the ability to audit this requirement. These complexities introduce reliability
and audit issues when encroachments into this conceptual area are defined as violations. The SERC OCSRG
believes the Sustained Outage, as defined by other measures in this standard, should be the non-compliance
measure. We suggest that the Critical Clearance Zone concept be kept in the technical white paper and that all
references to the Critical Clearance Zone be removed from the body of the standard. R5, R6, and R7 ensure that
version 2 of the standard has reliability requirements equal to version 1; therefore R4 should be removed.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time. The
SDT, for clarity, did add the phrase “of Vegetation” as requested.
Western Utility Arborists
September 8, 2009
The new requirement in R4 stipulates that the Transmission Owner is in violation if an encroachment of the CCZ
occurs at any time. However, the CCZ changes with each foot of the transmission line from the insulator to the
mid-span, depending on loading, actual operating temperature, wind loading, ice loading, maximum design rating,
maximum operating load, and so on. Further, measure M4 requires that the Transmission Owner has evidence
demonstrating there were no vegetation encroachments into the CCZ. To provide evidence demonstrating there
were no vegetation encroachments into the CCZ would be an extremely onerous task and an expensive
requirement for the Utilities. The Western Utilities strongly supports the alternative to R4 as recommended in the
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Comment Form (#15), which is to require immediate removal of the vegetation or immediate implementation of the
imminent threat procedure upon discovery of a possible encroachment of the CCZ, thereby proactively preventing
an outage. This means a violation would occur only if the imminent threat process is not successfully
implemented. This alternative is essentially the same as R2. Therefore, the Western Utilities recommend removing
R4 from the standard entirely.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Florida Power & Light
Disagree
NERC standards require the Transmission Owner certify annually that they are in compliance to the standard for
the entire year. Since there is no way that a Transmission Owner could monitor every span of line every minute of
every day, Requirement R4 cannot be certified. A Transmission owner can only certify that at the time inspected
the system met the specification in the standard and that implementation of its Transmission Vegetation
Management Plan maintains these specifications. As stated earlier, the Critical Clearance Zone is difficult to
accurately identify in the field and without an outage it would be difficult for an auditing body to find and validate.
Requirements R4-R7 are reactive in nature. They are violations after the event has occurred or when the tree wire relationships are so close that emergency action is the only recourse for the Transmission Owner. The
standard needs to drive the Transmission Owner to identify and remove trees threatening the system in a
proactive fashion. A Transmission Owner should never be in violation for timely action to remove a threat to the
system.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Santee Cooper
Disagree
Recommend replacing the word "prevent" in R4 to "monitor". The first alternative that requires immediate removal
of vegetation or immediate implementation of the imminent threat procedure would be a Requirement that could
be measured. In addition, if an encroachment is found it needs to be eliminated and the first alternative specifies
immediate removal. If R4 is left as written, how can you provide evidence that there has been no encroachments
within the Critical Clearance Zone.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
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Southern Company
Agree?
Disagree
Question 15 Comment
The Critical Clearance Zone is a concept that adequately describes the salient functionality a Transmission Owner
must consider when determining acceptable clearances. However, the practicality of a requirement that forbids
even one encroachment in the Critical Clearance Zone presents a problem for not only the field personnel doing
the vegetation work, but also the Regional Entity that must enforce the requirement. This zone changes not only
from one span to another, it also changes at each location along each span. The reality is that the difference in
encroaching into the zone and not encroaching into the zone is a matter of a fractional inch. In order to prove noncompliance or to defend compliance at a particular site, all vegetation work would have to be postponed for survey
accuracy equipment and appropriately trained personnel to be brought to the site, measurements and calculation
to be made and consequently a determination rendered. This hardly seems worthwhile when the vegetation could
simply be cut, the threat removed and the vegetation work could continue on down the transmission line. As
stated in a previous comment, there could be many examples given of encroachments into this theoretical zone
that would neither threaten the transmission line conductor nor cause a reduction in the capacity of the
transmission line. This concept would be better suited to be a “trigger point” that, if found, would be incentive for
the Transmission Owner to either take immediate action or ensure future activities are appropriately scheduled
and implemented. This action may be as urgent as implementation of the immediate threat procedure or as nonurgent as making sure that the upcoming maintenance on that line is scheduled appropriately. If a sustained
outage occurs due to an encroachment, the outage should be the compliance measure.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
E.ON U.S.
Disagree
The concept of the Critical Clearance Zone is useful as a mental model to visualize required vegetation
management work. While this is a good conceptual tool to drive consistent terminology and proper vegetation
management practices, it remains theoretical in nature and impractical to measure on a span by span basis. The
complexity of determining an encroachment into the Critical Clearance Zone is overly burdensome due to the need
for survey accuracy measurements and engineering evaluations. In addition, this complexity leads to questions
about the ability to audit this requirement. These complexities introduce reliability and audit issues when
encroachments into this conceptual area are defined as violations. We believe the Sustained Outage, as defined
by other measures in this standard, should be the non-compliance measure. We suggest that the Critical
Clearance Zone concept be kept in the technical white paper and that all references to the Critical Clearance Zone
be removed from the body of the standard.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
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Bonneville Power Administration
Agree?
Disagree
Question 15 Comment
R4 states that the Transmission Owner is in violation of the Standard if the Critical Clearance Zone is encroached
upon. The CCZ, as defined by the Standard, changes along the transmission line from the insulator to mid-span,
depending on loading, actual operating temperature, wind and ice loading, maximum design rating and operating
load, etc. Also, the tandem, Measure M4, requires that the Transmission Owner has evidence demonstrating that
there has been no vegetation encoachments in the CCZ along its transmission system. In order to meet the letter
of the Standard, that is to provide evidence that no encroachments in the CCZ have occurred under all manner of
these fluid environmental and operating conditions, the Transmission Owner would have to employ the highest
level of modeling technology available, which would seem to be LiDAR technology. The standard should not be
written in such a manner so that it requires, by all intent and purpose, a Transmission Owner to acquire a
particular technology. BPA recommends that the Alternative represented by "the second bullet" above, be used
rather than R4 in its present state, or that R.4. be simply dropped and R1.4 modified to state that the imminent
threat procedures include immediate removal of encroachments into the Critical Clearance Zone. Also, the term
"immediate" implies instantaneous response. The use of another term is recommended, such as "as immediate
as human health and safety considerations allow, in order to prevent the possibility of flashover".
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Public Service Electric and Gas
Company
Disagree
An additional clarifying exception in the footnotes to R4 consisting of a tree that is located off of the transmission
owner's right of way falling into the CCZ should be added to the encroachment exceptions. Transmission owners
should not be found in violation of the standard for falling vegetation located off of the TO's property.
Response: The SDT thanks you for your comments. The SDT has added the exception you requested. Note that the exception applies to any falling
vegetation regardless of its location.
3. Brief encroachment into the Minimum Vegetation Clearance Distances listed in Attachment 1 resulting from falling vegetation.
FirstEnergy
September 8, 2009
Disagree
Providing evidence to prove that there were no encroachments of the CCZ is difficult at best. An occurrence of an
encroachment does not necessarily translate to an outage. The CCZ is dynamic and difficult to measure exactly
from span to span and day to day and is dependent on environmental and line conditions. The costs to comply
with this requirement as written are difficult to justify considering that reliability may not be improved at all.
FirstEnergy believes that the first alternative above should be used and is a more logical approach from both a
reliability and compliance standpoint. Furthermore, since the first alternative is already covered by the currently
proposed wording of R2, the only changes needed to the standard are to remove the proposed R4 and M4 and renumber the requirements.
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Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
MRO NERC Standards Review
Subcommittee
Disagree
The MRO believes R4 should be eliminated as vegetation contacts are covered in R5 and R6. A violation should
only occur with a vegetation contact. Assessing a violation and fine for a potential reduction in system reliability is
not correct. Actual contacts that trip a transmission element have some measurable impact on system reliability
even if it is slight.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Midwest ISO Stakeholders
Standards Collaborators
Disagree
The second bulleted alternative above is the best approach, but it should be improved by changing the imminent
threat trigger from "encroachment of the CCZ" to "encroachment within some observed, field distance that is a
multiple of the Gallet distances referenced in Table I". We have recommended changes to accomplish this in
Requirement R2 (see our response to Question #11 above), and R4 should simply be deleted. While the CCZ is
valuable to understanding the movement of conductors, it cannot be readily applied in the field. This field
application challenge is noted in the Technical Reference Document (pages 29 & 30).The way R4 is currently
stated, the Transmission Owner would be in violation of R4 for any CCZ encroachment not due to natural
disasters or human or animal activity. This would include a tree falling from outside the right of way corridor that
passes through the theoretical CCZ. Furthermore, Transmission Owners would be required to self-certify
compliance with R4, and we don't think there's any way to do that. Clearly the approach of assessing violations
for CCZ encroachment is unworkable. Likewise, the third alternative listed above is untenable. The tiered
approach could have a mitigating effect on violations, but it would require the same inspection effort and
postponement of vegetation management that makes the first alternative unworkable. Both the first and third
alternatives would require very significant additional expenditures for surveys and documentation in an impossible
attempt to certify compliance - money that would be better spent controlling vegetation.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time. The
proposed standard revision specifies the MVCD as a starting point and TO’s may apply multiples at their own discretion in order to achieve their TVMP
objectives and adhere to applicable safety standards.
SERC Compliance Staff
September 8, 2009
Disagree
The concept of the Critical Clearance Zone is useful as a mental model to visualize required vegetation
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management work. While this is a good conceptual tool to drive consistent terminology and proper vegetation
management practices, it is impractical to measure on a span by span basis. The complexity of determining an
encroachment into the Critical Clearance Zone is overly burdensome due to the need for survey accuracy
measurements and engineering evaluations. While it may be a technically sound approach to designate the
clearance zone to be tied to the conductor movement envelope as found in the NESC, this results in a bananashaped zone that is difficult to substantiate in the field by entity and compliance personnel. We suggest that the
Critical Clearance Zone concept be kept in the technical white paper and that all references to the Critical
Clearance Zone be removed from the body of the standard.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
ITC HOLDINGS
Disagree
First, it’s impossible to determine that no encroachments into the CCZ have occurred at any time and
determination of the CCZ from the field perspective is problematic. The standard is ambiguous and it seems like
clear cutting is the underlining message that is wanted. Determining an encroachment into the CCZ is problematic
due to the need for survey accuracy measurements and engineering evaluations. This will also lead to questions
about the ability to audit this requirement. The CCZ changes in size and shapes continuously in each and every
span and will be difficult to monitor. This would require field personnel to spend numerous hours estimating and
attempting to measure potential encroachments of the CCZ. The way R4 is currently written the Transmission
Owners would be required to self-certify compliance with R4, and which we don’t think this is possible. This will
lead to audit issues with more scrutinizing and potentially more penalties or fines. It is important to recognize that
the ultimate goal of the standard is to ensure that vegetation management is conducted in order to maintain an
adequate level of reliability, and not to precisely measure clearance zones. Alternative 2 would be the most logical
choice, depending on easement/legal rights, with changes that would eliminate any reference to a trigger point into
the encroachment zone of the CCZ to; measuring encroachment to a fix distance (Gallet tables) observed by field
personnel
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Tennessee Valley Authority
September 8, 2009
Disagree
TVA recommends that R4 be removed from this standard. Since this is a "zero tolerance" standard with substantial
penalties for controllable vegetation related outages there is an overwhelming incentive for the Transmission
Owner to proactively perform inspections, preventative maintenance, inpections and corrective maintenance to
prevent potential outages. As such, R4 does not add any value to improving reliability while causing numerous
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unresolvable problems.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Exelon
Disagree
The first bullet is unworkable in the real world. It will be virtually impossible to prove that "no encroachments of the
CCZ have occurred anywhere at any time during the compliance period". The effort to do this will not enhance
reliability. In fact, in may harm reliability by requiring unnecessary investments and O&M expenditures that could
be better spent on real reliability enhancements. Exelon agrees, subject to the development of a workable
definition of the CCZ, that the second bullet is the preferred approach.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Central Maine Power Company
Disagree
Central Maine Power Company suggests the second alternative to R4 as recommended above, which is to
require immediate removal of the vegetation or immediate implementation of the imminent threat procedure upon
discovery of a possible encroachment of the critical clearance zone, thus preventing an outage. This alternative is
similar to R2, therefore R4 may not be required.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
American Electric Power (AEP)
September 8, 2009
Disagree
AEP disagrees with the proposed requirement that violations be automatically declared if the CCZ is encroached.
Instead, AEP would support a standard utilizing the first alternative proffered in these comment questions. While
the CCZ is an interesting theoretical concept, it is not realistically feasible in the field to implement a concept that
depends on accurate measurements and calculations. Further, the proposed requirement offends common notions
of reliable maintenance methods, because it demands that forestry crews stop work if they see a potential
encroachment and that surveyors and engineers be brought in to take detailed measurements and perform
complex calculations to determine whether an encroachment has in fact occurred. The need for a reliable
transmission grid would be much better served by a standard utilizing the first alternative, in which no violation
occurs in the event of an encroachment as long as the TO implements its imminent threat procedure and removes
the vegetation. While seemingly technically appealing, the CCZ concept is fraught with implementation difficulties.
It should not be used as a Pass/Fail zero-tolerance decision point to determine whether a violation has occurred.
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After all, a zero-defect condition has not been achieved in many other aspects of electric utility operation. For
instance, the utility industry attempts every year to conduct its business without any workplace deaths, yet deaths
occur every year. Many millions of dollars are spent by North American utilities to promote safety programs and
safe work procedures, but some work-related vehicle accidents and personal injuries still occur. Also, utilities
aggressively investigate electric switching errors and have instituted rigorous dispatcher-training programs, but a
few switching errors still occur. For an industry in which billions of stems of vegetation must be managed, even a
high six-sigma level of quality would still result in a few cases annually of imperfectly managed vegetation. It is
unreasonable to expect zero-tolerance perfection with the CCZ concept. Also, with the way R4 is worded, a tree
falling from outside the right of way would result in a violation if it passed through the CCZ, whether it resulted in
an outage or not. It is not appropriate to place a burden on the TO for such circumstances outside the TO's
control. As R4 is written, it appears that there is no way that a TO could certify at the end of the year that it has
maintained a CCZ free of encroachments, even if no outages occurred. AEP believes a more effective and
reliability-centered approach would be one where TOs are expected to implement their imminent threat procedure
if vegetation is encroaching upon the Gallet equation distance. If TOs act accordingly and remove the vegetation
without incurring an outage, then they would not be in violation. However, if the TOs knew of vegetation
encroaching upon the Gallet equation distance but failed to implement their imminent threat process, they would
be in violation and be obliged to report the event.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Platte River Power Authority
Disagree
This requirement should be removed completely. It is too stringent and it is impossible to prove compliance
through documentation. Encroachemnt of Clearance 2 (or CCZ) should be addressed in the imminent threat
procedure.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
City of Tallahassee
September 8, 2009
Disagree
VEHEMENTLY DISAGREE! The purpose of the standard is to prevent vegetation related outages. A violation
should occur if an outage occurs. As written, R4 and M4 would be impossible to prove or disprove. It is not like
we can get up there with a tape measure and measure it. R2 requires action if the CCZ is "approached". This is
undefined and subject to a myriad of interpretations. Evidence is hard enough to obtain to the satisfaction of the
Compliance Monitor. To require sufficient evidence to prove that something didn't occur is a tremendous burden
and is not a wise expenditure of vegetation management dollars. Let us spend the money on trimming and not on
paperwork. As an alternative replace "encroachment within the Critical Clearance Zone" with "vegetation caused
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outages". This would allow the same exceptions and is much easier to prove or disprove with a breaker operation.
Although this would result in the cause of every breaker operation being tracked, it is a tangible evidence
requirement and leaves very little room for interpretation. The levels of fines have already shown that vegetation
management is a serious standard and we had better comply.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Northern Indiana Public Service
Company
Disagree
It will be impossible for a T.O. to provide "evidence" that no encroachments of the C.C.Z. occurred at any time
during the year. This approach will be a compliance nightmare and is unworkable. How does one prove this never
happens? You can't monitor every span of every line at all times. Obviously, whenever a T.O. has a preventable
outage, that should be a violation. To address the issue of preventing outages before they occur and penalizing
T.O.'s who don't take proper steps to prevent them, I prefer the approach of immediate removal of threatening
vegetation that encroaches within a "threat trigger/action threshold" clearance distance per the T.O.'s formal
imminent threat procedure. This "threat trigger/action threshold" clearance would be established by the T.O. and
be a specific requirement under a revised FAC-003.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Tampa Electric Company
Disagree
This is a good start. The Critical Clearance Zone (CCZ) is a very real and practical concept; however, it is not
transferable to field conditions. This could result in a "fill in the blank" standard relative to what the Critical
Clearance Zone will be in terms of distance. As I read this, it will be a sliding scale from insulator to mid span and
back for each designated line voltage. The max wind speed to be used and other assumptions behind the
determination of this zone may be as involved a Gallet's formula. This will lead to complications during operational
inspection and verification of these clearances.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Orange and Rockland Utilities
Inc.
September 8, 2009
Disagree
We believe that R4 is not the most effective way to achieve the purpose of the Standard. As previously stated the
CCZ and encroachments of it are generally not possible to identify in the field without taking precise
measurements. The CCZ changes in size and shape continuously throughout each and every span. In many
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cases the CCZ can be very large, and the position of the conductor with respect to encroaching vegetation within
the CCZ can be relatively far apart. Such cases would typically not be identified as encroachments of the CCZ by
visual inspections. Only those instances where the vegetation is significantly overgrown would be readily
identifiable. R4, as written presents a problem in terms of compliance, certification of compliance, and auditing
because precise measurements of every span are impractical and costly to perform. Certification of compliance
would require field personnel to spend valuable time estimating and attempting to measure potential
encroachments of the CCZ. R4 does not provide incentive for Transmission Owners to deploy modern technology
that is better able to identify encroachments of the CCZ with a reasonable amount of accuracy, such as ALS and
LIDAR which are described in the response to Question 11. In fact R4 might provide an incentive not to utilize this
technology because Transmission Owners who identify encroachments using ALS which would otherwise not
have been identified would be in violation of R4. Transmission Owners that choose to be less proactive often
would not identify such encroachments and would be at less risk of violating R4. The effect could be less frequent
use of ALS and other technology that may emerge. This would result in fewer problems being identified, a small
percentage of which may not be discovered until they result in a line trip. We believe that the best way to achieve
the purpose of this Standard is to encourage proactive behavior which prevents vegetation-related outages
throughout the entire industry. R4 does not achieve this in the most effective way. We recommend the following:
Eliminate encroachment of the CCZ as a violation of R4. Require Transmission Owners to immediately implement
the imminent threat process defined in R1.4 when they identify instances where vegetation has grown within a
specific distance as described in the response to Question 11 regarding R2. This would essentially combine R2
and R4.Require Transmission Owners to report to the Regional Entity any instances where the imminent threat
process was implemented due to a vegetation-related clearance encroachment. This would add a reporting
requirement for Transmission Owners. Require Regional Entities to perform additional audits of Transmission
Owners that exceed metrics for vegetation-related clearance encroachments. The metrics should be established in
the Standard based upon 1000 circuit miles of applicable lines. This would add an additional requirement for
Regional Entities. Modify R5, R6, and R7 to include preventing momentary outages as well as Sustained Outages.
We believe that this concept would result in a more rigorous standard because of the additional requirements, but
would focus the industry's attention in a more effective fashion. We believe it would result in fewer vegetationrelated interruptions and a higher level of reliability soon after implementation, and would therefore best support
the purpose of the Standard.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
The SDT very carefully and thoroughly examined the merits, disadvantages, ease and difficulties of assessing momentary outages as a violation, and
chose to address this issue with the language in R4.
September 8, 2009
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American Transmission
Company
Agree?
Disagree
Question 15 Comment
While the CCZ is valuable to understanding the movement of conductors, it cannot be readily applied in the field.
This field application challenge is noted in the Technical Reference Document (pages 29 & 30).The way R4 is
currently stated, the Transmission Owner would be in violation of R4 for any CCZ encroachment not due to natural
disasters or human or animal activity. This would include a tree falling from outside the right of way corridor that
passes through the theoretical CCZ. Furthermore, Transmission Owners would be required to self-certify
compliance with R4, and ATC does not think there is a practical way to do that. Clearly, the approach of
assessing violations for CCZ encroachment is unworkable. ATC believes that R4 should be deleted.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Xcel Energy
Disagree
The way this requirement is written may require a utility to prove a negative. In other words, prove that we did not
have trees encroaching into the CCZ at any time. This is impossible to prove. We propose the following
language: ?The TO shall not have a encroachment within the CCZ which was not dealt with by utilizing the
imminent threat procedure before experiencing a Sustained Outage, with the following exceptions 1)
Encroachment of the CCZ that result for natural disasters 2) Encroachment of the CCZ that result from human or
animal activity."
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Ameren
Disagree
September 8, 2009
The second bulleted alternative above is the best approach, but it should be improved by changing the imminent
threat trigger from "encroachment of the CCZ" to "encroachment within some observed, field distance that is
defined in the Plan. This would allow Transmission Owners to define for field personnel a CCZ that accomplishes
some multiple of the Gallet distances referenced in Table I" but is easy to determine and apply. We have
recommended changes to accomplish this in Requirement R2 (see our response to Question #11 above), and R4
should simply be deleted. While the CCZ is valuable to understanding the movement of conductors, it cannot be
readily applied in the field. This field application challenge is noted in the Technical Reference Document (pages
29 & 30).The way R4 is currently stated, the Transmission Owner would be in violation of R4 for any CCZ
encroachment not due to natural disasters or human or animal activity. This would include a tree falling from
outside the right of way corridor that passes through the theoretical CCZ. Furthermore, Transmission Owners
would be required to self-certify compliance with R4, and we don't think there's any way to do that. Clearly the
approach of assessing violations for CCZ encroachment is unworkable. Likewise, the third alternative listed above
is untenable. The tiered approach could have a mitigating effect on violations, but it would require the same
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inspection effort and postponement of vegetation management that makes the first alternative unworkable. Both
the first and third alternatives would require very significant additional expenditures for surveys and documentation
in an impossible attempt to certify compliance - money that would be better spent controlling vegetation.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Nebraska Public Power District
Disagree
NPPD disagree with an encroachment being a violation. A lot of time would need to be spent to determine if an
encroachment occurred and in a self regulating environment, reporting would be minimal if any. The Transmission
Owner would be in violation for any non natural event. Even a tree falling into the ROW passing through CCZ
would be in violation of R4. Difficult at best to enforce. We need to spend time keeping the ROW cleared and less
time inspecting for possible encroachments.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Long Island power Authority
Disagree
The Standard is about preventing outages and having an effective program. An effective program should allow for
the identification of a threat and the removal of the threat prior to a vegetation caused outage. I prefer alternative
2. If a vegetation caused outage should occur or if the Regional Entity determines a violation occurred based on a
compliance investigation then the entity is in violation of this requirement.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
USDA Forest Service,
Southwestern Region, Regional
Office for AZ and NM
Disagree
The wording appears too strong. Who can predict the unforeseen circumstances that inevitably arise. If the
standards require the reporting of encroachments, the ensuing report can help determine if the Transmission
Owner did everything reasonable to avoid the problem. It seems like the standard should be written to require the
Transmission Owner to do everything reasonable to avoid the problem. A judgment call would still be needed to
evaluate the performance.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
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Manitoba Hydro
Agree?
Disagree
Question 15 Comment
Manitoba Hydro asserts that the reliability of the system is measured by outage, not by the possibility of an outage,
and therefore if the overall vegetation management system (plan-patrol-discover-mitigate) is effective in preventing
an outage, then the reliability of the system has been maintained, and the intent of the reliability standard
achieved. Therefore, we propose that the second bullet above is the preferred alternative, and that R2 and R4 be
combined as the violation of R4 would then imply a violation of R2.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Consumers Energy Company
Disagree
The CCZ does not provide adequate clearance and the imminent threat procedure if successfully implemented
only works IF YOU KNOW ABOUT THE VEGETATION THAT THREATENS THE CCZ which cannot be ensured
with yearly inspections. Consumers Energy believes that the Clearance 2 distances in FAC-003-1 provide more
reliability than the CCZ proposed in this draft or any of the alternatives disused above.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Pacific Gas & Electric Co.
Disagree
PG&E believes a "minimum clearance distance" or "do not encroach zone" is a critical element of this standard
and necessary to achieve the stated purpose of preventing vegetation caused outages. Preventing vegetation
encroachments will prevent outages. However, PG&E disagrees with using the CCZ as a minimum clearance
requirement because it is ambiguous and subject to wide variations and interpretation. CCZ is a good concept to
aid in understanding movement of conductors but is a theoretical calculation and would be very difficult if not
impossible to enforce. PG&E suggests using a clearly defined distance such as Gallet equation plus a safety
margin to assure there is no chance of spark over. Two times Gallet would be a reasonable clearance
requirement to assure a spark over does not occur and eliminate the ambiguity of the CCZ as the "do not
encroach zone".
Response: The SDT thanks you for your comments. The SDT discussed the Gallet plus alternative suggested by PG&E. Due to the tremendous variation
of design standards, the team decided that the decision as to how much a margin for error to use belonged to the individual TO. The essential changes
are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and Transmission Owners are required to prevent encroachment of
vegetation into “Minimum Vegetation Clearance Distances” as observed in real time. The threat of a violation is believed sufficient to motivate a
Transmission Owner to maintain a larger clearance.
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NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Agree?
Disagree
Question 15 Comment
The new requirement in R4 stipulates that the Transmission Owner is in violation if an encroachment of the CCZ
occurs at any time. However, the CCZ changes with each foot of the transmission line from the insulator to the
mid-span, depending on loading, actual operating temperature, wind loading, ice loading, maximum design rating,
maximum operating load, and so on. Further, Measure M4 requires that the Transmission Owner has evidence
demonstrating there were no vegetation encroachments into the CCZ. These requirements may result in having to
LIDAR the lines annually, to prove that trees have not encroached upon the CCZ. This would be an extremely
onerous and expensive requirement for utilities. NV Energy strongly supports the alternative to R4 as
recommended in the Comment Form (#15), which is to require immediate removal of the vegetation or immediate
implementation of the imminent threat procedure upon discovery of a possible encroachment of the CCZ, thereby
proactively preventing an outage. This means a violation would occur only if the imminent threat process is not
successfully implemented. This alternative is essentially the same as R2. Therefore, we recommend removing R4
from the standard entirely.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
San Diego Gas & Electric
Disagree
The new requirement in R4 stipulates that the Transmission Owner is in violation if an encroachment of the Critical
Clearance Zone (CCZ) occurs at any time. However, the CCZ changes with each foot of the transmission line
from the insulator to the mid-span, depending on loading, actual operating temperature, wind loading, ice loading,
maximum design rating, maximum operating load, and so on. Further, Measure M4 requires that the
Transmission Owner have evidence demonstrating there were no vegetation encroachments into the CCZ. These
requirements may result in having to LIDAR the lines annually to prove that trees have not encroached upon the
CCZ. This would be an extremely oerous and expensive requirement for utilities. We strongly support the
alternative to R4 as recommended in the Comment Form, which is wto require immediate removal of the
vegetation or immediate implementation of the imminent threat procedure upon discovery of a possible
encroachment of the CCZ, thereby proactively preventing an outage. This means a violation would occur only if
the imminent threat process is not successfully implemented. This alternative is essentially the same as R2.
Therefore, we recommend removing R4 from the standard entirely.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Hydro One Networks Inc.
September 8, 2009
Disagree
A statement is needed that this requirement applies to the active right of way. Outside of the active right of way
there is no guarantee that this can be achieved. As noted in the question above, it may be very difficult with the
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first alternative to provide adequate evidence that no encroachment had occurred over the compliance period, as
the situation is very difficult to assess along each span to the accuracies (1/100 of a foot) spelled out for the CCZ.
It may be more meaningful that the Transmission Owners be able to demonstrate processes, methodologies and
actions that can support that vegetation has not entered the CCZ. Another alternative for R4 could then be: Each
Transmission Owner shall demonstrate that adequate actions and processes are in place to prevent vegetation
from entering the CCZ. The effectiveness of the process can then be evaluated based on methods used for field
assessment and performance, i.e., outages and imminent threat reporting. It appears that the second alternative
noted above can be combined with R2. It is not clear why there needs to be a separate requirement. Hydro One
is not in favour of alternative 3, as this would create added administration with a situation that will be difficult to
prove to the accuracy required. LIDAR may be the only means available to provide evidence of a quality needed
to produce meaningful statistics, and in many cases this may not be the most efficient use of the limited funding
that is available.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Edison Electric Institute
Disagree
Encroachment without a Sustained Outage should not be construed as a violation. The proposed R4 requirement
should be removed. EEI strongly believes that this requirement, if approved, is unenforceable. The alternative, to
require implementation of the imminent threat procedure, should be considered as a practical approach. In
particular, this concern applies to a requirement to prove that no encroachments have existed. This will require
extensive work by field personnel, who will be required to make subjective judgments. In addition, determining
actual clearance zones in the field would require a span-by-span analysis to be conducted with the rigor of survey
level measurements. Calculations made to determine the clearance zones are based on undefined terms and
subject to wide variation. Enforcement authorities will be required to make interpretations. EEI believes that the
costs of conducting such work will not deliver sufficient benefit to warrant the requirement. Ultimately, there is no
basis for determining whether the theoretical clearance zones included in the proposed standard will increase, or
even maintain, an adequate level of reliability as provided by the existing standard.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Consolidated Edison Company
of New York (CECONY)
September 8, 2009
Disagree
CECONY disagrees with R4 as currently written. As mentioned in the response to Question 15, performing a field
measurement of the CCZ and a field measurement of the vegetation encroaching into the CCZ are complicated,
time-consuming efforts. As the CCZ changes along the conductor, so too may the Active ROW dimensions, the
vegetation clearances at multiple points, and elevation levels to name a few. Certifying compliance that no
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encroachments have occurred would be very difficult for auditors and field inspectors. Modern laser technology
would have to be deployed to take these measurements and CECONY is concerned that, if an encroachment of
the CCZ constitutes a violation, utilities would not consider investing in this technology knowing that multiple
violations could potentially be found within a single span. Enhanced reliability is achieved when utilities invest in
the best available technology and perform proactive inspections on their systems but, as written, R4 would not
effectively motivate a utility to follow through with these initiatives.
We recommend that the term 'momentary outage' or the phrase 'all outages' be used in R5, R6, and R7 instead of
'Sustained Outages' to avoid confusion throughout the industry. Momentary outages identify a potential failure of
the utility's vegetation management program and stating it directly in the Standard clearly sends the message to
utilities that all vegetation outages are unacceptable. In summary, we do not agree that encroachments are
violations but we do recommend that when a utility identifies vegetation-related imminent threats and takes
immediate action, they report this to their Reliability Coordinator. The Reliability Coordinator (RC) could then
identify the utilities that have had multiple issues or have exceeded acceptable pre-established reporting limits
which, in turn, would help the RC prioritize auditing efforts. This, in our opinion, would enhance reliability more
effectively.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
The SDT very carefully and thoroughly examined the merits, disadvantages, ease and difficulties of assessing momentary outages as a violation. The
result of that effort led to the more precise and field observable aspects of R4. It should be noted that by their very nature the exact causes of “momentary
outages” are very challenging to determine and will vary widely from utility to utility. The SDT did not find that such variability was appropriate for a
reliability standard, and chose to address this issue with the language in R4.
Arizona Public Service Company Disagree
September 8, 2009
APS agrees with alternative one. The new requirement in R4 stipulates that the Transmission Owner is in violation
if an encroachment of the CCZ occurs at any time. However, the CCZ changes with each foot of the transmission
line from the insulator to the mid-span, depending on loading, actual operating temperature, wind loading, ice
loading, maximum design rating, maximum operating load, and so on. Further, Measure M4 requires that the
Transmission Owner has evidence demonstrating there were no vegetation encroachments into the CCZ. These
requirements may result in having to LIDAR the lines annually, to prove that trees have not encroached upon the
CCZ. This would be an extremely onerous and expensive requirement for utilities. APS strongly supports the
alternative to R4 as recommended in the Comment Form (#15), which is to require immediate removal of the
vegetation or immediate implementation of the imminent threat procedure upon discovery of a possible
encroachment of the CCZ, thereby proactively preventing an outage. This means a violation would occur only if
the imminent threat process is not successfully implemented. This alternative is essentially the same as R2.
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Therefore, APS recommends removing R4 from the standard entirely.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Baltimore Gas & Electric
Company
Disagree
One concern with the proposed wording is that the verbiage seems to provide a loophole that will count any fallen
tree, or tree with the potential to fall from inside or outside of the R/W (that doesn't meet the criteria in footnotes 4
& 5) that passes or could pass through the CCZ, and that may or may not cause an outage, would qualify as a
violation in the std. There is no other language that I can detect in the std. that counters this point. Determination
of whether or not a fallen tree, or tree with the potential to fall would qualify would be predicated upon height
measurements of the fallen or standing tree(s) relative to the CCZ at max. engineered sag. An alternative wording
suggestion is: "Each Transmission Owner shall prevent encroachment within the Critical Clearance Zone of it's
applicable lines associated with trees that meet the criteria for grow-ins from on or off the Active right-of-way. Fallins from inside or outside of the active right-of-way are not applicable to this sub-requirement." If the occurrence is
a violation, reporting of the incident will be an ethical issue and rely on the honesty of the inspector or whomever
finds the problem. If it's not a violation, it will be more likely that the incident will be reported and can be treated as
"Near Miss' reports are with respect to safety incidents - they provide valuable input to help forestall future more
serious incidents. Consequently, I recommend that no violation occur as long as the 'Imminent Threat Procedure'
is implemented. Further, if there is no violation associated with Imminent Threat Procedure implementation, I
would suggest that falling or standing trees originating from within the active right-of-way that encroached or could
encroach in the CCZ be added to the requirement to enhance the 'Near Miss' data pool.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Duke Energy Corporation
September 8, 2009
Disagree
The second bulleted alternative above is the best approach, but Duke believes it should be improved by changing
the imminent threat trigger from "encroachment of the CCZ" to "encroachment within some observed, field
distance that is a multiple of the Gallet distances referenced in Table I". We have recommended changes to
accomplish this in Requirement R2 (see our response to Question #11 above), and R4 should simply be deleted.
While the CCZ is valuable to understanding the movement of conductors, it cannot be readily applied in the field.
This field application challenge is noted in the Technical Reference Document (pages 29 & 30).The way R4 is
currently stated, the Transmission Owner would be in violation of R4 for any CCZ encroachment not due to natural
disasters or human or animal activity. This would include a tree falling from outside the right of way corridor that
passes through the theoretical CCZ. Furthermore, Transmission Owners would be required to self-certify
compliance with R4. The technological requirements for accurately certifying compliance would be impossible to
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administer. Clearly the approach of assessing violations for CCZ encroachment is unworkable. Likewise, the third
alternative listed above is untenable. The tiered approach could have a mitigating effect on violations, but it would
require the same inspection effort and postponement of vegetation management that makes the first alternative
unworkable. Both the first and third alternatives would require very significant additional expenditures for surveys
and documentation in an impossible attempt to certify compliance - money that would be better spent controlling
vegetation.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
CenterPoint Energy
Disagree
It is not reasonable to expect Transmission Owners to devote resources, both human and financial, to prove that
vegetation never encroached into the Critical Clearance Zone, anytime-anywhere. R4 and M4 should be
deleted.R2 and M2 are sufficient in ensuring a level of reliability equal to or better than FAC-003-1 with some
minor wording changes to adopt similar wording of the alternative to R4 that was considered by the drafting team
that includes "immediate implementation of the imminent threat procedure" for imminent threats of a vegetation
related Sustained Outage in lieu of a nebulous "encroachment of the Critical Clearance Zone". According to the
Technical Reference, it is "nearly impossible to field correlate and accurately 'superimpose' the Critical Clearance
Zone around the conductor". It not likely that the Transmission Owner will know when the Critical Clearance Zone
is approached through field observation. The previous Clearance 2 provided for a specific radial clearance from
the conductor that was much easier to observe. (See comments to Q3 above.)
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Entergy Services
Disagree
1. Entergy believes that outages caused by vegetation are the most reasonable and objective measures for a
violation which is not consistent with the proposed R4. See additional comments in section 16 related to R5, 6,
and 7.
2. If R4 remains, Entergy proposes that the most reasonable approach to this requirement is a variation of the
second bulleted option. This variation would include wording clarifying that only known encroachments of the
Critical Clearance Zone would be considered violations. Entergy is willing to include failures to enact the imminent
threat process (which is really a violation of R2) and also known vegetation inside the Critical Clearance Zone.
This variation should continue to include the exceptions for natural disaster and human activities.
3. Determining objective, quantifiable encroachments into the Critical Clearance Zone is very challenging in field
operations because such determination may require a degree of accuracy only obtainable using survey equipment
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or other sophisticated, costly measuring devices.
4. Entergy is concerned about the challenges of uniform audit ability due to noted uncertainties and the statement
of absolute criteria that have to be shown in the negative. If the first bullet option is approved for R4, Entergy
suggests the sentence “Evidence will be required to prove that no encroachments of the Critical Clearance Zone
have occurred anywhere at the any time during the annual compliance period” be deleted. It is very difficult in
regulatory terms to attest that no vegetation has ever crossed the Critical Clearance Zone during the time period
being reviewed given the wide range of potential conditions that may not have been detected or even been
detectable unless the conditions afforded direct observation. Too many assumptions would have to be made for
an entity to self certify to this requirement. If R4 is implemented as stated, those assumptions need to be stated
and clarified.
5. If any version of R4 is approved, Entergy suggests that the standard include an exception for trees falling from
off the right of way and encroaching the Critical Clearance Zone. For example, a tree that falls from off the right of
way. During the fall towards the conductor, the tree could possibly break the Critical Clearance Zone without
causing an outage or even a threat of an outage yet still be a violation of the proposed standard.
6. If the second bulleted item is approved, it should be altered to read “a violation would have occurred only if no
vegetation imminent threat process was initiated.”
7. Entergy does not feel the third bulleted item is adequately defined to use as a requirement in the standard at
this time.
8. Conditions for blow-out, in the development of the Critical Clearance Zone, need to be defined in the standard.
Their inclusions, in the white paper only, are not appropriate, as well.
Response: The SDT thanks you for your comments and suggested alternatives. Significant changes to R4 have been made to the current draft of the
Standard based upon substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance
Distances”, and Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed
in real time. The SDT addressed your item 5 in subpart 3 in R4. This exception would apply to any falling vegetation outside the right of way or inside the
right of way.
Pepco Holdings, Inc
Disagree
As discussed in our response to Q11, the concept of encroachment into the Critical Clearance Zone is flawed. It is
enforceable almost exclusively through self reports. R5, R6 and R7 provide all incentives for the TO to follow its
inspection and maintenance plans, and R2, if properly written to remove references to the Critical Clearance Zone
provides additional incentives. R4 is not needed and should be deleted. PHI is puzzled where this concept came
from. Nowhere in Order 693 is this concept discussed.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
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substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time. The
concept of the CCZ was originally intended to provide an area that could be used to produce a metric for less than “zero tolerance” however that did not
materialize.
JEA
Disagree
As written, demonstration of compliance may not be feasible and would certainly be prohibitively expensive,
consuming resources better spent managing vegetation. In general, putting entities in the position of proving
something didn't occur is exptremely difficult and burdensome, without really aiding reliability. If the incident was
significant, the region would know about it, and investigations can be pursued, if warranted. The first alternative
requiring implementation of the imminent threat procedure is a better choice.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Salt River Project
Disagree
Disagree with R4 as it is written. The new requirement in R4 stipulates that the Transmission Owner is in violation
if an encroachment of the Critical Clearance Zone occurs at any time. However, the Critical Clearance Zone
changes with each foot of the transmission line from the insulator to the mid-span, depending on loading, actual
operating temperature, wind loading, ice loading, maximum design rating, maximum operating load, and so on.
See additional comments in Comment #18 below. Furthermore, Measure M4 requires that the Transmission
Owner has evidence demonstrating there were no vegetation encroachments into the Critical Clearance Zone. To
provide evidence demonstrating there were no vegetation encroachments into the Critical Clearance Zone would
be an extremely onerous task and an expensive requirement for the utilities. We strongly support changing this to
the 1st alternative written in Comment #15 "One alternative to R4 required immediate removal of the vegetation or
immediate implementation of the immenent threat procedure upon discovery of a possible encroachment of the
Critical Clearance Zone, thereby proactively preventing an outage. A violation would have occurred only if the
immenent threat process was not successfully implemented." This alternative is essentially the same as R2,
therefore, we recommend removing R4 from the standard entirely.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Northeast Utilities
September 8, 2009
Disagree
First - the determination of the CCZ is highly problematic in the field. Second - it is impossible for any utility to
certify that no encroachments have occurred at any time unless a utility has completely removed all potentially
interferring vegetation on all areas of their transmission system. If the standard is to clear-cut and maintain a tree
free right of way, the standard should say so. To determine if vegetation may have violated the CCZ the inspector
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must know at the time of the inspection the ambient temperature, the wind speed, the loading of the line and the
actual distances between the vegetation and conductors. Then, the information must be compared to possible
extreme operating levels of the line under all conditions to know if the vegetation may violate the CCZ. As stated it is improbable that this could accurately be performed in the field as the data changes within each segment of a
span's length. The first alternative provides the most effective means of addressing encroachment of the CCZ having an encroachment is not a violation - knowing there is an encroachment and not correcting the problem
would be a violation. Implementing the imminent threat procedure and correcting the problem is a more effective
approach. Having a zero tolerance for encroachments of the CCZ under all situations and operating conditions
would sub-optimize the use of resources. No actual event may have occurred on the system, yet the utilities will
be in violation just for a possible or potential problem that even under extreme operating conditions may not
actually occur. It would be best if the violations were limited to "known encroachments" (not "possible
encroachments") such as would occur if a line were to trip due to vegetation contact, or if there is evidence of any
burns. If no action was taken on known encroachments to correct the problem (such as implementation of the
imminent threat procedure) then a violation will have occurred. It is doubtful that any utility will be able to certify
that at no time has vegetation encroached into the CCZ. Utilities will have to spend an untold amount of resources
to verify that there have not been any encroachments during a compliance period - instead of using these
resources more effectively in taking proactive measures to manage and control encroaching vegetation. As
written, any encroachment into the CCZ is considered a violation of FAC-003-2 (R4). There are exceptions
provided for encroachments due to natural disasters and human or animal activity. There is no exception for
encroachments due to the failure of a tree(s) outside of the active transmission line ROW. Based on R4, a trip and
reclose of a transmission line (no outage) is a violation even if the tree is outside of the active right-of-way;
whereas per R6 and R7, a line outage would not be a violation if the tree was outside of the active right-of-way.
As written - this is not clear - there should be exceptions to allow for trees falling into the CCZ (and into the active
transmission line right-of-way) from outside the limits of the active transmission line right-of-way. Also - how are
violations of the CCZ requirement to be reported - there is no provision for the reporting process and requirements
(specifics on the type of violation). Will this be addressed in the Compliance Section yet to be added?
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Hydro-Quebec Transenergie
(HQT)
September 8, 2009
Disagree
The purpose of the standard is "To improve the reliability of the Bulk Electric System by preventing vegetation
related outages that could lead to Cascading". We believe that R4 is not the most effective way to achieve this
purpose because it does not provide incentive for Transmission Owners to take advantage of modern technology,
such as aerial laser survey (ALS) using Light Detection and Ranging technology (LIDAR), that is capable of
accurately identifying vegetation which is approaching the CCZ or has encroached into it. In fact R4 provides an
incentive not to utilize this technology because Transmission Owners who identify encroachments would be in
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violation of R4 for each identified encroachment. On the other hand, Transmission Owners who choose to be less
proactive often would not identify such encroachments because the CCZ and encroachments of it are generally
not easy to determine without taking precise measurements. Unless the line is heavily loaded or the vegetation is
significantly overgrown, encroachments of the CCZ would not be readily noticed. In most cases these
Transmission Owners would simply remove or cut back incompatible vegetation without taking measurements.
The threat to the line would have been eliminated with no encroachment having been identified.R4 presents a
dilemma for Transmission Owners that are considering making the significant investment in ALS technology. While
the technology would allow them to identify any potential grow-in or fall-in conditions, it would also expose them to
the risk of identifying violations of R4, that would otherwise not have been identified. Violation Risk Factors
(VRFs), Violation Severity Levels (VSLs), and Time Horizons are not included in this Draft, but after making a
significant investment in ALS, Transmission Owners could be faced with significant additional cost in terms of
NERC penalties. In addition, even if the penalties were relatively low they would be exposing themselves to
violations that less proactive Transmission Owners would not be exposed to. In our view R4 as written would, in
some cases, have the opposite effect of what is intended because the business case for using ALS is more
difficult to make. This will result in less use of ALS and other emerging technology that is likely to be developed.
This would result in fewer problems being identified, a small percentage of which will not be discovered until they
result in a line trip. Still we believe that the concept of the CCZ is a good one and recommend that R4 be changed
so that Transmission Owners are provided with an incentive to invest in the best technology available in order to
ensure the highest level of reliability. The opportunity exists to develop the standard in a manner that encourages
the industry to take advantage of new technology and manage vegetation in a very proactive way. We recommend
that R4 be changed as follows: Modify R4 to require Transmission Owners to immediately implement the imminent
threat process defined in R1.4 when they identify instances where the CCZ is approached or encroached upon.
Failure to do so would be a violation of R4. Eliminate encroachment of the CCZ as a violation of R4. This would
eliminate R2 and incorporate implementation of the imminent threat process into R4.Require Transmission
Owners to report to the Regional Entity on a quarterly basis any instances where the imminent threat process was
implemented due to an encroachment of the CCZ. This would add a reporting requirement for Transmission
Operators. Require Transmission Owners to report to the Regional Entity on a quarterly basis any instances where
either a momentary or sustained outage was caused by grow-ins, Active Transmission Line Right of Way blow-ins,
or Active Transmission Line Right-of-Way fall-ins. This would add three additional reporting requirements for
Transmission Operators. Require Regional Entities to perform additional audits of Transmission Owners that
exceed metrics for violations of the CCZ. The metrics would be established in this Standard based upon 100
circuit miles of applicable lines. This would add an additional requirement for Regional Entities. This concept would
result in a more rigorous standard than FAC-003-01 because of the additional reporting and auditing requirements.
It would drive proactive behavior throughout the industry and provide a significant incentive for Transmisison
Owners to invest in new technology such as ALS that is capable of accurately identifying vegetation that has
approached or encroached upon the CCZ. We believe that this change would result in the identification of more
incipient vegetation-related problems and fewer vegetation-related outages as soon as it was implemented and
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would best support the purpose of the Standard.
Response: The SDT thanks you for your comments and suggestions. The reporting and documenting concept that you suggest has been incorporated in
part in R2. Significant changes to R4 have been made to the current draft of the Standard based upon substantive industry comment. The essential
changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and Transmission Owners are required to prevent
encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Buckeye Power, Inc.
Disagree
Proving vegetation is not in a clearance zone will be difficult without having third-party verification.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Great River Energy
Disagree
GRE supports the elimination of R4, as vegetation contacts are covered in R5 and R6. A violation should only
occur with a vegetation contact. Assessing a violation and fine for a potential reduction in system reliability is not
correct. Actual contacts that trip a transmission element have some measurable impact on system reliability even
if it is slight. In the event that the SDT chooses not to eliminate R4, GRE would also support the alternative
language that is shown under the second bullet.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
WECC
Agree
Yes, R4 as written provides clear guidance to TOs on the minimum radial distance, dependant on line voltage that
vegetation is allowed to approach energized conductors. These industry standardized distances will ensure a level
of reliability equal to or better than FAC-003-1.
Response: The SDT thanks for your comments. Please see the summary consideration for this question – based on other comments, the SDT made
significant revisions to Requirement R4. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
National Grid
Agree
National Grid agrees that there should be no encroachments into the CCZ. However, encroachments in the CCZ
should NOT be considered a violation. Violations should only be for sustained transmission outages.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
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Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Northern California Power
Agency (NCPA)
Agree
WECC Reliability Coordination
Agree
Response: The SDT thanks you for your positive feedback. Most commenters disagreed with R4. Changes to R4 have been made to the current draft of
the Standard based upon substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance
Distances”, and Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed
in real time.
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16. Requirements R5, R6, and R7 define that Sustained Outages due to vegetation growing into, blowing together with,
and falling into transmission lines are violations (subject to certain exemptions). Therefore, all such outages must be
reported as violations of the standard. Do you agree with this change? If not, please explain.
Summary Consideration: Seventy two percent of the respondents agreed with the changes. Multiple commenters made the
following points: Questionable cost benefit, not all lines are equal, complicated and burdensome to know precisely where edge
of ROW is, the standard should read minimize outages and not prevent them. The majority of the team did not agree there
was sufficient argument to support making changes to the requirements based on the comments.
Several commenters pointed out that debris that has been detached from the tree and blown into the conductor and trees from
outside the ROW should be exempt. The team adjusted the standard to accommodate debris and falling from outside the
ROW.
Organization
Western Utility Arborists
Agree?
Question 16 Comment
The Western Utilities strongly recommend that the requirement under R7 be changed from “shall prevent
sustained outages” to “shall minimize sustained outages due to vegetation falling into a conductor.” We note
that the word “minimize” was present in earlier drafts of the document. We are concerned about the
requirement for utilities to prevent sustained outages from vegetation falling into the conductor from within the
active transmission ROW. It is operationally almost impossible to know precisely where the edge of the ROW
is in all situations under all conditions. This could lead to an incident where utilities are charged unreasonably?
for example, for an outage from a tree that was one foot within the active ROW line. We should not be held
liable when reasonable due diligence is practiced. Further, it is not economically feasible for utilities to survey
every ROW in the U.S. and Canada to determine precise clearance zones.
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT. The SDT believes that the Transmission Owner holds responsibility for knowing the location of the edges of its active rights of
way and whether a rooted tree is within or outside the active right of way.
BCTC
BCTC strongly recommends that the requirement under R7 be changed from “shall prevent sustained
outages” to “shall minimize sustained outages due to vegetation falling into a conductor.” We note that the
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word “minimize” was present in earlier drafts of the document.
BCTC is concerned about the requirement for utilities to prevent sustained outages from vegetation falling into
the conductor from within the active transmission ROW BCTC’s operating area covers rugged and remote
terrain, and many areas have accessibility issues. It is operationally almost impossible to know precisely
where the edge of the ROW is in all situations under all conditions. Further, it is not economically feasible to
accurately survey and marked on the ground the absolute width of all ROW in the province. Therefore, we are
concerned about the requirement for utilities to prevent sustained outages from vegetation falling into the
conductor from within the active transmission ROW. This could lead to an incident where BCTC is charged
unreasonably – for example, for an outage from a tree that was one foot within the active ROW line. We
should not be held liable when reasonable due diligence is practiced.
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT. The SDT believes that the Transmission Owner holds responsibility for knowing the location of the edges of its active rights of
way and whether a rooted tree is within or outside the active right of way.
Kansas City Power & Light
Disagree
Exceptions should include flying debris including vegetation.
Response: Thank you for your comment. Your suggestion has been incorporated.
Associated Electric Cooperative
Inc.
Disagree
Requirements 5, 6 and 7, as written, compel the Transmission Owner to allocate precious resources to
ensuring a vegetation related outage will NEVER occur on any applicable transmission line, regardless of the
line's true importance to maintaining electric transmission system reliability. All lines are not created equal;
only those which are an IROL or contribute to IROLs should be held to a zero tolerance standard.
Response: Thank you for your comments. FERC Order 693 affirmed that the Standard shall apply to all transmission lines operating above 200kV as
well as to designated sub-200kV lines. The Standard was prepared in accordance with FERC Order 693.
NPCC
Disagree
NPCC participating members request clarification if violations of R5, R6, and R7 result in outages that must be
reported.
Response: The SDT appreciates your response. Under NERC’s Compliance Guidelines, any violation of a reliability standard requirement must be selfreported; thus, a violation of Requirement R5, R6 or R7 must result in a report from the Transmission Owner.
SERC OC Standards Review
September 8, 2009
Disagree
R5, R6 and R7 should begin with "Subject to its legal rights,”. The requirements, as written, compel the
Transmission Operator to allocate precious resources to ensuring that a vegetation outage NEVER will occur
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Question 16 Comment
on any transmission line, regardless of that line's true importance to maintaining electric transmission system
reliability. All lines are not created equal; only those that are involved in IROLs should be held to a zero
tolerance standard. R5, R6, and R7 ensure that version 2 of the standard has reliability requirements equal to
version 1; therefore R4 should be removed.
Response: Thank you for your comments.
The SDT certainly agrees that all actions taken by a Transmission Owner must be within its legal rights, but believes that inclusion of “Subject to its legal
rights” will tend to unnecessarily limit legitimate actions that a Transmission Owner must take to maintain reliability.
FERC Order 693 affirmed that the Standard shall apply to all transmission lines operating above 200kV as well as to designated sub-200kV lines. The
Standard was prepared in consideration of the directives and recommendations contained in FERC Order 693.
Florida Power & Light
Disagree
As currently written, Requirements R5, R6 and R7 demand perfection. The only acceptable number for all
150K miles of affected transmission line in the US is 0. The standard should be achievable and enable
proactively addressing potential threats to facilities from vegetation. Even using a Six Sigma level of quality
and control, processes can achieve a level of 3.4 defects per million opportunities for defect. Each tree on the
ROW represents one of those opportunities. FPL has outlined an alternative proposal in response to Question
18.
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT.
Santee Cooper
Disagree
Recommend removing R7 because current and proposed standards do not require the entire right-of-way or
Active Transmission Line Right of Way to be clear of vegetation. In this case, a utility should not be penalized
if a tree falls from within the right-of-way or Active Transmission Right-of-Way as long they are meeting all the
other standards (e.g., minimum vegetation clearance distances). Since fall-ins from just outside of the right-ofway is currently not a compliance issue, it makes sense that a fall-in from within the right-of-way be treated the
same. This is especially true for a utility who has elected to acquire a wider right-of-way than another utility.
That utility may have a tree(s) growing just inside the right-of-way but still maintains a better clearance
distance between trees and conductors than a utility with a narrower right-of-way and no tree encroachment.
Response: Thank you for your comments. While it is true that there is a negligible difference in risk to the electric system for trees just within or just
outside the active right of way, the major difference is that the Transmission Owner generally has the right to manage vegetation within the active right
of way. Also, while Transmission Owners employ differing active right-of-way widths, this is essentially uncontrollable by the SDT or by regulators.
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Exelon
Agree?
Disagree
Question 16 Comment
It appears to Exelon that the requirements of the standard have been written and modified at different times
and as a result the document lacks a degree of consistency and coherence. While the Standard mentions
encroachment of the CCZ and Sustained Outages as potential violations, it is completely silent on how
momentary outages should be addressed. Exelon views the following events as a risk continuum that should
be addressed in the Standard and handled as a part of the VRFs and VSLs - encroachment of the air gap
distance, momentary outages and Sustained Outages.
Response: Thank you for your comments. The Minimum Vegetation Clearance Distance is the calculated spark-over distance derived from the Gallet
equations. Therefore a momentary caused by a tree under the circumstances defined in R4 would by definition be a violation of R4.
Platte River Power Authority
Disagree
The requirement under R7 should be changed from "shall prevent sustained outages" to "shall minimize
sustained outages due to vegetation falling into a conductor." We note the word "minimize" was present in
earlier drafts of the document. We are concerned about the requirement for utilities to prevent sustained
outages from vegetation falling into the conductor from within the active transmission ROW. It is operationally
almost impossible to know precisely where the edge of the ROW is in all situations under all conditions. This
could lead to an incident where utilities are charged unreasonably - for example, for an outage from a tree that
was one foot within the active ROW line. We should not be held liable when reasonable due diligence is
practiced.
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT. The SDT believes that the Transmission Owner holds responsibility for knowing the location of the edges of its active rights of
way and whether a rooted tree is within or outside the active right of way.
USDA Forest Service,
Southwestern Region, Regional
Office for AZ and NM
Disagree
I believe that the text for each element should be re-written with the general philosophy that the Transmission
Owner shall do everything reasonable to prevent such problems in line with the comment for section
15.Problems should be reported and investigated and a judgment call should be made about whether the
Transmission Owner did everything reasonable to avoid the problem.
Response: Thank you for your comments. The purpose of this standard is to improve reliability of the electric transmission system by preventing
vegetation-related outages that can lead to cascading by establishing clear and measureable requirements. While the SDT appreciates the value of
judgment in the field FERC has indicated that requirements in proposed Standards be equivalent to or more stringent than the same or similar
requirements in already approved Standards.
Consumers Energy Company
September 8, 2009
Disagree
R5, R6 and R7 should be rewritten as a single requirement for vegetation within the "Active Transmission Line
Right of Way" and the exceptions listed. Additionally, a requirement for hazardous trees outside of the "Active
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Question 16 Comment
Transmission Line Right of Way" should be incorporated into this draft and similar exceptions listed for natural
disasters, third-party, and animal causes.
Response: Thank you for your comments. Requirements R5, R6 and R7 deal with three distinct types of outages which may pose different risks or
severity in terms of impact to the electric system. The SDT chose to break the three requirements apart to allow application of different Violation Risk
Factors because blow-in and fall-in interruptions do pose a significantly lower risk of causing a cascading blackout event.
Regarding incorporating a requirement to address hazardous trees outside the Active Right-of-Way, Transmission Owners generally have the right to
manage vegetation within the Active Transmission Right-of- Way. These rights will not always exist beyond the Active Transmission Right-of-Way.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Disagree
We strongly recommend that the requirement under R7 be changed from “shall prevent sustained outages” to
“shall minimize sustained outages due to vegetation falling into a conductor.” We note that the word “minimize”
was present in earlier drafts of the document. We are concerned about the requirement for utilities to prevent
sustained outages from vegetation falling into the conductor from within the active transmission ROW. It is
operationally almost impossible to know precisely where the edge of the ROW is in all situations under all
conditions. This could lead to an incident where utilities are charged unreasonably ? for example, for an
outage from a tree that was one foot within the active ROW line. We should not be held liable when
reasonable due diligence is practiced. Further, it is not economically feasible for utilities to survey every ROW
in the U.S. and Canada to determine and document precise clearance zones. Such costly effort would not
produce any benefit to the reliability of the bulk electric system.
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT. The SDT believes that the Transmission Owner holds responsibility for knowing the location of the edges of its active rights of
way and whether a rooted tree is within or outside the active right of way.
San Diego Gas & Electric
Disagree
We recommend that the requirement under R7 be changed from "shall prevent sustained outages" to "shall
minimize sustained outages due to vegetation falling into a conductor." The word minimize was present in
earlier drafts of the document. We are concerned with the requirement for utilities to prevent sustained
outages from vegetation falling into the conductor from within the active transmission Right of Way. It is
operationally almost impossible to know precisely where the edge of the ROW is in all situations under all
conditions. This could lead to an incident where utilities are charged unreasonably.
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT. The SDT believes that the Transmission Owner holds responsibility for knowing the location of the edges of its active rights of
way and whether a rooted tree is within or outside the active right of way.
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Hydro One Networks Inc.
Agree?
Disagree
Question 16 Comment
A further exception would be a sustained outage where the conductor has moved outside of the critical
clearance zone. This could occur under conditions of heavy icing, operating outside the line rating or
excessive wind. These would not necessarily be the result of a natural disaster. Also, it is recommended that
the requirement for R7 be revised to “Each Transmission Owner shall minimize (“minimize” replacing
“prevent”) Sustained Outages of applicable lines due to vegetation falling into a conductor”.. A fall in is a
random occurrence and the likelihood that this would be the cause or contribute to a cascading event is very
remote. These types of outages are rare and can be considered similar in nature to an insulator flashover or a
hardware failure, which have not been given any association with cascading events. The purpose of the
standard is to prevent cascading events and it is suggested that this remain the focus and not introduce other
types of outages on a selective basis.
Response: Thank you for your comment. The Critical Clearance Zone (CCZ) has been removed from the standard.
The SDT concurs that fall in events present a lower risk to the system than grow in events. Requirements R5, R6 and R7 have been drafted to address
three distinct types of outages which may pose different risks or severity in terms of impact to the electric system. The SDT chose to break the three
requirements apart to allow application of different Violation Risk Factors and Violation Severity Levels.
Arizona Public Service
Company
Disagree
APS strongly recommends that the requirement under R7 be changed from “shall prevent sustained outages”
to “shall minimize sustained outages due to vegetation falling into a conductor.” We note that the word
“minimize” was present in earlier drafts of the document. We are concerned about the requirement for utilities
to prevent sustained outages from vegetation falling into the conductor from within the active transmission
ROW. It is operationally almost impossible to know precisely where the edge of the ROW is in all situations
under all conditions. This could lead to an incident where utilities are charged unreasonably ? for example, for
an outage from a tree that was one foot within the active ROW line. We should not be held liable when
reasonable due diligence is practiced. Further, it is not economically feasible for utilities to survey every ROW
in the U.S. and Canada to determine precise clearance zones.
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT. The SDT believes that the Transmission Owner holds responsibility for knowing the location of the edges of its active rights of
way and whether a rooted tree is within or outside the active right of way.
Entergy Services
September 8, 2009
Disagree
1. If a version of R4 that states an encroachment to the Critical Clearance Zone is a violation, Entergy
disagrees with the need for R5, R6, and R7 because it is redundant to R4. An outage cause by vegetation: a)
growing into the line b) blowing into the line and c) falling into the conductor would require the vegetation to
break the Critical Clearance Zone. If these requirements stay in the standard, an outage of the above nature
would mean the entity violated two requirements, R4 and R5, R6, or R7. 2. Entergy is amenable to keeping
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R5, 6, and 7 if R4 is removed from the standard. 3. If approved, we suggest that R5, 6, and 7 not apply to
trees from off the right of way.
Response: Thank you for your comments. Requirements R5, R6 and R7 have been drafted to address three distinct types of outages which may pose
different risks or severity in terms of impact to the electric system. The SDT chose to break the requirements apart to allow application of different
Violation Risk Factors and Violation Severity Levels. R4 has been drafted to clarify that clearance encroachments are violations of the Standard. Matters
of being assessed two violations for a single event are addressed in the NERC compliance sanctions guideline.
Salt River Project
Disagree
Recommend that the requirement under R7 be changed from "shall prevent sustained outages" to "shall
minimize sustained outages due to vegetation falling into a conductor". We understand that the word
"minimize" was present in earlier drafts of the document. We are concerned about the requirement to prevent
sustained outages from vegetation falling into the conductor from within the active transmission ROW. It is
operationally almost impossible to know precisely where the edge of the ROW is in all situations under all
conditions. This could lead to an incident where a utility is charged unreasonably - for example, for an outage
from a tree that was one foot within the active ROW line. We should not be held liable when reasonable due
diligence is practiced. Furthermore, it is not economically feasible for utilities to survey every ROW to
determine precise clearance zones.
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT. The SDT believes that the Transmission Owner holds responsibility for knowing the location of the edges of its active rights of
way and whether a rooted tree is within or outside the active right of way.
Hydro-Quebec Transenergie
(HQT)
Disagree
HQT request clarification if violations of R5, R6, and R7 result in outages that must be reported. A further
exception would be a sustained outage where the conductor has moved outside the critical clearance zone.
This could occur under conditions of heavy icing, operating outside the line rating or excessive wind.
Response: Thank you for your comments. Regarding your question on reporting of violations, under NERC’s Compliance Guidelines, any violation of a
reliability standard requirement must be self-reported; thus, a violation of Requirement R5, R6 or R7 must result in a report from the Transmission
Owner. In addition, the revised standard includes compliance elements, including the need to provide periodic reports of specific vegetation-related
outages.
The Critical Clearance Zone (CCZ) is defined by the movement of the conductor between no load and its rating. The Standard does not apply to events
which occur outside of the CCZ.
Southern California Edison
September 8, 2009
Agree
Q16: SCE agrees in part with the establishment of R5, R6 and R7, however, we note that the opening of each
requirement repeats a slightly altered version of the FAC-002-2 purpose statement. We find such
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Question 16 Comment
repetitiveness unnecessary and note that as written, Requirements 5-7 presents a near identical compliance
conundrum for Transmission Owners as Requirement 4. Again, Transmission Owners would be required to
prove that they did not incur a sustained outage due to a vegetation caused flash-over or vegetation-to-line
contact whether it be a grow-in, blow-in or fall-in. Although proving a sustained outage (for cause) did not
occur will be difficult and unwieldy, it is not impossible. The simple difference between a Transmission Owner
disproving the occurrence of a CCZ incursion and their disproving vegetation caused sustained outages, is
that Transmission Owners do in fact keep records of “outages”. Because a Transmission Owner’s record
keeping prowess is the only viable option for proving a vegetation caused outage did not occur, SCE
respectfully suggests R5, R6 and R7 be revised to read:R5 - "Each Transmission Owner shall document
Sustained Outages of applicable lines due to vegetation growing into a conductor operating within its Rating
with the following exceptions:"R6 - "Each Transmission Owner shall document Sustained Outages of
applicable lines due to vegetation blowing into a conductor operating within its Rating and located within an
Active Transmission Line Right of Way with the following exceptions:"R7 - "Each Transmission Owner shall
document Sustained Outages of applicable lines due to vegetation falling into a conductor operating within its
Rating and located within an Active Transmission Line Right of Way with the following exceptions: "We also
note that Footnote 6 is misplaced in the draft and should follow the word “Outages” in each of these
requirements.
Response: Thank you for your comments. Requirements R5, R6 and R7 deal with three distinct types of outages which may pose different risks or
severity in terms of impact to the electric system. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable)
vegetation-related outages. Additionally, the Transmission Owner must document and report outages under NERC’s Compliance Guidelines. However,
the SDT chose to break the three requirements apart to allow application of different Violation Risk Factors and Violation Severity Levels.
As to the matter of proving the lack of CCZ incursions, please refer to the SDT’s response to your Question # 15 comments.
Your suggestion regarding Footnote 6 has been incorporated.
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 16.
Response: Thank you for your comments.
American Electric Power (AEP)
Agree
AEP is in agreement with these changes.
Response: Thank you for your supportive comment.
City of Tallahassee
September 8, 2009
Agree
Why have we gone backwards with only "Sustained Outages" being a violation? Even a momentary outage
indicates that a violation has occurred if the cause was vegetation related (with the same exceptions). This
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would seem to contradict the proposed R4. If it wasn't a Sustained Outage it wasn't a violation? If you have a
sustained outage due to vegetation, you must have violated the CCZ.
Response: Thank you for your comments. The SDT very carefully and thoroughly examined the merits, disadvantages, ease and difficulties of
assessing momentary outages as a violation. The result of that effort led to the more precise and field observable aspects of R4. It should be noted that
by their very nature the exact causes of “momentary outages” are very challenging to determine and will vary widely from utility to utility. The SDT did
not find that such variability was appropriate for a reliability standard, and chose to address this issue with the language in R4.
Northern Indiana Public Service
Company
Agree
While being more specific & explicit, I don't interpret the overall requirement as being any different from the
current standard.
Response: Thank you for your comment. Please note that while the current standard did not specifically define an interruption as a violation, the
proposed standard explicitly defines outages as violations.
Orange and Rockland Utilities
Inc.
Agree
We agree, but recommend that momentary outages be included as violations of all three requirements as well.
Also, the Standard does not directly require reporting of vegetation-related outages although implicitly,
outages which are violations of the Standard must be reported. This has lead to some confusion during this
comment phase and we suggest that the reporting requirements be directly stated in the Standard.
Response: Thank you for your comments. Under the Compliance section of the new standard section 2 the Transmission Owner is required to report
outages.
Xcel Energy
Agree
We agree, however please add a reference to ?wind gusts 45 miles per hour or greater? to the exception note
for this requirement. The exception would read ?1) Sustained Outages of transmission lines that result from
sustained winds (45 miles per hour or greater) or gusts due to natural disasters.?
Response: Thank you for your comments. The SDT believes that a fresh gale (see footnote 4) represents an appropriate threshold for exemptions.
Manitoba Hydro
Agree
Agree with splitting the various events. We note that there is no specific requirement to actually report an
outage. The Requirements say that we should Prevent Sustained Outages, but not actually report sustained
outages should they occur. In version 1, R3 clearly stated that the Transmission Owner shall report.
Response: Thank you for your comments. Under NERC’s Compliance Guidelines, any violation of a reliability standard requirement must be selfreported; thus, a violation of Requirement R5, R6 or R7 must result in a report from the Transmission Owner.
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National Grid
Agree?
Agree
Question 16 Comment
National Grid agrees with the proposed change, however, Standard FAC-003-2 does not provide outage
reporting requirements in R5, R6, R7, or anywhere else in the Standard.
Response: Thank you for your comments. Under NERC’s Compliance Guidelines, any violation of a reliability standard requirement must be selfreported; thus, a violation of Requirement R5, R6 or R7 must result in a report from the Transmission Owner. The revised standard includes
compliance elements, including the need to provide periodic reports of specific vegetation-related outages.
Pacific Gas & Electric Co.
Agree
M5, M6 and M7 do not explicitly exclude the exceptions in R5, R6 and R7 and should do so.
Response: Thank you for your comments. The SDT believes that the requirements and measures are properly aligned. The exceptions language is
appropriately located in the technical requirement.
Consolidated Edison Company
of New York (CECONY)
Agree
CECONY agrees that outages caused by the factors mentioned are violations of R5, R6, and R7 but we
recommend that either the phrase 'momentary outage' be included in the wording or the phrase 'All Outages'
replace 'Sustained Outages' to make the requirements clearer.
Response: Thank you for your comments. The SDT very carefully and thoroughly examined the merits, disadvantages, ease and difficulties of
assessing momentary outages as a violation. The result of that effort led to the more precise and field observable aspects of R4. It should be noted that
by their very nature the exact causes of “momentary outages” are very challenging to determine and will vary widely from utility to utility. The SDT did
not find that such variability was appropriate for a reliability standard, and chose to address this issue with the language in R4.
WECC
Agree
However reporting requirements are not identified in the standard. WECC believes that sustained outages
caused by vegetation should be reported to the Regional Entity using the existing reporting requirements in
FAC-003-1
Response: Thank you for your comments. Under NERC’s Compliance Guidelines, any violation of a reliability standard requirement must be selfreported; thus, a violation of Requirement R5, R6 or R7 must result in a report from the Transmission Owner. The revised standard includes compliance
elements, including the need to provide periodic reports of specific vegetation-related outages.
CenterPoint Energy
Agree
We agree with the exemptions; however, R6 and R7 refer to an "Active Transmission Line Right-of-way" which
is not defined as to its limits, so M6 and M7 cannot be determined by definition. See comments to Q3 above
relating to the definitions and the examples in the Technical Reference.
Response: Thank you for your comments. The SDT asserts that the Transmission Owner is responsible for defining the Active Transmission Line Right
of Way. Additionally please refer to the response to Question 3. Note that the SDT made significant changes to clarify R5, R6 and R7 and the associated
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Question 16 Comment
measures.
Pepco Holdings, Inc
Agree
There is no need for three separate requirements if the incident is a Sustained Outage, but there is nothing
inherently wrong with the three requirements.
Response: Thank you for your comments. Requirements R5, R6 and R7 have been drafted to address three distinct types of outages which may pose
different risks or severity in terms of impact to the electric system. The SDT chose to break the requirements apart to allow application of different
Violation Risk Factors and Violation Severity Levels.
Northeast Utilities
Agree
Agree that contacts resulting in sustained outages due to vegetation from within the active transmission line
right-of-way should constitute a violation of the Standard. However, this Standard is written for a zero
tolerance of any vegetation caused outages or encroachment into the CCZ. One vegetation-caused outage or
one CCZ encroachment may not result in a potential Cascading effect. Agree with the use of different violation
risk factors (VRF's) and violation severity levels (VSL's) for each of the three outage classes. Also - how are
outage violations to be reported - there is no provision in the revision for the reporting process and
requirements (specifics on the type of violation). Will this be addressed in the Compliance Section yet to be
added? Suggest in both R6 and R7, move the phrase "within an Active Transmission Line Right of Way" to
immediately follow "vegetation".
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT.
Requirements R5, R6 and R7 have been drafted to address three distinct types of outages which may pose different risks or severity in terms of impact
to the electric system. The SDT chose to break the requirements apart to allow application of different Violation Risk Factors and Violation Severity
Levels.
Regarding your question on reporting of violations, under NERC’s Compliance Guidelines, any violation of a reliability standard requirement must be
self-reported; thus, a violation of Requirement R5, R6 or R7 must result in a report from the Transmission Owner. In addition, the revised standard
includes compliance elements, including the need to provide periodic reports of specific vegetation-related outages.
Your suggested wording change to requirements R6 and R7 was evaluated by the SDT. The SDT asserts that the original wording is appropriate.
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
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Agree?
Northern California Power
Agency (NCPA)
Agree
Central Maine Power Company
Agree
Tampa Electric Company
Agree
WECC Reliability Coordination
Agree
Western Area Power
Administration, Upper Great
Plains Region
Agree
SERC Vegetation Management
Subcommittee (VMS)
Agree
Progress Energy Florida
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Progress Energy Carolinas
Agree
Southern Company
Agree
E.ON U.S.
Agree
Question 16 Comment
Bonneville Power Administration Agree
FirstEnergy
Agree
MRO NERC Standards Review
Subcommittee
Agree
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Agree?
Midwest ISO Stakeholders
Standards Collaborators
Agree
Ameren
Agree
American Transmission
Company
Agree
Nebraska Public Power District
Agree
Long Island power Authority
Agree
Edison Electric Institute
Agree
Baltimore Gas & Electric
Company
Agree
Duke Energy Corporation
Agree
JEA
Agree
Independent Electricity System
Operator
Agree
Buckeye Power, Inc.
Agree
Great River Energy
Agree
September 8, 2009
Question 16 Comment
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17. R8 is a new requirement which separates the implementation of the annual plan from the requirement to have an
annual plan. Do you agree with R8? If not please explain.
Summary Consideration: The SDT modified the Requirement for implementation of the work plan (now R9 in the revised
standard) after reviewing these comments. Commenters focused on two main areas. First, there was a suggestion that the
work plan wording be amended to include a note that it was only required on the Active Right of Way. Requirement R1 clearly
limits the scope of the TVMP to work on the entity's Active Transmission Line Rights of Way - and the "annual work plan" is one
element of the overall TVMP. The second overriding theme was that the standard be re-ordered to better tie the requirement
to have a plan and the requirement to implement a plan. Some commenters suggested that the requirement to implement the
annual work plan be embedded as part of Requirement R1, and the SDT did not make this change. The requirement to “have”
a TVMP is administrative and the requirement to “implement” the annual work plan is a real-time requirement – by keeping
these requirements separate, each requirement can be assigned an appropriate VRF. The SDT is offering for comment a
proposed re-ordering of the Standard that provides a more logical sequence to the Standard which, if supported by
stakeholders, can be applied to Draft 3 of the standard.
For Draft 2, the SDT also removed the wording “within the extent of its easements and/or legal rights.” The justification for
removing these words was to remove the possibility that the TO would be held to the maximum criteria or be limited to the
minimum criteria outlined in their easements.
Deleted: R8
R9. Each Transmission Owner shall implement its annual work plan for vegetation management to accomplish the purpose of this
standard.
Organization
Central Maine Power Company
Agree?
Deleted: within the extent of its
easement and/or legal rights
Question 17 Comment
Central Maine Power Company suggests that R9 read as A Transmission Owner shall implement its annual
work plan within the Active Right of Way to the the extent of its easements or legal rights.
Response: The SDT thanks you for your response. In response to overwhelming industry comments The SDT has removed the words “within the
extent of its easements and/or legal rights”. The SDT also feels that the Active Right of Way concept is supported adequately in Requirement R1 which
limits the scope of the TVMP (and the annual work plan) to the entity’s Active Rights of Way.
British Columbia Transmission
Corp
BCTC understands that it’s possible to have an annual plan and not implement it. However, we feel that the
document itself would be easier to follow if it was re-organized so that the requirement to have the plan is kept
together with the requirement to implement it.
Response: The SDT thanks you for your response. The SDT proposes a new sequence for the technical Requirements R1-R11 and seeks industry
feedback as requested in Question 4 of the Second Comment Form.
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Organization
Agree?
Western Utility Arborists
Question 17 Comment
The Western Utilities understands that it’s possible to have an annual plan and not implement it. However, we
feel that the document itself would be easier to follow if it was re-organized so that the requirement to have the
plan is kept together with the requirement to implement it.
Response: The SDT thanks you for your response. The SDT proposes a new sequence for the technical Requirements R1-R11 and seeks industry
feedback as requested in Question 4 of the Second Comment Form.
SERC Vegetation Management
Subcommittee (VMS)
Disagree
While the SERC VMS agrees in principle, we believe that the Requirement, as written, is “open ended” and
could be interpreted to be in conflict with the "Active Rights of Way" concept. Clarifying the intent for the annual
plan to focus on the Active Rights of Way will prevent incorrect interpretations. The SERC VMS suggest that
the Requirement be reworded to read: ?Each Transmission Owner shall implement its annual work plan for
vegetation management within the Active Right of Way to accomplish the purpose of this standard within the
extent of its easements and or legal rights.?
Response: The SDT thanks you for your response. The SDT considered your request at length but feels that the Active Right of Way concept is
supported adequately in Requirement R1 which limits the scope of the TVMP (and the annual work plan) to the entity’s Active Rights of Way.
JEA
Disagree
See comment from #3.
Response: Thank you for your comment. Please see the response to comments on #3. .
Salt River Project
Disagree
The document would be easier to follow if the two elements would be kept together in the same requirement
(similar to comments in #4, #6, & #14 above). It makes the standard longer than necessary and creates
redundancy.
Response: The SDT thanks you for your response. The reason that the development of the annual plan and the implementation of the plan were
separated was to apply the appropriate VRF’s and VSL’s to each. The SDT feels that the current organization is appropriate because development of
the annual work plan is a sub-part of the development of the Transmission Vegetation Management Program and should be separate from the
implementation requirement for the annual plan.
SERC OC Standards Review
Group
Disagree
The SERC OCSRG suggests that the Requirement be reworded to read: “Each Transmission Owner shall
implement its annual work plan for vegetation management within the Active Rights of Way." Any further
verbiage is confusing, ambiguous or unnecessary.
Response: The SDT thanks you for your response. The SDT considered your request at length but feels that the Active Right of Way concept is
supported adequately in the definition and elsewhere in the standard. The SDT did, however, remove the last phrase of the sentence, “within the extent
September 8, 2009
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Organization
Agree?
Question 17 Comment
of its easement and/or legal rights.”
Florida Power & Light
Disagree
The standard goes to great length to specify the Active Transmission Right-of-Way but omits its reference in
requirement R9. The inclusion of this term in Requirement R9 adds consistency to the application of the
standard. FPL suggests the following change: "Each Transmission Owner shall implement its annual work plan
for vegetation management to accomplish the purpose of this standard within the extent of its easement and/or
legal rights in the Active Transmission Line Right-of-Way."
Response: The SDT thanks you for your response. Due to industry comments the SDT revised the wording on this requirement to delete the words
“within the extent of its easements and/or legal rights”. The SDT also feels that the Active Right of Way concept is supported adequately in the
Requirement R1 which limits the scope of the TVMP (and the annual work plan) to the entity’s Active Rights of Way.
Southern Company
Disagree
While we agree in principle, we feel Requirement R9 as written is “open ended” and could be interpreted to be
in conflict with the “Active Rights of Way” concept. Clarifying the intent for the annual plan to focus on the
Active Rights of Way will prevent incorrect interpretations. We suggest that the Requirement be reworded to
read: Each Transmission Owner shall implement its annual work plan for vegetation management within the
Active Right of Way to accomplish the purpose of this standard within the extent of its easements and or legal
rights.
Response: The SDT thanks you for your response. Due to industry comments the SDT revised the wording on this requirement to delete the words
“within the extent of its easements and/or legal rights”. The SDT also feels that the Active Right of Way concept is supported adequately in
Requirement R1 which limits the scope of the TVMP (and the annual work plan) to the entity’s Active Rights of Way.
E.ON U.S.
Disagree
E.ON U.S. believes that the Requirement, as written, is “open ended” and could be interpreted to be in conflict
with the "Active Rights of Way" concept. Clarifying the intent for the annual plan to focus on the Active Rights
of Way will prevent incorrect interpretations. We suggest that the Requirement be reworded to read: “Each
Transmission Owner shall implement its annual work plan for vegetation management within the Active Right of
Way to accomplish the purpose of this standard within the extent of its easements and or legal rights.”
Response: The SDT thanks you for your response. The SDT agrees with your comments and has removed the words “within the extent of its
easements and/or legal rights”. The SDT also feels that the Active Right of Way concept is supported adequately in Requirement R1 which limits the
scope of the TVMP (and the annual work plan) to the entity’s Active Rights of Way.
Exelon
Disagree
September 8, 2009
Strike "within the extent of it's easement and / or legal rights." This is unnecessary and will cause confusion.
The annual work plan as required to be developed per R1.3 requires consideration of permitting, scheduling
and regulatory limitations.
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Organization
Agree?
Question 17 Comment
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support for your suggestion and the
requirement has been revised to reflect your suggestion.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Disagree
We understand that it is possible to have an annual plan and not implement it. However, we feel that the
document itself would be easier to follow if it was re-organized so that the requirement to have the plan is kept
together with the requirement to implement it.
Response: The SDT thanks you for your response. The SDT feels that the current organization is appropriate because development of the annual
work plan is a sub-part of the development of the Transmission Vegetation Management Program and should be separate from the implementation
requirement for the annual plan. The SDT proposes a new sequence for the technical Requirements R1-R11 and seeks industry feedback as requested
in Question 4 of the Second Comment Form.
San Diego Gas & Electric
Disagree
We feel that the document itself would be easier to follow if it was re-organized so that the requirement to have
the plan is kept together with the requirement to implement the plan.
Response: The SDT thanks you for your response. The SDT feels that the current organization is appropriate because development of the annual
work plan is a sub-part of the development of the Transmission Vegetation Management Program and should be separate from the implementation
requirement for the annual plan. The SDT proposes a new sequence for the technical Requirements R1-R11 and seeks industry feedback as requested
in Question 4 of the Second Comment Form.
Baltimore Gas & Electric
Company
Disagree
As in question no. 14 above for R1.2, it would seem to make more sense to combine R1.3 & R9 as follows:
"Require development and implementation of an annual plan that?."
Response: The SDT thanks you for your response. The reason that the development of the annual plan and the implementation of the plan were
separated was to apply the appropriate VRF’s and VSL’s to each. The SDT feels that the current organization is appropriate because development of
the annual work plan is a sub-part of the development of the Transmission Vegetation Management Program and should be separate from the
implementation requirement for the annual plan.
Pepco Holdings, Inc
Disagree
THE SDT has introduced the term Active Transmission Line Right of Way. R9 should use this term to avoid
any misinterpretation.
Response: The SDT thanks you for your response. In response to industry comments The SDT has removed the words “within the extent of its
easements and/or legal rights”. The SDT also feels that the Active Right of Way concept is supported adequately in Requirement R1 which limits the
scope of the TVMP (and the annual work plan) to the entity’s Active Rights of Way.
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Organization
Great River Energy
Agree?
Disagree
Question 17 Comment
GRE both Agrees and Disagrees. GRE agrees with the separation between having an annual plan and
implementing it. However, GRE suggests removing all the words after vegetation management.
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support for your suggestion and the
requirement has been revised to reflect your suggestion.
City of Tallahassee
Disagree
Combined with Question 6. R9 needs to have the same flexibility that R1.3 has. As written, it could be argued
that you have to do everything in your annual plan, AND anything in addition due to the changing conditions.
This contradicts what is put forth in the white paper. I would add "as modified per R1.3" after "implement it's
annual work plan for vegetation management"
Response: The SDT thanks you for your response. The SDT feels that the “flexibility” of the annual plan is built into the development of the plan and
that same flexibility carries through to the implementation.
Tampa Electric Company
Disagree
Good start. R9 must also address the flexibility which is addressed in R1.3. As written, R9 does not do this. In
addition, R9 states "within the extent of its easement and/or legal right..". This could create another set of
conflicting criteria, where the utility has a long term "interim corrective action plan".
Response: The SDT thanks you for your response. The SDT feels that the “flexibility” of the annual plan is built into the development of the plan and
that same flexibility carries through to the implementation. The SDT does agree with the possible confusion the words “within the extent of its
easement and/or legal rights” could cause and has consequently removed these words from the requirement.
USDA Forest Service,
Southwestern Region, Regional
Office for AZ and NM
Disagree
This standard needs to be broadened to include evaluation of the good faith efforts by the Transmission Owner
to coordinate with the USFS on development of the work plan. A mechanism should be developed to allow the
Transmission Owner to evaluate the good faith efforts of the USFS.
Response: The SDT thanks you for your response. The Standard is a continental reliability standard. While the SDT agrees with you that every
Transmission Owner should strive for mutually beneficial relationships with the various landowners and other entities involved in vegetation
management, it would be outside the purvey of this effort to outline specific relationships.
Arizona Public Service Company
Disagree
APS understands that it’s possible to have an annual plan and not implement it. However, we feel that the
document itself would be easier to follow if it was re-organized so that the requirement to have the plan is kept
together with the requirement to implement it.
Response: The SDT thanks you for your response. The SDT feels that the current organization is appropriate because development of the annual
work plan is a sub-part of the development of the Transmission Vegetation Management Program and should be separate from the implementation
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Organization
Agree?
Question 17 Comment
requirement for the annual plan. The SDT proposes a new sequence for the technical Requirements R1-R11 and seeks industry feedback as requested
in Question 4 of the Second Comment Form.
SERC Compliance Staff
Agree
Vegetation management practices should be extended areas outside of the active rights-of-way (ROW) to the
extent necessary to prevent vegetation-related outages. This should include the identification and removal of
trees that could impact transmission line operation similar to the practice of identifying danger trees off of the
ROW. The requirement as written could serve to reward those entities that, for whatever reason, have
insufficient right-of-way widths. From a practical perspective, it should not be necessary to perform clear cutting
of non-active ROW, but Entities should be held responsible for any outages that occur due to contact with
vegetation within their legal rights to control.
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support to remove any wording referring to
the easement rights. The SDT agreed with this view and has revised the requirement.
ITC HOLDINGS
Agree
Clarifying the intent for the annual plan is to focus on the Active Rights of Way will prevent interpretation
conflicts
Response: The SDT thanks you for your response. The SDT agrees with your observation, but also points out that the requirement for an annual work
plan (sub-part 1.3) is part of Requirement R1, which specifically states its applicability to Active Transmission Line Rights of Way. Therefore, the SDT
respectfully feels that your concern is addressed without additionally placing such verbiage in R8 (now R9).
American Electric Power (AEP)
Agree
AEP agrees with this change.
Response: The SDT thanks you for your comments. The SDT modified the requirement, based on stakeholder comments, to remove the last phrase,
“within the extent of its easement and/or legal rights.”
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 17
Response: The SDT thanks you for your comment. The SDT modified the requirement, based on stakeholder comments, to remove the last phrase,
“within the extent of its easement and/or legal rights.”
Platte River Power Authority
September 8, 2009
Agree
The separation allows lower sanctions and penalties to be assessed for a weak plan and higher sanctions and
penalties to be assessed for not implementing an annual plan. However, we feel that the standard itself would
be easier to follow if it was re-organized so that the requirement to have a plan is kept together with the
requirement to implement it.
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Organization
Agree?
Question 17 Comment
Response: The SDT thanks you for your response. The reason that the development of the annual plan and the implementation of the plan were
separated was to apply the appropriate VRF’s and VSL’s to each. The SDT feels that the current organization is appropriate because development of
the annual work plan is a sub-part of the development of the Transmission Vegetation Management Program and should be separate from the
implementation requirement for the annual plan. The SDT proposes a new sequence for the technical Requirements R1-R11 and seeks industry
feedback as requested in Question 4 of the Second Comment Form.
American Transmission
Company
Agree
ATC agrees with the requirement to implement the annual work plan, but recommends striking the words
"within the extent of its easement and/or legal rights". The emphasis for this requirement is to execute the
annual work plan. The white paper already speaks to the point that it is a best practice for utilities to exercise
their legal rights. If we agree that the goal is to prevent outages, then we can simply end this requirement with
"implement its annual work plan for vegetation management." Propose Changes to R9: Each Transmission
Owner shall implement its annual work plan for vegetation management.
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support for your suggestion and the
requirement has been revised to reflect your suggestion.
Ameren
Agree
We recommend striking, or modifying, the words "within the extent of its easement and/or legal rights" as they
may be introducing an unintended compliance quagmire. For example, if the easement is extraordinarily wide
but reliability and the work plan do not dictate that the work plan apply to the entire easement, how will
compliance be measured? The work plan should recognize easement or legal rights issue. Therefore, the
emphasis for this requirement should be to execute the annual work plan. The white paper already speaks to
the point that it is a best practice for utilities to exercise their legal rights. By tagging the words on to the
requirement, we are adding unnecessary compliance validation to this requirement for both industry and the
regulators. If a clarifying sentence is required, we would suggest that R9 stop with the word standard and a new
sentence be added, "The work plan should address easement or legal/rights"
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support for your suggestion and the
requirement has been revised to reflect your suggestion.
MRO NERC Standards Review
Subcommittee
Agree
The MRO both Agrees and Disagrees. The MRO agrees with the separation between having an annual plan
and implementing it. However, the MRO suggests removing all the words after vegetation management.
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support for your suggestion and the
requirement has been revised to reflect your suggestion.
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Organization
Midwest ISO Stakeholders
Standards Collaborators
Agree?
Agree
Question 17 Comment
We recommend striking the words "within the extent of its easement and/or legal rights". The emphasis for this
requirement is to execute the annual work plan. The white paper already speaks to the point that it is a best
practice for utilities to exercise their legal rights. By tagging the words on to the requirement, we are adding
unnecessary compliance validation to this requirement for both industry and the regulators. By the way this is
written, it could be interpreted different ways. If we agree that the goal is to prevent outages, then we can
simply end this requirement with "accomplish the purpose of the standard". Each Transmission Owner would
be accountable to manage compliance with this standard and public relations in their service area.
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support for your suggestion and the
requirement has been revised to reflect your suggestion.
Duke Energy Corporation
Agree
Duke agrees with the requirement to implement the annual work plan, but recommends striking the words
"within the extent of its easement and/or legal rights". The emphasis for this requirement is to execute the
annual work plan. The white paper already speaks to the point that it is a best practice for utilities to exercise
their legal rights. If we agree that the goal is to prevent outages, then we can simply end this requirement with
"accomplish the purpose of the standard". Each Transmission Owner will be accountable to manage
compliance with this standard.
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support for your suggestion and the
requirement has been revised to reflect your suggestion.
CenterPoint Energy
Agree
R9 requires implementation of the annual work plan "within the extent of its [the Transmission Owner's]
easement and/or legal rights." All measures and compliance should be determined on this basis as well. This
concept should also be carried through the definitions for "Active Transmission Line Right-of-way" and "Critical
Clearance Zone", or for any definition of clearances should the Standard continue to utilize such terms.
Response: The SDT thanks you for your response. In response to industry comments The SDT has removed the words “within the extent of its
easements and/or legal rights”. The SDT also feels that the Active Right of Way concept is supported adequately in the definition and in Requirement
R1 which limits the scope of the TVMP (and the annual work plan) to the entity’s Active Rights of Way.
Progress Energy Florida
Agree
While Progress Energy agrees with the change, the term “annual plan” should be a defined term including
threshold elements.
Response: The SDT thanks you for your response. The SDT feels that the annual plan is adequately defined between the descriptions in the Standard
(sub section 1.3) and in the technical reference document.
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Organization
Southern California Edison
Company
Agree?
Agree
Question 17 Comment
Q17: SCE agrees in part with the inclusion of R9, however, we believe R9 should be revised and renumbered
to replace proposed R3. In SCE’s view, the act of implementing a Transmission VM program encompasses
both inspection and maintenance activities. SCE respectfully suggests that proposed R9 be revised to read:
"Each Transmission Owner shall implement and follow its Vegetation Management Program to the extent
allowed by existing easement and/or legal rights."
Response: The SDT thanks you for your response. The SDT separates the vegetation inspections from the annual work plan because of partly due to
the fundamental importance of the inspection process, and partly because a key purpose of an inspection is to provide input to the formation of the
annual work plan. The SDT also points out that the TVMP is comprises the overarching processes and standards for program management, while the
annual plan is the specific annual activities to accomplish the goals set forth in the program. In addition, the SDT modified the requirement, based on
many other stakeholder comments, to remove the last phrase, “within the extent of its easement and/or legal rights.”
FirstEnergy
Agree
FirstEnergy agrees with the intent of R9, but the standard should be clarified by removal of the word
"easement". As written the standard is open to interpretation between "easement" and active right of way. It is
important to have the term "legal rights" remain in the standard. The Transmission Owner should be held
accountable to fully enforce the legal rights outlined in maintaining the active right of way. This will lead to a
more reliable transmission system.
Response: The SDT thanks you for your response. Due to industry comments the SDT revised the wording on this requirement to delete the words
“within the extent of its easements and/or legal rights”. While we agree and state in the technical reference document that clearing to the maximum
extent is in most cases the best practice, there are particular situations where a clear cut policy would not be in the best interest of the Transmission
Owner or the landowner. The SDT also feels that the Active Right of Way concept is supported adequately in Requirement R1 which limits the scope of
the TVMP (and the annual work plan) to the entity’s Active Rights of Way.
Pacific Gas & Electric Co.
Agree
PG&E agrees with the requirement to implement the annual work plan, but recommends removing the
language "within the extent of its easement and/or legal rights".
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support for your suggestion and the
requirement has been revised to reflect your suggestion.
Entergy Services
Agree
Entergy would like to note that requirements R1.3 and R9 are administrative requirements that add marginal
value to the reliability of the Transmission System. Since entities are required to have flexible annual plans,
deviations from the annual plan only need to be documented and these requirements will be met. Entergy
utilizes annual plans as a good practice but sees limited value with the inclusion in this standard.
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad concern that the current wording could
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Organization
Agree?
Question 17 Comment
cause confusion with the wording “within the extent of its easements and/or legal rights”. Consequently the SDT agreed with this view and has revised
the requirement to address these concerns. The SDT respectfully disagrees that sub section 1.3 and R9 are administrative requirements and only add
marginal value to the reliability of the system. Requirement R8 (now R9) is a real-time requirement, not an administrative requirement.
Nebraska Public Power District
Agree
Long Island power Authority
Agree
Northern California Power
Agency (NCPA)
Agree
Northern Indiana Public Service
Company
Agree
Bonneville Power Administration
Agree
Orange and Rockland Utilities
Inc.
Agree
Manitoba Hydro
Agree
Consumers Energy Company
Agree
National Grid
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
Consolidated Edison Company
of New York (CECONY)
Agree
WECC
Agree
Independent Electricity System
Agree
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Organization
Agree?
Question 17 Comment
Operator
Northeast Utilities
Agree
Hydro-Quebec Transenergie
(HQT)
Agree
Buckeye Power, Inc.
Agree
Santee Cooper
Agree
Associated Electric Cooperative
Inc.
Agree
NPCC
Agree
WECC Reliability Coordination
Agree
Western Area Power
Administration, Upper Great
Plains Region
Agree
Kansas City Power & Light
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Progress Energy Carolinas
Agree
Response: Thank you for your positive response. The SDT modified the requirement, based on many other stakeholder comments, to remove the last
phrase, “within the extent of its easement and/or legal rights.”
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18. If you have further suggestions for improving this standard or the technical reference document, please offer them.
Summary Consideration: The overall industry feedback provided to this question reiterated concerns expressed in previous
comments above. Most were related to the Critical Clearance Zone and associated issues of measurability, enforceability and
practicality.
Organization
Associated Electric
Cooperative Inc.
Question 18 Comment
R10 and R11: Associated Electric Cooperative Inc does not believe the Reliability Coordinator (RC) is the appropriate entity to
determine whether or not selected sub-200 kv transmission lines should be subject to this standard. The planning horizon for the RC is
typically much shorter than the time needed to incorporate a sub-200 kv transmission line into a vegetation management program.
Associated recommends Planning Coordinator be designated as the applicable functional entity and be substituted wherever Reliability
Coordinator appears in the Standard.
M1.4: The language in M1.4, requiring immediate communication of an imminent threat to the Transmission Operator, is inconsistent
with the Applicability in Section A.4.1.1 which designates the Transmission Owner as the responsible entity.
M4: The preparation and retention of inspection reports, imminent threat reports, quality assurance reports, etc. is appropriate. These
reports would not, however, absolutely demonstrate the Transmission Owner had experienced no vegetation encroachments into the
Critical Clearance Zone. A negative cannot be proven.
M6 and M7: The Transmission Owner is again expected to demonstrate a negative to prove compliance.
Section C: Associated Electric Cooperative Inc recognizes the Standard, as posted, is a first draft for comments and will likely be
revised before submittal for ballot. However, the Compliance section should be posted for an adequate comment period prior to
balloting.
Response: The SDT thanks you for your comments.
The drafting team has made significant changes to the draft standard in response to industry comments, including the replacement of RC with PC.
R1.4 and M1.4 are changed and the inconsistency has been resolved.
R4 and M4 are changed such that real time observations during inspections and patrols replace the previous condition of proving a negative. In
addition, the revised standard does not use the concept of the Critical Clearance Zone.
M6 and M7 have been changed so that the proof of a negative is not required.
The SDT had developed compliance elements for the industry to review in the second comment period.
NPCC
NPCC requests that the Standard Drafting Team review the compliance and reporting requirements for consistency and adequacy.
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Question 18 Comment
Response: The SDT thanks you for your comments. The drafting team has made significant changes to the draft standard in response to industry
comments. Compliance elements have been added to the second draft of the standard.
WECC Reliability
Coordination
R10 Should a dispute arise, how are those disputes resolved. Who keeps the list.
R10 What is acceptable methodology given the lack of interpretation of unacceptable risk of instability(R 10.2) or cascading failures.
There is no definition of the consequences if a sub 200kv line is left off the list for vegetation management, and caused a cascading
outage or placed the grid at an unacceptable risk of instability.
Response: The SDT thanks you for your comments The drafting team has made significant changes to the draft standard in response to industry
comments.
The RC has been replaced with the PC in R9 and R10.
This standard requires the PC to prepare and keep the list. Requiring the list to be developed in consultation with the TO ensures that the list will be
available to the TO for the purposes in this Standard. The revised language should eliminate any disputes as the PC is ultimately the responsible entity
for developing the list.
R10 was revised and now uses terminology that replicates terms within the IROL definition in the NERC Glossary of Terms for reliability standards. The
intent is for the PC to use the same methods that determine those lines which are elements of an IROL be used to determine sub 200kV lines which are
applicable to this standard.
While the planning study or similar analysis as cited in M10 could contain errors, it is not the intent of this standard to determine the competency of the
PC or the results of PC any PC’s analysis.
Western Area Power
Administration, Upper
Great Plains Region
1) Proactive utilities are implementing policies that call for the removal of all vegetation that could grow into the Critical Clearance Zone
. Such policies are not without resistance from landowners, environmental groups, etc. One of the arguments used by such groups is
that NERC/FERC do not require removal of the trees. It would very helpful if this document included the practice of removing vegetation
capable of encroaching within the Critical Clearance Zone as a reasonable or acceptable practice under this Standard.
2) We can foresee a possible public backlash if this Standard is adopted as written. We see many utilities needing rate increases to
cover the additional costs of implementing and monitoring the more stringent requirements of this proposal. We also believe that the
more stringent requirements will have no noticeable impact on reliability. So you'll have the public paying more and seeing no change in
reliability and questioning why.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The essential changes are: The CCZ concept has been replaced with the concept of minimum vegetation clearance distances, and
Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time. The
Standard Drafting team has found that this Standard can not establish any legal basis to require Transmission Owners to exercise rights that do no
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exist within their transmission line easements or permits.
Progress Energy Florida To avoid interpretation errors and provide clarity, the Applicability section for Facilities (4.2) of FAC-003 should include a statement that
the standard only applies to vegetation within the Active Transmission Line Right of Way. For example, a fall-in from outside of the
Active Transmission Line Right of Way that causes a sustained outage is not a violation of this standard. Any encroachment/outage
initiated by vegetation falling from outside of the Active Transmission Line Right of Way should be excluded from violations. The Critical
Clearance Zone concept is academically elegant, but when applied in the field, it presents significant implementation, interpretation and
enforcement issues: the complexity of determining compliance could have the unintended negative consequences to reliability; removal
of vegetation will likely be delayed because of the complexity and accuracy required to determine compliance prior to tree removal;
certification that no violations have occurred will require lengthy and costly calculations and survey measurements; the standard refers to
Ratings in the determination of line sags and Ratings is not a tightly defined term, PRC-023 requires relays to hold lines in beyond the
line Ratings; how will PRC-023 requirements be factored into the Critical Clearance Zone concept. The Critical Clearance Zone
concept introduces more complexity and ambiguity into the standard than it resolves. The drafting team needs to develop an alternative
to the Critical Clearance Zone concept that is simple, easy to apply and clearly defines at what point a violation occurs. There are over
158,000 line miles of AC Transmission above 200kV in the United States, covering a Right of Way area potentially as large as 3,000 to
4,000 square miles (an area roughly equivalent to Rhode Island and Delaware combined). With billions of stems of managed vegetation,
in and along the right of way, even six-sigma performance would result in a number of outages on a system this large. With countless
VM processes and assessments that take place daily, it is unrealistic/unreasonable to expect zero-tolerance for random vegetation
events (the transmission system is planned/operated to handle at least any single contingency).
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The essential changes are: The CCZ concept has been replaced with the concept of minimum clearance distances, and
Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time.
The exclusion you request for vegetation falling through the MVCD, regardless of its being form inside or outside the right-of-way, has been added.
Due to the industry impact that arises from zero tolerance for vegetation-related sustained outages, the Drafting Team tried several approaches but
could not find a mechanism in the standard development process to establish a non-zero threshold for outages that was acceptable to FERC staff,
because Standard revisions may not lead to less emphasis on reliability.
The PRC-023 Standard seeks to ensure that transmission protective relays are properly set such that they do not trip a transmission element
unnecessarily. This FAC-003 Standard seeks to prevent vegetation related Sustained Outages by requiring Transmission Owners to maintain their
Active Transmission Line Rights of Way to be sufficiently clear. These two Standards are not mutually exclusive nor conflict with each other.
Kansas City Power &
Light
The title and explanation for Table 1 in Attachment 1 is not clear as to it’s usage and applicability. It is being confused with the correlation
with a minimum clearance and not as a component or building block of the Critical Clearance Zone.
Under R10, there may be other methods for consideration of assessing reliability significance of the sub-200 kV lines other than what is
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listed. Suggest the Drafting Team consider other criteria that an RC should consider in its processes.
R10.2 is redundant with R10.1. IROL by definition are those operating limits that represent instability, uncontrolled separation or
cascading. Suggest removing R10.2.
Under M1.3 the measure requires the annual plan to cover a calendar year. An annual plan may cover a cycle growing season to
growing season using the inspection to verify the next seasons work.
Suggest removing the language for calendar year.M5, M6, M7 The measures should be requesting the evidence that it has violated the
requirements. Good standing programs should not have to defend good practice by providing useless reports. The FAC-003-1 existing
requirement R4 for reporting sustained outages is a reasonable and sustainable method that should be retained.R10 should include a
periodic review period of annually. Any requirement to maintain current documentation should have a review period.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The essential changes are: The CCZ concept has been replaced with the concept of minimum clearance distances, and
Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time.
Under M10 (now M11) the language now allows the criteria used in planning studies and analysis to be acceptable measures for R10 (now R11).
The redundancy in 10.1 and 10.2 you found has been removed.
The reference to the calendar year that was in M1.3 has been removed.
M5, M6, M7 language has been changed. These measures now rely on the certification reports to the RE reporting will occur for both full compliance
and any violations. The revised standard includes data retention periods as well as more detailed compliance information.
Western Area Power
Administration, Rocky
Mountain Region
1. Further clarification of the definition of the active right-of-way appears to be required. For example, if a tree falls from an area
controlled by the utility which is outside of the normal width of the actively managed right-of-way, but this area is not reserved or
"intended for other facilities", could this be a violation of a Standards requirement? The narrative discussion within the white paper
seems to imply that it is not, but the "intended for other facilities" requirement within Standards definition implies that it would be.
2. As currently presented, FAC-003-2 requires an impractical and unrealistic level of performance from the industry. This level of
performance is unwarranted for the overwhelming number and expanse of transmission facilities to which the Standards are applicable.
Many of these facilities, such as radial load lines, are not critical Transmission OwnerT or IROL facilities and have a minimal impact on
overall grid reliability. The rigorous zero tolerance level of performance is only warranted for those lines that are critical Transmission
OwnerT or IROL facilities.
3. The Standards should clearly identify any and all reporting requirements.
Response: The SDT thanks you for your comments.
1. The definition of the Active Transmission Line Right of Way states it is “A strip of land that is occupied by active transmission facilities. This corridor
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does not include the inactive Right of Way or unused part of the Right of Way intended for other facilities.” This definition is not limited only to those
parts of the Right of Way intended for other facilities. The SDT has also further clarified the concept in the white paper.
2. Due to the directive given by FERC Order 693 your suggestion for removing some lines above 200 kV from the Standard’s Applicability was not
considered. (Excerpt from order 693 paragraph 706 “we did not intend to make this Reliability Standard applicable to fewer facilities than it currently is
with the 200 kV bright line applicability, but to extend the applicability to lower-voltage facilities that have an impact on reliability”).
3. Reporting requirements are included in standard in the second posting.
Progress Energy
Carolinas
To avoid interpretation errors and provide clarity, the Applicability section for Facilities (4.2) of FAC-003 should include a statement that
the standard only applies to vegetation within the Active Transmission Line Right of Way. For example, a fall-in from outside of the
Active Transmission Line Right of Way that causes a sustained outage is not a violation of this standard. Any encroachment/outage
initiated by vegetation falling from outside of the Active Transmission Line Right of Way should be excluded from violations. The Critical
Clearance Zone concept is academically elegant, but when applied in the field, it presents significant implementation, interpretation and
enforcement issues: the complexity of determining compliance could have the unintended negative consequences to reliability; removal
of vegetation will likely be delayed because of the complexity and accuracy required to determine compliance prior to tree removal;
certification that no violations have occurred will require lengthy and costly calculations and survey measurements; the standard refers to
Ratings in the determination of line sags and Ratings is not a tightly defined term, PRC-023 requires relays to hold lines in beyond the
line Ratings; how will PRC-023 requirements be factored into the Critical Clearance Zone concept. The Critical Clearance Zone
concept introduces more complexity and ambiguity into the standard than it resolves. The drafting team needs to develop an alternative
to the Critical Clearance Zone concept that is simple, easy to apply and clearly defines at what point a violation occurs. There are over
158,000 line miles of AC Transmission above 200kV in the United States, covering a Right of Way area potentially as large as 3,000 to
4,000 square miles (an area roughly equivalent to Rhode Island and Delaware combined). With billions of stems of managed vegetation,
in and along the right of way, even six-sigma performance would result in a number of outages on a system this large. With countless
VM processes and assessments that take place daily, it is unrealistic/unreasonable to expect zero-tolerance for random vegetation
events (the transmission system is planned/operated to handle at least any single contingency).
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The essential changes are: The CCZ concept has been replaced with the concept of minimum clearance distances, and
Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time.
The exclusion you request for vegetation falling through the MVCD, regardless of its being form inside or outside the right-of-way, has been added.
Due to the industry impact that arises from zero tolerance for vegetation-related sustained outages, the Drafting Team tried several approaches but
could not find a mechanism in the standard development process to establish a non-zero threshold for outages that was acceptable to FERC staff,
because Standard revisions may not lead to less emphasis on reliability.
The PRC-023 Standard seeks to ensure that transmission protective relays are properly set such that they do not trip a transmission element
unnecessarily. This FAC-003 Standard seeks to prevent vegetation related Sustained Outages by requiring Transmission Owners to maintain their
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Active Transmission Line Rights of Way to be sufficiently clear. These two Standards are not mutually exclusive nor conflict with each other.
Southern California
Edison Company
SCE notes that Section C (Compliance) is incomplete and that the associated levels of Non-Compliance listed in FAC-003-1 may be
different from those proposed for FAC-003-2. SCE reserves the right to revise its initial comments and submit additional comments
regarding the requirements, measures and compliance portions of FAC-003-2.
Response: The SDT thanks you for your comments. Draft 2 will be a complete Standard for you to review.
SERC OC Standards
Review Group
The SERC OCSRG recommends that the definition of "Active Rights of Way" be revised as follows: "A strip of land, designated by the
Transmission Owner, that is occupied by active transmission facilities. This corridor does not include the inactive or unused part of the
Right of Way set aside by the Transmission Owner for other facilities or uses." The SERC SOSRG recommends that this standard
should exclude radial to load facilities and, for consistency, all 200 kV and above lines should not be included in the standard unless they
meet the same requirements as sub 200 kV lines.
Response: The SDT thanks you for your comments. The SDT opted to retain the “bright line” of 200kV without further qualifications such as radial to
load transmission facilities, due to the directive given by FERC Order 693 (paragraph 706 “we did not intend to make this Reliability Standard applicable
to fewer facilities than it currently is with the 200 kV bright line applicability, but to extend the applicability to lower-voltage facilities that have an impact
on reliability”.
Western Utility Arborists
Any standard that is developed should not contain advisory-type language? it should be declarative in tone. For example, in R1.4, the
ending clause that begins “and may include actions” should be removed because it is advisory in nature. The suggested actions are not
even the responsibility of the vegetation management program.
ADDITIONAL COMMENTS We have prepared, and will submit via email, additional comments regarding our online submission. If the
ability to submit them electronically is not available on this website, we will send the complete document via email to Harry Tom and
would ask that it be reviewed and considered by the drafting team.
Response: The SDT thanks you for your comments. The phrase in R1.4, “and may include actions” has been removed from the revised standard in
support of your suggestion.
Please refer to the various responses to your comments provided in the individual questions. The changes to the standard in this reposting and the
responses to your comments on questions 1-17 are intended to serve as a reply to your various comments.
Florida Power & Light
FPL believes the Vegetation Management standard should concentrate on grow-in tree issues that contribute to cascading or blackout
events as stated in the purpose statement. Fall-in trees from either on or off ROW do not in-and-of themselves cause cascading or
blackout events. Transmission systems are appropriately designed to handle incidental outages under N-1 conditions which are the
case in fall-in type outages. Requirements relating to fall-in and blow-in outages (R6 and R7), which deal with incidents resulting from
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force majeure or acts of God, should be removed to allow resources to be allocated to addressing events related to grow in interruptions.
Because of an utter lack of control or such situations, no Standard or regulation places a duty on one to control force majeure or acts of
God, yet that is precisely what R6 and R7 intend to do. If R6 and R7 stay in its current form, this will be yet another reason why this
Standard as written will be unenforceable. FPL recommends the following approach. The entire US Transmission system was built
under the National Electric Safety Code (C2). That code uses the Reference Component as the initial building block for establishing the
lowest height of a conductor for all operating and designed environmental conditions. Over most open land this distance is 14 feet. FPL
recommends creating a new requirement to clearly define a trimming standard. New Requirement At time of trimming, trees under
conductors should be trimmed or removed so that the average growth would remain below the Reference Component of Rule 232 in the
National Electric Safety Code C2. The wire zone should extend to the blowout distance calculated at 39 miles per hour (Fresh Gale) not
to exceed the Active Transmission Right-of-Way. Where the Transmission Owner can not achieve that clearance, they shall have a
permanent (ex. raised conductor) or interim (ex. short trim cycles) corrective action plan in place to prevent tree wire conflicts.
Permanent corrective action plans should reside in the Transmission Owner's vegetation program record keeping system (database) for
application when that line is maintained or inspected. Trees to the side of the ROW should be maintained at the edge of the Active
Transmission Right-of-Way. The value in this approach is in its application by arborists and tree trimmers in field conditions. This
approach is clear and measurable without a surveyor or an engineer present. The line design calculations were made to the NESC
Standard at the time the line was built and incorporate all potential conductor locations within its flight path. As it stands now if there is a
violation to R4, R5, R6, or R7 it is already too late. The standard should seek to identify and correct poor performers before they create
a reliability threat to the system. In the field, a poor performer has many trees close to the line and will have to do many emergency cuts.
It will also have more momentary interruptions before it has a single Sustained interruption. Sustained Interruptions have a history of
contributing to cascading and blackout events. The standard should measure performance and penalize poor performance. The changes
below reflect performance measurements with a graduated penalty applied to the metric.
Change R2 to read
Each Transmission Owner shall implement its Imminent Threat procedure when the Transmission Owner has knowledge, obtained
through normal operating practices or notification from others, that the tree / conductor distance is less than the minimum clearance
distance as specified in Table 2 of ANSI Z133.1-2006 (the minimum approach distance for qualified line-clearance arborists or qualified
line-clearance trainees). Transmission Owners are to document and report activation of the Imminent Threat Procedure for violation of
Table 2. Activation of the Imminent Threat Procedure for other causes shall not be reportable.
The Violation Severity level should read: Activation of the Imminent Threat Procedure for encroachment of Table 2 of ANSI Z133.1-2006
(the minimum approach distance for qualified line-clearance arborists or qualified line-clearance trainees) has the following severity level:
Lower ? Greater than 5 per 1000 miles of line and less than 7
Moderate ? Greater than 7 per 1000 miles of line and less than 9
High - Greater than 9 per 1000 miles of line and less than 13
Severe - Greater than 13 per 1000 miles of line
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Trees inside of Table 2 can only safely be trimmed under a clearance from the system operator, using special techniques under a line
right of way from the system operator, or by a lineman with a live line permit from the system operator. No utility wants to let a tree get so
close to energized lines such that it has to take the line out of service for a tree trim. It should be noted that Table 2 represents an
established industry standard which is normally found placarded on the side of every tree trimming easement truck and bucket truck. It is
minimum knowledge for every qualified line-clearance tree person under OSHA regulations. This is a distance that field personnel
understand.
New R5 to read: Each Transmission Owner shall minimize Momentary Outages of applicable lines due to vegetation growing into a
conductor with the following exceptions:? Sustained Outages of applicable lines that result from natural disasters.? Sustained Outages of
applicable lines that result from human or animal Activity. The Violation Severity level should read:
Lower ? Having Momentary Outages Greater than 3 per 1000 miles of line and less than 6
Moderate ? Having Momentary Outages Greater than 6 per 1000 miles of line and less than 8
High - Having Momentary Outages Greater than 8 per 1000 miles of line and less than 12
Severe - Having Momentary Outages Greater than 12 per 1000 miles of line
New R6 to read:
Each Transmission Owner shall minimize Sustained Outages of applicable lines due to vegetation growing into a conductor with the
following exceptions:? Sustained Outages of applicable lines that result from natural disasters.? Sustained Outages of applicable lines
that result from human or animal Activity.
The Violation Severity level should read:
Lower ?
Moderate ?
High - Having Sustained Outages Greater than 1 per 1000 miles of line
Severe - Having Sustained Outages of 2 or greater per 1000 miles of line
These VSL's listed above constitute a strawman for discussion. The drafting team could request historical performance data from
Transmission Owners to statistically evaluate where the VSL should be set. As time progresses, future performance data could be reevaluated to reset the limits. These changes bring the standard back in line with measurable and auditable requirements which provide
practical field measurements to the personnel who can make the difference. These parameters provide measurements to indicate the
tree health of the system. On a separate note, FPL believes that clarifying information captured in footnotes within the standard should
specifically be referenced and made part of the standard. These notes add clarity and better define the standard requirements.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
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industry comment. The essential changes are: The CCZ concept has been replaced with the concept of minimum clearance distances, and
Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time.
The Drafting Team reviewed the exclusion in R6 and R7 and reached consensus that the stated exclusions are adequate to exclude force majeure or
acts of God.
This posting includes under R1 the new section 1.6. That would make the proposal you offer related to maintaining the height of trees above ground
level to be a method for the TO to select. The language also allows TOs to select a separation distance between the conductor and the vegetation.
When lines traverse terrain with significant changes in elevation within spans the latter method may be more practical.
Changes made to utilize the MVCD as observed in real time will provide the clarity and measurability you requested.
R2 has been revised to ensure that the process is used only for conditions that require immediate actions to prevent a sustained outage. Other factors
which under some conditions would not pose an imminent threat of a sustained outage were purposely omitted to provide clarity and consistency of
application.
Since R2 is binary requirement its VSL cannot be gradated as you suggest.
R5 has been left as a binary requirement with a zero tolerance in lieu of a gradated metric in the requirement as you suggest. Due to the industry
impact that arises from zero tolerance for vegetation-related sustained outages, the Drafting Team tried several approaches but could not find a
mechanism in the standard development process to establish a non-zero threshold for outages.
Momentary outages are purposely not included because of the challenges they pose during investigation. These problems often lead to unreliable,
inconsistent, false, or missing reports. Furthermore momentary outages caused by vegetation have not been a historical cause of cascading or
widespread outages.
Santee Cooper
The SDT should clarify that Transmission lines operated at 200 kV and above is for lines that are network facilities. Radial load
transmission facilities operated at 200 kV and above should not be subject to this standard as they would not lead to SOLs or IROLs.
M2 requires evidence that a Transmission Owner implemented its imminent threat procedure upon knowledge of a Critical Clearance
Zone breach. M4 requires evidence that there were NO encroachments into the Critical Clearance Zone. These two measures are in
conflict with one another. If a utility provides evidence for M2 then they are in violation based upon M4.M4 and M5 requires a utility to
provide "proof to the negative". These measures should be removed from the standard.
R10, R11, M10, and M11 should be removed from this standard as critical facilities are identified through the PRC standards.
Response: The SDT thanks you for your comments.
Regarding your request to line applicability to only network lines above 200 kV FERC in order 693 paragraph 706 stated “we did not intend to make this
Reliability Standard applicable to fewer facilities than it currently is with the 200 kV bright line applicability, but to extend the applicability to lowervoltage facilities that have an impact on reliability”. The standard drafting team therefore does not see that honoring your request as one that would be
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permissible.
Regarding the conflicts you cite between M2 and M4, please note the revisions in this posting for R2, R4 and the associated measures. The conflict you
reference should now be resolved since the distance in R4 is not the exclusive basis for implementing R2 and the concept of the “CCZ” has been
removed from the revised standard.
In M4, the language is now changed to remove the “proving a negative” dilemma.
There is a 200 kV bright line for applicability in this standard; therefore it is appropriate for the applicability for sub 200 kV lines to be determined within
this standard in lieu of the PRC standards.
Significant changes have been made to the current draft of the Standard based upon substantive industry comment. The essential changes are: The
CCZ concept has been replaced with the concept of minimum clearance distances, and Transmission Owners are required to prevent encroachment of
vegetation into minimum vegetation clearances distances as observed in real time.
Southern Company
We would like to re-emphasize our concern over the zero tolerance philosophy of FAC-003-1 which is continued in this proposed
revision. FAC-003 has been singled out as the only zero tolerance NERC standard. Compliance should not be based on the
encroachment of vegetation into a theoretical, pre-defined zone, but on the occurrence of a sustained outage, as stated in the
document's Purpose Statement. We agree with the philosophy utilized in other NERC standards where a clearly discernible compliance
event signals a review of the Transmission Owner's plans, policies, and procedures to determine the effectiveness of the entity's
programs and spirt toward compliance.
Applicability Section 4.2 describes the Facilities pertinent to this Standard. Recommendation is to restructure the sentence by relocating
the parenthetical phrase: Transmission lines operated at 200kV or higher, and transmission lines operated below 200kV designated by
the Reliability Coordinator as being subject to this standard (“applicable lines”) including but not limited to those that cross lands owned
by federal, state, provincial, public, private, or tribal entities.
Requirement R3Recommend rephrasing to say: Each Transmission Owner shall conduct vegetation inspections of all applicable lines in
accordance with the frequency specified in its transmission vegetation management program.
Requirement 10The standard does not mention whether or not the results of this specific assessment methodology are supposed to be
compiled and maintained. The resulting information could be labeled as sensitive and possibly critical since the loss would place the grid
at an unacceptable risk of instability, separation, or cascading failures. If the resulting information becomes auditable (subject to
discovery and posting) then precautions must be taken that are comparable to those designed to preserve the integrity of critical assets
or critical cyber assets. We would like to express our sincere appreciation and thanks the drafting team for their efforts.
Response: The SDT thanks you for your comments.
Due to the industry impact that arises from zero tolerance for vegetation-related sustained outages, the Drafting Team tried several approaches but
could not find a mechanism in the standard development process to establish a non-zero threshold for outages that was acceptable FERC staff
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because revisions to a Standard may not lead to less emphasis on reliability.
The standard has been revised to remove the violation for encroachment into a theoretical zone and is now based on an observed encroachment in real
time inside a distance where flashover becomes a possibility.
The Drafting Team considered the applicability wording with the (“applicable lines”) to be acceptable as written.
R3 has been revised as you recommended.
The Drafting Team agrees that documentation regarding the methodology used to determine applicability of lines below 200 kV should have similar
precautions for confidentiality as other critical assets or critical cyber assets.
The issue of transmission line applicability is addressed in FERC Order 693.
Bonneville Power
Administration
There is a typographical error / omission in the Technical Reference on Page 36, which states, "R6. Each Transmission Owner shall
prevent Sustained Outages of applicable lines due to the blowing together of vegetation and a conductor with (sic) Active Transmission
Line Right of Way) operating within design blow-out conditions) with the following exception: . . . " I believe the intent is for the statement
to read "due to the blowing together of vegetation and a conductor WITHIN Active Transmission Line Right of WAY". This change is
needed to make the technical reference consistent with R6. as it appears in the Standard, the definition of Active Transmission Line
Right of Way on Page 5 of the Technical Reference, as well as the terminology used on Page 37 in describing Fall-into outages. This
needs correction.
Response: The SDT thanks you for your comments. The technical reference error is noted and has been corrected by the SDT.
Public Service Electric
and Gas Company
These comments were prepared by Richard Wolowicz, Manager Vegetation Management, on behalf of Public Service Electric and Gas
Company ("PSE&G"). PSE&G also joins with and supports the comments filed by the Edison Electric Institute (EEI) in this matter.
Response: The SDT thanks you for your comments. Please see our response to EEI.
FirstEnergy
FE provides these additional comments for consideration:
1. Regarding the Applicable Facilities - Section 4.2.2 would be more appropriately placed under Sec. 5 "Effective Dates" since it deals
with the timeframe the Transmission Owner has to implement its Transmission Vegetation Management Program on sub-200 kV lines.Section 4.2.3 - We suggest removing this section. First energy does not agree that this standard should dictate the amount of time a
Transmission Owner has to obtain compliance with this standard for newly acquired transmission lines. It should be the responsibility of
every organization to "self-report" its compliance issues and planned mitigation plans for all standards when they acquire new lines or
facilities. If the SDT believes this should be explicitly stated, then it should recommend to NERC that explicit language be placed in the
NERC Rules of Procedure. No other standards set timetables for newly acquired facilities and this standard should be no exception.
2. Regarding R1.1, this subrequirement requires the Transmission Owner to specify the methodologies it uses to control vegetation. It
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should be clear that not all of these methodologies are required to be deployed in every situation (as explained in the white paper pg.12).
We suggest rewording the requirement as follows: "R1.1. Specify the methodologies that the Transmission Owner may use to control
vegetation."
3. R1.5 requires a process for "interim corrective action" be specified in the Transmission Vegetation Management Program. However,
the standard does not explicitly specify that this corrective action be implemented when the Transmission Owner is constrained from
performing vegetation maintenance as planned.
4. As written, in addition to the responsible RC, R10 may imply that this requirement is also the responsibility of the Transmission
Owner(s) and neighboring RC(s) due to the use of the term "jointly". Also, R10 should require the RC submit the list of designated lines
below 200 kV to the Transmission Owner(s) and neighboring RC(s) within a reasonable time-frame after its completion. We suggest
rewording and addition of subrequirements to R10 as follows:
R10. Each Reliability Coordinator, in consultation with its Transmission Owner(s) and neighboring Reliability Coordinator(s), shall
prepare and keep current a list of designated applicable lines that are operated below 200kV, if any, which are subject to this standard.
R10.1. The RC shall submit the list to the impacted Transmission Owner(s) within 30 calendar days of completion and/or revision.
R10.2. The RC shall submit the list to its neighboring RC(s) within 30 calendar days of completion and/or revision. Lastly, measure M9
will need to add sub-measures for the proposed additions above.
5. Requirement R10 should require that the RC ONLY uses the assumptions detailed in R10.1 and R10.2 to designate a line as
significant. Also, R10.1. should reference the IROL methodology standard FAC-011 since it directly ties into this requirement. Also, in
R10.2, "grid" should be replaced with "BES" and the term "failures" is not necessary. We suggest re-wording R10, R10.1 and R10.2 as
follows:
R10. Each Reliability Coordinator shall document its method for assessing the reliability significance of sub-200kV lines and shall be
based only on the following:
R10.1 Transmission lines whose loss would result in the exceedance of an Interconnection Reliability Operating Limit (IROL) as
determined by standard FAC-011.
R10.2 Transmission lines whose loss would place the BES at an unacceptable risk of instability, separation, or cascading.
Response: The SDT thanks you for your comments.
The placement of Section 4.2.2 was chosen to allow the TO time to bring those lines into compliance which are identified by future studies well after the
effective dates in Section 5.
The SDT chose to leave Section 4.2.3 as it does provide a reasonable time allowance (limitation) to bring the subject lines into compliance. {note for a
newly acquired line to have not previously been subject to the standard it may have been 1) owned and operated by a private entity such as a mining
company that was not connected to the grid, 2) was a de-energized line not in operation until it was acquired by the TO, 3) was previously operated at
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less than 200kV but was insulated for an operated at 200kv or higher, or 4) some similar situation to 1-3 above} The SDT sees this Section as following
the Rules of Procedure Standard Applicability Section as noted on page 9 to “identify any limitations on the applicability of the standard based on
electric facility characteristics”.
The SDT modified Requirement R1, Part 1.1 as suggested. The standard does not explicitly state that the interim corrective action process in 1.5 must
be implemented. The SDT suggests that the other requirements in the standard related to outages and imminent threats and encroachment provide
necessary and sufficient incentives for TOs to utilize the process when and if required.
R9 and R10 (now R10 and R11) have been revised to replace the RC with the PC as the applicable functional entity. The verbiage “in consultation with”
has been replaced by “shall consult with its Transmission Owner(s) and neighboring Planning Coordinators to obtain input to develop the list”. Since
this list is prepared by the PC for the TO to know of any sub 200 kV line(s) that the TO must maintain, the SDT does not see a benefit to adding a
requirement that the PC will provide the list to the TO.
The SDT chose to keep the word “grid” in lieu of BES to avoid confusion related to the fact that the BES generally includes all lines above 100 kV as
defined by the Regional Reliability Organization and this standard does not.
Other changes were made in the language of R9 and R10 to which incorporate parts of recommendations from other commenters and FE. Requirement
R10, Parts 10.1 and 10.2 were redundant, and Part 10.1 was deleted and Part 10.2 was translated into a separate requirement, R11.
Midwest ISO
Stakeholders Standards
Collaborators
FAC-003-1 lacks clarity that is essential for understanding what is necessary for compliance. The proposed FAC-003-2 needs to be
simplified to aid with field implementation and compliance interpretation. Currently, it does not provide the clarity and simplification
needed by Transmission Owners and regulatory bodies to enhance reliability.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The essential changes are: The CCZ concept has been replaced with the concept of minimum clearance distances, and
Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time.
These changes should add the clarity and simplification that your and other commenters suggested was needed for field implementation.
SERC Compliance Staff
SERC staff continues to find the Applicability section of the standard to be confusing and contentious. While we recognize it is the intent
this section to make the standard applicable t all entities that own transmission lines that operate at greater than 200 kV, this section
should not be written to be applicable to transmission lines. Only registered entities can be held accountable for compliance with the
standards. SERC staff believes the applicability should be rewritten to include Transmission Owners, Distribution Providers, and
Generation Owners that own transmission lines with the characteristics defined in Section 4.2. This would eliminate the need to make
register, for example, a Distribution Provider that own a 230 kV line that serves load as a Transmission Owner and make them subject to
the requirements of FAC-001 and FAC-002. SERC Staff also suggest the applicability could be handled as it is in PRC-005-1 where the
applicability is qualified as 'distribution provider that owns..' and 'generator owner that owns..' or in a similar manner that captures the
appropriate subgroup but does not include unintended entities.
SERC Staff believes a flashover between vegetation and overhead ungrounded supply conductors that occurs, whether or not the
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flashover results in a Sustained Outage, is clear evidence of an unallowable encroachment of vegetation into the space that should be
avoided and thus should be identified as evidence of a violation of the standard. SERC staff has also found that excluding outages
resulting from "earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the
Transmission Owner?" results in inconsistencies in reporting because of the inconsistency of the Transmission Owners' definitions of
same. If such exceptions are to be allowed, a consistent method of determining the acceptability of those exemptions should be
pursued.
Response: The SDT thanks you for your comments.
The intent of the Facilities section under Applicability which you suggest is confusing and contentious, was chosen to follow the Reliability Standards
direction under Applicably, specifically “if not applicable to the entire North American bulk power system, then a clear identification of the portions to
which the standard applies…”
The issue you raise with respect to Distribution Owners and Generation Owners does not appear to be supported when one reviews the definition of a
Transmission Owner in the NERC Glossary “The entity that owns and maintains transmission facilities.” The SDT is concerned that your suggestion
will add confusion to the standard.” PRC-005-1 properly addresses the coordination needed between transmission protection and the interface with
distribution protection at the point of transformation. There is no comparable expectation for vegetation maintenance on the low voltage side of a
transmission to distribution transformer to be subject to this standard. Simply put, either someone owns transmission or does not. It is of no matter
whether they may also be a DP or GO. Until the functional model includes provisions to state that “all transmission is not equal”, the applicability
should remain.
Your concern about flashovers that do not result in Sustained Outages needing to be stated as violations of this standard has been discussed at length
by this SDT. The interest is to have a Standard that is not subject the levels of uncertainty associated with any automatic operation which is returned to
service by either manual or automatic means. These events are very often not possible to identify, many times misidentified often occur during
conditions that have several possible explanations (such as high winds blowing conductors together, wind-blown debris, lightning, contamination
flashovers during the onset of wind and rain storms) and do not have a historical basis for ever creating a cascading event. Inclusion of these events
as violations in the standard could also cause significant additional costs for extensive investigations by TOs to prove their “innocence” for events that
any properly designed and operated transmission system should withstand with no more challenge that the far greater number of lightning, and
equipment failure events (cross-arms, insulators, conductor splices, poles) nor ever been the subject of momentary opera being.
Members of the SDT attempted to get the TADS reporting requirements to clearly identify those faults on transmission lines that required maintenance
to return the line to service. If such a definition was entertained, then a great deal of the uncertainty is cleared. However there are still conditions
where trees and poles are found down after apparent high wind conditions in locations remote to the nearest weather reporting station that depend on
assumptions as to which fell first the pole or the trees. The zero tolerance nature of this standard and the Penalty Matrix values should not be tied to
anything with a high degree of assumption and uncertainty. Therefore the standard has been revised and worded to have the violation of MVCD as
observed in real time.
As an added note there is unnecessary confusion caused by simply labeling the automatic operation line operations as momentary, sustained, and/or
locked-out. If a line is not reclosed within moments of the automatic interruption, but is later “test closed” was the line truly unavailable? Was the
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reclosing signal/command properly performed initially? Did the TOP ever truly lose control of this line if all that was required was another close
attempt? The true nature of the loss of a line is manifested when it is known that a clearance must be issued such that the line is removed from the
TOP’s control.
The SDT has reviewed the data on vegetation related reported outages on the NERC website. There are 223 reports of outages in that data covering the
period January 2004 to March 2009. The associated documentation with these events indicate that TOs are supplying supportive information to
indicate that the level of any disaster exclusion is sufficient to identify that design criteria was exceeded. Further specifics on the threshold for each
disaster would not ensure that weather data would be adequate to support each location/situation.
ITC HOLDINGS
V1 was a better written standard and had clear requirements on reporting and who was to report violations etc. When and how are
violation to be reported is not mentioned in the V2. The standard should clearly identify all reporting requirements. Standard
development should focus on practicality for the field personnel in terms of implementing the standard and enforceability. Version 2 is not
as user friendly for field personnel and ambiguous at best which requires an impractical and unrealistic level of performance from the
industry. This standard needs to stress that it applies to vegetation within the Active Transmission Right of Way. Vegetation from outside
the active ROW, falling through the Critical Clearance Zone should not be a violation. V2 needs further clarification of the definition of
the active ROW.
Response: The SDT thanks you for your comments. The issue of reporting has been addressed in the compliance section of the revised standard.
The changes made to R4 focus on the practicality for field implementation that you suggest. The exclusion you request for vegetation falling through
the MVCD, regardless of its being form inside or outside the right-of-way, has been added.
The definition of the active right of way was debated at length and determined to be best stated in its current form.
Exelon
Applicability. 4.2.2 is unclear. If 4.2.2 is intended to cover Generator Owner interconnections, say so uniquivocally. Do not rely on future
changes to the NERC Registry Criteria or other "global" solutions if the intent is to make the standard applicable to Generation Owners
who own generator leads.
Exelon would like to reemphasize our concern with implementing the requirements if the Gallet equation derived Critical Clearance Zone
is used. ANSI A300 part 1 and part 7 should be part of the standard as they provide independently recognized valid methods and
guidance to conduct maintenance on the ROW corridor.
Response: The SDT thanks you for your comments.
The issue you raise with respect to Generation Owners does not appear to be supported when one reviews the definition of a Transmission Owner in
the NERC Glossary “The entity that owns and maintains transmission facilities.” The SDT is concerned that this suggestion to add the Generation
Owner will add confusion to the standard.” The SDT does not agree there is ambiguity. Either an entity is a TO or not.
The Gallet Equations distances were chosen in lieu of ANSI A300 for clearances because the Gallet is a distance that is necessary to prevent flashover.
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The ANSI values are related to worker and public safety not flashover between the conductor and the vegetation.
Central Maine Power
Company
The White paper is an important support document and should remain as an attached reference to FAC 003. The white paper should
clarify that capable tree species should always be removed from the border zone, except in selected areas where topography includes
deep ravines.
Response: The SDT thanks you for your comments. The standard was designed to allow the Transmission Owner the flexibility to design its TVMP.
Further, ANSI A300 is also footnoted in the standard as a “best practice”. The White Paper will remain a reference for this Standard and text has been
added to try to provide additional guidance as you suggest.
American Electric
Power (AEP)
The definition for Critical Clearance Zone (Critical Clearance Zone ) on page 2 of the proposed draft Standard does not specify the
Rating (summer, winter, normal, emergency, etc.). This suggests that different Critical Clearance Zone s apply at different times of the
year and thus that vegetation in the area might be outside the Critical Clearance Zone at certain times of the year and inside the Critical
Clearance Zone at other times. AEP suggests that this may not have been the intent of the drafting team.
Also, the term "design blowout" is not defined; thus, it appears that it will be up to the Transmission Owner and the auditor to determine
the bounds of the Critical Clearance Zone . AEP again suggests that this may not have been the intent of the drafting team.
Requirement R9 contains the clause "within the extent of its easement and/or legal rights". This intent of this clause is unclear and its
rationale is not obvious. AEP suggests that this clause be removed or at least reworded for clarity.
Response: The SDT thanks you for your comments. The CCZ concept has been replaced with the concept of minimum clearance distances, and
Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time. The
verbiage you suggested removing form R8 (now R9) was removed. Finally, the new Requirement R1 should address the concern about sag and blowout
in that it talks about planning to keep vegetation out of all positions the conductor may be for all design conditions.
Platte River Power
Authority
The white paper ensures consistent interpretation of the standard. Perhaps the lack of such a paper in the first version of the standard
contributed to the varying interpretations.
Response: The SDT thanks you for your comments. The White Paper will accompany this Version as a Reference document.
City of Tallahassee
Attachment I. Titles are different between page 8 and 9. Page 8 should have (D) after Distances. Page 9 should have indication that it
is "continued" since the table spans multiple pages.
Response: The SDT thanks you for your comments. The SDT has reformatted the table in Attachment 1 of the Standard.
Northern California
Section A. 5. Effective Dates: This is extremely vague and I would not know the actual effective date. Whose regulatory approval is
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Power Agency (NCPA)
needed? If this is meant to leave flexibility between FERC and the Canadian entities, please write it that way. Most effective dates are
clear and concise, i.e., "the first month following approval by FERC". Let's clear this up and avoid a subsequent interpretation request.
Response: The SDT thanks you for your comments. The wording of this portion of the standard (the Standard’s effective date) is governed by NERC
policy. The process for approval is different in different jurisdictions – some Canadian Provinces approve a standard when it is approved by the NERC
Board of Trustees, other Provinces have other mechanisms for approving standards. For entities that operate in the United States, the FERC is the
regulator that must approve the standard. As written, the standard will become effective in the United States the first calendar day of the first calendar
quarter one year after FERC approval.
Northern Indiana Public
Service Company
While I very much respect the industry commitment and expertise of the drafting team members, the resulting revised standard reflects
an effort to "revolutionize" the standard, when an "evolution" of the current standard would better serve the interests of system reliability.
The kinds of wholesale changes proposed in this revision evoke real concerns about governmental regulations being a moving target
and in many aspects, backs away from requirements that have led to real progress in UVM made since the 2003 blackout. For example,
our company has invested tens of thousands of dollars and countless man-hours to comply with provisions of the existing standard only
to see them simply done away with under the proposed revised standard. These investments were made based on an industry
consensus standard as well as a realization that the requirements were reasonable and essential to improving system reliability. Where
is the evidence that the current standard is not working as intended? What has changed in the last few years to warrant a complete rewrite of the current standard? Most UVM professionals will agree there are some changes that need to be made to address FERC's
concerns and to clarify intent. However, as presently written, I will recommend our T.O. vote against adoption of FAC-003-2.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The essential changes are: The Critical Clearance Zone concept has been replaced with the concept of minimum clearance
distances, and Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in
real time. Moreover, certain language changes were needed to comply with directives in FERC Order 693. The changes proposed are meant to
capitalize on programs already implemented, not to discard them.
Tampa Electric
Company
Good start. However, this will need additional work and review predicated on the above comments.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The essential changes are: The CCZ concept has been replaced with the concept of minimum clearance distances, and
Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time.
Orange and Rockland
Utilities Inc.
Clearance 1 has been eliminated from this draft. Version 2 as drafted only requires that Transmission Owners address vegetation that
approaches the Critical Clearance Zone . This is essentially equivalent to Clearance 2 in version 1, a minimum clearance. Although
unlikely this could result in some Transmission Owners adopting a just in time vegetation management concept that focuses on
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maintaining minimum clearances, rather than removing incompatible vegetation or achieving greater clearances. Although R1 requires
Transmission Owners to design their Transmission Vegetation Management Programs to control vegetation there is no clear
requirement to address incompatible vegetation early and aggressively. The drafting team should revisit this and consider returning to
some form of Clearance 1 or requiring the Transmission Vegetation Management Program to address removal of incompatible
vegetation within their easement rights.
Response: The SDT thanks you for your comments.
The SDT did revisit and reconsider reinserting a Clearance 1. The issue of how and when to remove or control “incompatible vegetation” was also
revisited. The SDT decided to leave C1 and the methods to control (or remove) “incompatible vegetation” to the discretion of the TO. Such
discretionary measures do not meet the qualifications to be a requirement within a standard.
Please take a comprehensive look at all the requirements in the standard we are now re-submitting with this posting. Compliance with these
requirements will ensure that the TO maintained vegetation such that 1) no controllable sustained interruptions have occurred, 2) no imminent threats
were left unaddressed, 3) all the separation distances between the conductors and vegetation every time they were observed were greater than the
distance necessary to prevent a flashover.
Compliance with each of the above requirements can be achieved with inspection and pruning cycles on a frequent basis such as annually, or on a
longer term basis such as every 4 years where warranted by local conditions. There are numerous examples in the industry of these different
approaches being both appropriate and effective. Just because a “shorter cycle” is utilized, does not mean that a compromised or “just-in-time”
concept is has placed the adequate level of reliability of the grid at risk.
American Transmission
Company
FAC-003-1 lacks clarity that is essential for understanding what is necessary for compliance. The proposed FAC-003-2 needs to be
simplified to aid with field implementation and compliance interpretation. Currently, it does not provide the clarity and simplification
needed by Transmission Owners and regulatory bodies to enhance reliability. Requirement 1.3: The proposed requirement does not
allow enough flexibility for making changes to the Annual Plan. We believe that changes to the Annual Plan should be allowed even if
that means delaying something until the next Annual Plan. Our Proposed Changes: Have an annual plan that identifies the applicable
lines to be maintained and associated work to be performed. Adjustments to the annual plan are permissible. We believe that our
proposed language accomplishes the SDT's intent while allowing for appropriate flexibility.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. Those changes, including the removal of the concept of the CCZ, address and provide the clarity and simplifications you suggest
are needed for field implementation of the standard. R1.3 has been revised for to provide clarity.
These R1.3 changes do not explicitly remove the “within the year” clause as you requested, however we do not see the inclusion of that language as
restricting appropriate flexibility. It is expected that the annual work plan will be flexible to adjust to changing condition and findings which occur after
the plan is first issued for the year, then adjusted within the year as appropriate. Adjustment made within a year may mean accelerating work to the
current year that was not in the current year’s plans as well as extending work that was initially planned for this year into the future. And when
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disasters occur, the SDT has addressed an appropriate extension.
Xcel Energy
Attachment 1, Table I- Change the title of the table from "Proposed Minimum Vegetation Clearance Distances" to "Critical Clearance
Zone Distances". The reason being is that the general public could interpret this table to mean that this is all the clearance that is
required by a utility at the time of pruning.
Section C, Violation Severity Levels- There is some inconsistency between the C.2 chart and the contents of the Standard and the White
Paper. For example, the White Paper specifies that an exception to an R6 blowing together violation would exist for sustained winds of
gusts of 45 miles per hour or greater.
As to R7, the Standard itself notes that a violation only occurs if the vegetation falling into the line is from within the ROW ? C 2 does not
incorporate that requirement. There are two approaches: either note the exemptions within the C 2 chart, or add a footnote to the chart
along these lines: "This chart summarizes various provisions, the details of which are more fully set forth in the Standard and White
Paper?. We would recommend the later approach.
General suggestions:
1) It appears that the FAC-003 Standard is the only "zero tolerance" standard, in some respects. Is this reasonable?
2) There appears to be "advisory" language in this version of the Standard. This type of language should be part of the White Paper, not
the Standard itself.
3) Utilities need more support from FERC to deal with regional roadblocks within the USFS regarding the implementation of IVM. The
Memorandum of Understanding is not universally accepted within all regions of the USFS.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment parts of those changes address or remove the issues you raise for exemption and footnotes for Table 1.
Table 1 in not intended to be used by TOs to determine how much to prune. This table provides the actual physical separation distances, which if
observed, will ensure that flashover from the line to vegetation will not occur. When conditions exist such that the separation is reduced the risk of
flashover will become significant. The risk increases as the separation is reduced. Therefore this value represent a threshold which if not violated will
prevent flashover, as such it is a valid physical basis for R4 compliance.
This standard allows the TO to use any combination of pruning, removals of vegetation at ground level, frequency(cycles) of planned maintenance,
enhanced inspections, off-cycle corrective maintenance, etc to prevent violations occurring due to vegetation causing a non-exempted sustained
outage or MVCD violation.
Due to the industry impact that arises from zero tolerance for vegetation-related sustained outages, the Drafting Team tried several approaches but
could not find a mechanism in the standard development process to establish a non-zero threshold for outages that was acceptable to FERC staff
because revisions to Standards may not produce less emphasis on reliability.
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The advisory language in R1.4 has been removed.
The SDT discussed with NERC and FERC the need for support with the USFS issues. The SDT concluded that FERC has no power to change the rights
or restrictions within any permit or easement document across privately owned or publicly owned.
Therefore any efforts to improve permits or reduce limitation on permits or easements on federal lands must be handled through other available
methods.
Ameren
While FAC-003-1 lacks clarity that is essential for understanding what is necessary for compliance, the proposed FAC-003-2 needs to be
simplified to aid with field implementation and compliance interpretation. Currently, it does not provide the clarity and simplicity needed
by Transmission Owners to implement and regulatory bodies to monitor in a manner that will enhance reliability.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. Those changes address and provide the clarity and simplification you suggest are needed for field implementation of the standard.
Long Island power
Authority
1) Disagree with R1.1. The proposed standard is too lenient on the program documentation required for an effective program. R1.1
should include the words " the program will document the program objectives, method of site evaluation, the definition of action
thresholds, the control methodologies, and how the monitoring program is established". There is a wide gulf between listing IVM
methodologies and a vegetation program implementing A300.
2) CHANGE: Within Applicable Facilities listed in section 4.2 the phrase Transmission Line should be changed to Overhead
Transmission Line. The NERC Glossary definition of transmission Line is: " A system of structures, wires, insulators and associated
hardware that carry electric energy from one point to another in an electric power system. Lines are operated at relatively high voltages
varying from 69 kV up to 765 kV, and are capable of transmitting large quantities of electricity over long distances." The accompanying
white paper states the standard is addressing the impact of vegetation growth on overhead transmission lines. The intent of this
standard is the development and implementation of a vegetation management program for overhead transmission lines only. By
specifically stating "overhead transmission lines in Section 4.2 there will be no possibility of an occurrence of an auditor requesting a
vegetation management program for underground lines.
Response: The SDT thanks you for your comments. In R1.1 the SDT chose to direct the TO to specify the methods used to control vegetation vs
specifying a menu of items that may not be applicable to several TOs due to the limited types of vegetation in their areas. The SDT considered the
issue of overhead versus underground and concluded that no further clarification was needed. Further, ANSI A300 is referenced in the Standard as a
best management practice. The SDT leaves up to the TO the extent to which it wishes to apply A300.
USDA Forest Service,
Southwestern Region,
Regional Office for AZ
and NM
I'm having trouble getting comments to "stick" in this section of the form. I have a general concern with the opening paragraph of R1.
The wording seems to encourage a Transmission Owner to develop a Transmission Vegetation Management Program in a vacuum.
The US Forest Service definitely wants input into the development of an annual work plan and USFS land use authorizations include a
requirement for USFS approval of vegetation management plans. It seems much more reasonable to require the Transmission
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Vegetation Management Program to reflect USFS or any other landowner resource management considerations. This tactic would
require more "up front" work, but the end result is a plan which would reflect reasonable landowner input and where the disagreements
could be settled ahead of time rather than being left for the night shift. I also believe that some kind of dispute resolution process is
needed outside the control of either the Transmission Owner or the USFS. I think that NERC could fill that role very well.
Response: The SDT thanks you for your comments. Underlying landowner rights are outside the purview of this Standard. However, the SDT
recognizes the value in “up front” input between landowners and transmission Owners. Notice that in this posting of the standard within Requirement
1 at 1.3.4 the transmission vegetation management program shall “take into consideration permitting and scheduling requirements from landowners
and regulatory authorities”. Such consideration should aid in addressing the issues you raise.
Consumers Energy
Company
The annual work plan should be designed to avoid vegetation growing into a violation of the Critical Clearance Zone or whatever
minimum distance is acceptable. Since the plan can change throughout the year, it needs to be flexible, it should be stated that the plan
at a minimum must provide adequate funding to prevent vegetation growth from violating the minimum clearance distance. The flexibility
of change should be limited to changing to address emergent needs for vegetation management and not reductions in funding that delay
maintenance in the hopes that additional funding at some future point in time will be adequate to remove the backlog of vegetation
maintenance. The Purpose of the standard should be revised to state "(To maintain minimum clearance sufficient to avoid any
vegetation-related Sustained Outages for all applicable conditions) for all Transmission Lines covered by this Standard" as provided by
FERC in Order 693, Paragraph 731. The purpose as stated in FAC-003-2 waters down the intent of FERC to "improve the reliability"
and is only applicable to "outages that could lead to cascading".
Response: The SDT thanks you for your comments. The purpose statement language was chosen to explicitly state the outcome to be achieved by this
standard. The requirements themselves address, among other things, the Sustained Outages and minimum clearances along with the required
supporting language. This separation between the purpose and the requirements appears more appropriate to the SDT. Significant changes have been
made to the current draft of the Standard based upon substantive industry comment. The essential changes are: The CCZ concept has been replaced
with the concept of minimum clearance distances, and Transmission Owners are required to prevent encroachment of vegetation into minimum
vegetation clearances distances as observed in real time. Further, funding is not an issue addressed by this Standard.
National Grid
National Grid has the following comments:
1. Transmission Owners should be able to define their own inspection "year" and not be locked into a calendar year time frame.
National Grid performs inspections at least once per vegetation growth year. Under our Vegetation Management Program, growth years
are not skipped, and our inspections occur prior to new growth every year. For example, a transmission right-of-way may be inspected in
December 2008 and the right-of-way is next inspected in February 2010. Under this scenario, the inspections occurred 14 months apart,
but only one growth year occurred between inspections, and each inspection is ahead of the next year's growth. Transmission Owners
need this flexibility to deal with regional growth rate differences and climate.
2. Section C., Compliance, of Draft Standard FAC-003-2 states "To be added". Issuance of Draft Standard FAC-003-2 should have
been delayed for comments until all sections were complete. This section is likely to include the outage reporting and self-certification
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requirements. Transmission Owners need the opportunity to comment on these items.
3. With the elimination of Clearance 1 and reducing Clearance 2 clearances, there is concern that FERC will view Standard FAC-003-2
as a watered down version of Standard FAC-003-1.
Response: The SDT thanks you for your comments.
1.
It is recognized that most work management systems typically allow for planned work to be performed within a “band of dates” around a specific
end date, such as one-third or one-fourth of an interval. These partial intervals allow for the normal variations that occur in work scheduling. When
work is completed within that band of dates it is considered completed “as scheduled”. Compliance to R2 should be examined for the example
conditions you offer since you are addressing the implementation of the inspections. If the frequency was stated in the vegetation management
program as once per calendar year, and if the work was completed “as scheduled” then the TO would be compliant.
2.
The compliance elements are included with the second posting of the standard and will be subject to stakeholder comments.
3.
Effort were undertaken to address in the standard various elements for outages, imminent threats and clearances in a manner that was
responsive to a substantial number of industry concerns. The SDT is striving to meet industry stakeholder concerns with a standard that will be
approved by its ballot pool, the NERC BOT, and regulatory authorities, including FERC
Pacific Gas & Electric
Co.
1) The standard should be clear that it applies to all Federal and Non-Federal land. PG&E further recommends additional language
specifically dealing with Federal land such as application of ANSI A300.
2) The standard should specify applicability inside substations.
Response: The SDT thanks you for your comments. This Standard states in the applicability section that all lands are subject to the standard. Further,
ANSI A300 is footnoted in the Standard. Substation facilities are not included in this Standard. This will be addressed in the White Paper.
NV Energy (fka Sierra
Pacific / Nevada Power
Co.)
These comments were made with collaboration with other Western Utilities in a conference on this topic held in Denver. Any standard
that is developed should not contain advisory-type language? it should be declarative in tone. For example, in R1.4, the ending clause
that begins “and may include actions” should be removed because it is advisory in nature. The suggested actions are not even the
responsibility of the vegetation management program. NV Energy and the other Western Utilities support the development of this white
paper as a way to help ensure consistent interpretation of the standard. Perhaps the lack of such a paper in the first version of the
standard contributed to the varying interpretations by the auditors. The utilities understand however that this document is not a legal
document and is not binding.
Response: The SDT thanks you for your comments. Please refer to the various responses to your comments provided in the individual questions.
(R1.4 was modified to eliminate the list of possible actions and the use of the word, “may.”)
The changes to the standard in this reposting and the responses to your comments on questions 1-17 are intended to serve as a reply to your various
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comments.
San Diego Gas &
Electric
We feel that any advisory-type language should be removed from the standard and replaced with wording that is in a declarative tone.
We support the development of the white paper as a way to help ensure consistent interpretation of the standard.
Response: The SDT thanks you for your comments. The advisory-type language has been removed form R 1.4
Hydro One Networks
Inc.
Please see our comments on question 3.
Response: The SDT thanks you for your comments. Please see the response to comments on question 3.
Edison Electric Institute
Overall Comments EEI strongly believes that companies are responding assertively to the requirements in FAC-003-1 and that the
existing standard is effective in supporting an adequate level of reliability. The central issue with FAC-003-1 and the draft version 2
centers on circumstances where vegetation encroachments into clearance zones take place and do not result in interruptions. EEI
understands that a potentially broad range of interpretations are being applied to the existing standard, resulting in potential violations
due to clearance encroachments of any possible design position of the conductor being violations, as well as Sustained Outages.
Version 2 should clarify this issue in the context of focusing the industry in the direction that is most effective in establishing an adequate
level of reliability. The technical comments provided by EEI seek to address this critical issue. Quantitative analysis on vegetationrelated line outages or violations made publicly available do not support the need for a substantive revision of the standard. Analysis
needs to recognize a broader range of facts in a consistent manner. Analysis needs to consider whether violations resulted in a
Sustained Outage, whether all outages and vegetation encroachment were voluntarily reported prior to enactment of Section 215, or the
facts and circumstances surrounding violations. For example, while some entities may perceive a decline in industry performance, it
may be that companies are reporting much more completely than in the past. Much more rigorous analysis is needed before concluding
that the existing standard must be made tougher. Rather than focusing on whether the standard should be more stringent, EEI believes
that the emphasis in the standard development process should focus on practicality, both for field personnel in terms of implementing the
standard, and enforceability.
Revisions to the existing standard should therefore seek to a) respond to issues raised by FERC in Order No. 693 b) where possible,
clarify ambiguities in the requirements, and c) improve industry understanding, practicality, and enforceability. For example, it is
impractical to seek development of a ?bright line? set of performance requirements. The standard needs to recognize both the diversity
of the continent in terms of geography, topography, and climate, and the critical need to provide field personnel with workable
performance requirements. Bottom line; it is very important to recognize that the ultimate goal of the standard is to ensure that
vegetation management is conducted in order to maintain an adequate level of reliability, and the industry is achieving this goal. The
standard should aim for increasing clarity in the requirements without sacrificing flexibility, since companies expect high monetary
penalties associated with Sustained Outages caused by vegetation. In addition, a continued ?zero tolerance? approach to vegetation
management will emphasize operational excellence. Seeking ?zero tolerance? on momentary outages is equivalent to pursuit of
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operational perfection, which is achievable only at extraordinary expense to customers. Therefore, the Standard will be most effective if
its elements encourage proactive behavior and provide incentives for Transmission Owners to identify and address vegetation clearance
issues before they result in momentary interruptions or Sustained Outages. Vegetation Outage Data In Order No. 693, Paragraph 732,
FERC ordered NERC to collect and analyze transmission outage data to inform development of the revised standard. EEI encourages
the drafting team and NERC Standards Committee to request that NERC collect and analyze this critically important information. Such
analysis provides an important foundation for determining whether the standard can ensure an adequate level of reliability as required by
Section 215.Applicability Order No. 693, Paragraph 708, directs NERC to 'develop an acceptable definition that covers facilities that
impact reliability but balances extending the applicability of this standard against unreasonably increasing the burden on transmission
owners.' In the order, FERC appears to accept the 200-kv threshold, however, continues to ask about these other critical facilities.
EEI recommends that the drafting team develop a definition of 'sub- 200kv critical facilities' for use in the standard. Reliance on
Reliability Coordinators for developing their own definition raises the likelihood of inconsistent approaches and applications of the term.
In addition, the drafting team should consider whether such critical facilities might require expanding applicability to entities other than
Transmission Owners.
Annual Plan as a Defined Term In order to aid in compliance enforcement and industry compliance, the term 'annual plan' should be a
defined term.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. We agree with many of your points. The SDT developed R2 to promote proactive behavior by requiring the recording and
documentation of imminent threat procedure implementations. The NERC Transmission Availability Data System is set up to collect the outage data as
directed by the FERC. In the revised standard, to address the sub 200 kV facilities to be subject to the standard, the SDT chose the Planning
Coordinator (rather than the Reliability Coordinator) for that task. The Planning Coordinator has the wide area view and appropriate time horizon
perspective to identify sub 200 kV facilities. The SDT considered the situation where non-TO facilities such as generator “leads” would be subject to
this Standard. There is an ongoing discussion within NERC with regard to registration of Generator Owner’s as limited TO’s. Annual plans have
relevance within this Standard’s context and are not needed elsewhere. Therefore a glossary definition is not necessary.
Consolidated Edison
Company of New York
(CECONY)
CECONY does not feel that, as currently written, the Standard would effectively enhance reliability throughout the industry. We
recommend that stricter language be used in the Standard specifically requiring the industry to remove incompatible species on Active
ROWs. This should reduce the number of outages resulting from vegetation grow-ins and vegetation fall-ins from inside the Active ROW
and help maintain a higher level of reliability. This is currently done at the state level (in NY) and the revised wording in the Federal
Standard may help promote consistency industry-wide and avoid confusion. Also, the concept of the Critical Clearance Zone is
theoretically strong but it needs to be made simpler for the auditors and field inspectors.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. We agree with many of your points. The SDT developed R2 to promote proactive behavior by requiring the recording and
documentation of imminent threat procedure implementations. The NERC Transmission Availability Data System is set up to collect the outage data as
directed by the FERC. . In the revised standard, To address the sub 200 kV facilities to be subject to the standard the SDT chose the Planning
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Coordinator (rather than the Reliability Coordinator) for that task. The Planning Coordinator has the wide area view and appropriate time horizon
perspective to identify sub 200 kV facilities. The SDT considered the situation where non-TO facilities such as generator “leads” would be subject to
this Standard. There is an ongoing discussion within NERC with regard to registration of Generator Owner’s as limited TO’s. Annual plans have
relevance within this Standard’s context and are not needed elsewhere. Therefore a glossary definition is not necessary.
WECC
Reporting requirements are not identified in the standard. WECC believes that sustained outages caused by vegetation should be
reported to the Regional Entity using the existing reporting requirements in FAC-003-1 (Transmission Owners report outages to the
Regional Entity). Reports of sustained outages to the Reliability Coordinator should be made for reliability purposes and not compliance
purposes. The Reliability Coordinator should not be required to report vegetation outages of individual Transmission Owners to the
compliance department.
Response: The SDT thanks you for your comments. The revised Standard reflects changes in reporting requirements.
Arizona Public Service
Company
APS has a comment to NERC on picking the standard drafting team. FAC-003 is a vegetation management standard not an engineering
standard. The team members should have been chosen based on managing the vegetation program not because they were engineers.
Any standard that is developed should not contain advisory-type language? it should be declarative in tone. For example, in R1.4, the
ending clause that begins “and may include actions” should be removed because it is advisory in nature. The suggested actions are not
even the responsibility of the vegetation management program. APS supports the development of this white paper as a way to help
ensure consistent interpretation of the standard. Perhaps the lack of such a paper in the first version of the standard contributed to the
varying interpretations by the auditors. The utilities understand however that this document is not a legal document and is not binding.
Response: The SDT thanks you for your comments. The members of the SDT were selected based on their expertise – the following was taken from the
SDT Nomination form:
Candidates should have expertise in one or more of the following areas:
-
Transmission line rights-of-way (ROW) vegetation management or ROW maintenance
-
Transmission line design and ratings
-
Regulatory or legal considerations in ROW maintenance
-
Existing codes and good practices in vegetation management
Most of the SDT members have expertise in vegetation management.
The SDT has removed the advisory language in R1.4. The SDT has professional foresters, vegetation managers, system operators and regulators.
Baltimore Gas & Electric The Applicability Section of the Reliability Standards (4.2 Facilities) defines the Transmission Lines (Applicable Lines) that must comply
to the reliability standard. This section should clearly state that the scope is limited to the facilities that are Bulk Electric System facilities
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consistent with the Bulk Electric System definition as defined by the Regional Entity.
Regarding M5, M6, M7:The intention of these paragraphs is unclear to me as written. At first glance, it appeared that the paragraphs
were asking for a negative to be proven, e.g. prove that you didn't have any tree-related outages. Anther possible meaning is that
utilities have to justify the cause of any outage that may occur. As such, the burden of proof is on the Transmission Owner to provide
evidence that an outage was not caused by trees. If an outage were to occur but the Transmission Owner could not find any evidence of
the cause, the wording in these paragraphs suggests that by default, the outages will be classified as tree-related. If these paragraphs
are intended to assign an outage cause to an outage that has already occurred, then perhaps they could be reworded to say something
to the effect of: "Transmission Owner shall provide results of investigation into all transmission outages?? "If these paragraphs are not
intended to assign an outage cause to an outage that already occurred, but to provide a mechanism to report outage performance that is
currently covered in M3 and M4 in FAC-003-1, then perhaps they could be reworded to say something to the effect of: "Transmission
Owner shall provide documentation of tree-related outage performance on a quarterly basis. Investigation results for unknown outages
shall also be provided on a quarterly basis." Or as one last suggestion, the wording could simply be: " The Transmission Owner has
evidence that there was a Sustained Tree-related Outage?.
Regarding the Tech. Reference, I thought that overall it was helpful and will be valuable to help provide guidance for Transmission
Vegetation Management Program development and implementation. The area that covers the Active/Inactive R/W should be more
clearly explained and illustrated, particularly with respect to the towers with space for another circuit on one side of the structures.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The old M5, M6, and M7 have changed in a manner that should clarify their interpretation as you requested. The CCZ concept has
been replaced with the concept of minimum clearance distances, and Transmission Owners are now required to prevent encroachment of vegetation
into minimum vegetation clearances distances as observed in real time.
Reporting requirements are included in the compliance section with this posting.
The SDT will attempt to incorporate your suggestions on illustrations for double circuits in the white paper with the final posting of this standard.
Duke Energy
Corporation
FAC-003-1 lacks clarity that is essential for understanding what is necessary for compliance. The proposed FAC-003-2 needs to be
simplified to aid with field implementation and compliance interpretation. Currently, it does not provide the clarity and simplification
needed by Transmission Owners and regulatory bodies to enhance reliability.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The CCZ concept has been replaced with the concept of minimum clearance distances, and Transmission Owners are required to
prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time. These changes are directed at the clarity
and simplification you requested for effective field implementation and compliance interpretation.
CenterPoint Energy
The proposed FAC-003-2 has gone FAR beyond what was contemplated by the Commission in FERC Order 693 and equates to a total
re-writing of the Standard for no apparent reason. The Commission's determination dealt with the following areas: (1) applicability; (2)
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inspection cycles; and (3) minimum clearances on National Forest Service lands. For instance in Paragraph 729, the Commission
states, “As proposed in the NOPR, the Commission approves Reliability Standard FAC-003-1 with no proposed modification on the issue
of clearances. The Commission reaffirms its interpretation that FAC-003-1 requires sufficient clearances to prevent outages due to
vegetation management practices under all applicable conditions?.” Rewriting the minimum clearances introduced a new set of
confusing definitions, and further burdens the Transmission Owners with new documentation requirements with little if any benefit when
compared to the Clearance 2 concept in the existing Standard. A preferred approach would have been to incorporate the following few
items into the existing Standard: (1) the RC versus the RRO; (2) the designation of a specific inspection frequency; (3) the Gallet
equation; and (4) the applicability to National Forest Service lands. We agree that the removal of requirements for quarterly reporting of
outages, Clearance 1, and personnel qualifications reduces the burden on the Transmission Owners and does not affect the purpose of
the standard to prevent vegetation outages. The Standard could meet its purpose and be streamlined by considering the following
changes:1. Delete the new terms and definitions for "Active Transmission Line Right-of-way" and "Critical Clearance Zone" and revert
back to a Clearance 2 requirement while replacing the IEEE 516 standard distances with the Gallet equation standard distances.2.
Delete R2, M2, R4 and M4 which refer to the "Critical Clearance Zone" and rely on R5, M5, R6, M6, R7, and M7 which refer to the
prevention of Sustained Outages.3. Delete R1.5 and M1.5 as a requirement and measure, but footnote the "interim corrective action
process" as a best practice as was ANSI A300 in R1.1.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. Items such as the CCZ concept has been replaced with the concept of minimum clearance distances, and Transmission Owners are
required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time. Note that the SAR for this
project included a list of items to be addressed in the revised standard – and these items included not only the directives in Order 693, but other issues
identified during the initial implementation of the standard and during the refinement of the SAR.
Entergy Services
Entergy requests that the proposed FAC-003-2 revision continue work on clarifying the above mentioned “Disagree” items and
appreciates the consideration of the above comments in the development of the standard. A clear understanding of all standard
requirements by the industry is needed to make certain field implementation is achieved and that ultimately we improve system reliability.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. Those changes were made in part for the clarity that you and others requested in order to ensure that practical field implementation
may be achieved.
Alberta Electric System
Operator
The AESO is also a signatory to the joint ISO/RTransmission Owner Council Standards Review Committee comments which reflect our
comments to the other questions in the Comment Form.
Response: The SDT thanks you for your comments. Please see the SDT’s responses to the ISO/RTO SRC comments.
JEA
M5, 6 and 7 ask the entity to prove the negative. This type of evidence is problematic, and may result in nothing better than the entity
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making an attestation that the event did not occur, thus this measure is not useful. With well over 100,000 miles of transmission covered
by this standard, even six-sigma performance would result in vegetation related issues. It is unreasonable to expect zero-tolerance for
vegetation events and unnecessary for the industry (and customers) to expend resources to attempt to meet this level of compliance
when the transmission system is planned and operated to handle any single contingency, which means that a vegetation contact should
not, in isolation, cause a major problem to the bulk power system. This standard needs work to make it clear, unambiguous, feasible and
enforceable.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment.
The SDT pursued an approach to develop a metric that would not have a zero-tolerance for outages. Discussion with FERC led the SDT to the
conclusion that such an approach would not be acceptable.
Changes made to the old M5, M6 and M7 in this new draft should alleviate the “prove a negative” dilemma.
Independent Electricity
System Operator
We recommend removing the Transmission Owner as the one to define a major storm, this task should be left to an applicable regulatory
body only, for consistency in assessing such an event. Also, we recommend footnote #5 specify that planned removal of vegetation by
the utility is not part of the exceptions, because in our view this activity is a component of the vegetation management program and that
outages should be preventable. There is a typo in R6. The numeral "4" should be superscripted.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment
The SDT has reviewed the data on vegetation related outages that TO have reported on the NERC website. There are 223 reports of outages in that data
covering the period January 2004 to March 2009. The associated documentation with these events indicate that TO are supplying supportive
information to indicate that the level of any disaster exclusion (including major storms) is sufficient to reasonably identify conditions that exceed
design criteria. Further specific on the threshold for each disaster (or storm) would not ensure that weather data would be adequate to support each
location/situation.
Random human error in felling trees whether by loggers, homeowners or vegetation removal crews has not been associated with cascading events and
remains a valid exclusion. The related safety risks and equipment damages tend to effectively self-control this type of activity.
The typographical error in what was R6 (now R7) has been corrected.
Salt River Project
We question the method used in determining the clearance distances for Vegetation near Transmission Lines. First is the use of the
Gallet Equation. Although the Gallet Equation is more definitive than using IEEE 516 as identified in the current standard, we have
questions from an engineering prespective as to how and why this method was chosen for vegetation management. It is stated in the
Technical Reference paper that the Gallet Equation is a well known method of computing the required strike distance for proper
insulation coordination. It is our understanding it's purpose is for designing towers, to define the "tower window" or opening inside of a
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tower under normal conditions. Because this is not a method designed specifically for vegetation management, what is the basis for
applying this to vegetation management? Was there, or could there be testing done? We would find it definitive to substantiate the
calculated equation assertions with test data from actual energized flashover distances to vegetation. The testing ought to include dry
and misting conditions at 200+ kilovolt levels on a sampling of fresh cut common vegetation types. Reputable EHV testing facilities
where such tests can be performed exist within the United States and Canada. Is there additional information to clarify why this method
was used to help establish clearance distances for vegetation near transmission lines? Second, it is expected that each utility needs to
define their "Critical Clearance Zone". It is outlined in the Technical Reference document how complicated it is to define this clearance
area. As the conductor moves throughout its "flight path", the minimum clearance shell surrounding the conductor moves along with it.
The shape and size of the Critical Clearance Zone around the conductors is irregular and will change depending on where a conductor
segment is located within the span. At mid-span, where the potential for conductor movement is the greatest due to sag and wind
deflection, the corresponding Critical Clearance Zone is also the largest and most irregular. With the size, shape, and area of the Critical
Clearance Zone dramatically changing as one progresses along a span, identifying the precise location and boundary of the Critical
Clearance Zone around the conductor in the field becomes very problematic. There are many variables that are involved at any point
along a line and at any given time (loading, operating temperature, wind, maximum design rating, maximum operating loading and so
on). Therefore, even if the exact size and shape of the Critical Clearance Zone is known, it becomes nearly impossible to field correlate
and accurately "superimpose" the Critical Clearance Zone" around the conductor. Therefore, it seems unreasonable to expect each
utility to develop and implement a defensible and auditable clearance zone.
We strongly support the development of the Technical Reference document. This would have been helpful if it was available for the first
version, as it will help both utilities and auditors. We recommend that this be included in the revised version and subsequent future
revisions. Please note that as FAC-003-2 goes through additional revisions prior to finalization, the Technical Reference document
needs to be revised to reflect the final revisions prior to implementation.
Response: The SDT thanks you for your comments. The SDT engaged TO personnel who were technical experts with significant experience and
credentials in transmission line insulation coordination theory and applications. The purpose of the change to the Gallet derived distances was to
provide a set of specific distances that would ensure that flashover would not occur provided those distances were not breeched under expected
outdoor operating conditions. These distances are applicable to the wire with respect to structure components, vegetation or any other object at
ground potential level. These values have already been proven for dry and wet conditions and need no further testing.
We have made changes in R2 and R4 that should remove the problems you have raised regarding the CCZ and how it is “nearly impossible” to apply
under field conditions.
Northeast Utilities
In section 4.2.2. the time period for bringing sub 200-kV lines into compliance with the standard states a 12 month period following the
designation of the lower voltage lines by the Reliability Coordinator. This can present problems if the RC designates the lines during the
course of a plan year, because budgets may not have been established or funded for the additional work. It is suggested that the time
period be revised to state, "by the end of the following calendar or budget year after the designation of lower voltage lines", allowing for a
full calendar/budget year that can be planned and budgeted to bring lines into compliance.
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There is concern over the use of the Critical Clearance Zone and making this the "bright line" where encroachment at any time under
any conditions is a violation of the standard. The Critical Clearance Zone is a very detailed and calculated zone. It is improbable that
an accurate determination of the Critical Clearance Zone could be made in the field. Mere encroachment should not constitute a
violation. If the encorachment can be determined and corrected once found - this should be an acceptable practice. It is reasonable for
utilities to spend the time, money and manpower to actively manage rights-of-way, and dealing with encroachment issues which can be
identified. Many potential encroachments will not be identifiable unless one can accurately identify the Critical Clearance Zone in all
cases in all areas at all times. Also, there is some concern over how the requirements are set up for violations of the Critical Clearance
Zone and for sustained outages. A sustained outage due to vegetation within the active transmission right-of-way is a violation under
R.5, R.6 and R.7. It is also possible that the outage is a violation of the Critical Clearance Zone under R.4. The standard implies that a
utility could be assessed multiple violations of the standard for one outage with multiple penalties. Is this the desired intent?
Finally, version 1 had clear requirements on what was to be reported, when the reports were required, and who was to submit reports. Is
it intended that the standard rely solely on self-reports? Version 2 makes no mention of what is to be reported when a violation occurs,
or of any other reports. Is reporting going to be left up to the Regional Entity to establish?
Response: The SDT thanks you for your comments.
The standard was revised to replace the Reliability Coordinator with the Planning Coordinator as the entity responsible for identifying lines sub 200 kV
for which there should be a TVMP. By moving to the Planning Coordinator, there should be ample time to address the annual work plan. With its focus
on “planning horizon” issues (> 1 year), the PC provides the necessary look-ahead that the RC did not. As soon as a sub-200 kV line is designated as
being applicable to this standard, it is understood the subject line could potentially place the grid at risk of instability, separation or cascading. A 12
month period to perform any vegetation maintenance seems reasonable to the SDT.
Significant changes have been made to the current draft of the Standard based upon substantive industry comment. Items such as the CCZ concept
has been replaced with the concept of minimum clearance distances, and Transmission Owners are required to prevent encroachment of vegetation
into minimum vegetation clearances distances as observed in real time. Reporting requirements have been addressed in the compliance section of the
revised Standard.
Hydro-Quebec
Transenergie (HQT)
HQT recommends that the Standard Drafting Team review the compliance and reporting requirements for consistency and adequacy.
Applicability 4.2.3 contradict first part of Applicability 4.2.1 and that of former Applicability 4.3
Response: The SDT thanks you for your comments. The SDT reviewed your concern and did not see a contradiction.
BCTC
Any standard that is developed should not contain advisory-type language—it should be declarative in tone. For example, in R1.4, the
ending clause that begins “…and may include actions…” should be removed because it is advisory in nature. The suggested actions are
not even the responsibility of the vegetation management program.
BCTC supports the development of this white paper as a way to help ensure consistent interpretation of the standard. Perhaps the lack
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of such a paper in the first version of the standard contributed to the varying interpretations by the auditors. The utilities understand
however that this document is not a legal document and is not binding.
Response: The SDT thanks you for your comments. R1.4 has been changed to remove the advisory type language.
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Summary Considerations FAC-003-2
Second Industry Comment Period (9/10/09 to 10/24/09)
Background:
On January 14, 2010, the NERC Standards Committee endorsed the use of Project 2007-07
Vegetation Management as the prototype for the proof-of-concept for using the results-based
criteria for developing a reliability standard. The results-based initiative is intended to focus the
collective effort of NERC and industry participants on improving the clarity and quality of
NERC reliability standards by developing performance, risk and competency-based requirements
that accomplish a reliability objective through a defense-in-depth strategy, while eliminating
documentation-driven requirements that do not have an impact on bulk power system reliability.
The Standards Committee directed the Vegetation Management SDT to stop work in refining its
second draft of the Vegetation Management standard but to inform stakeholders on how the team
had used stakeholder comments to refine the technical requirements carried over into draft 3 of
the standard.
This report provides a copy of each of the questions that was posted for stakeholder comment
with the second draft of FAC-003-2, and a summary indicating how the drafting team used
stakeholder comments submitted in response to that question. The questions included in the
second comment form provided explicit references to either background information provided in
the comment form or to specific requirements or other elements in the standard and have been
paraphrased here.
All questions asked and all comments provided by stakeholders have been posted at the
following site:
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
FAC-003-2 — Transmission Vegetation Management
Index to Questions and Summary Responses:
Question 1 ................................................................................................................... 3
Question 2 ................................................................................................................... 5
Question 3 ................................................................................................................... 6
Question 4 ................................................................................................................... 7
Question 5 ................................................................................................................... 8
Question 6 ................................................................................................................... 9
Question 7 ................................................................................................................. 10
Question 8 ................................................................................................................. 11
Question 9 ................................................................................................................. 12
Question 10 ............................................................................................................... 13
Question 11 ............................................................................................................... 14
Question 12 ............................................................................................................... 15
Question 13 ............................................................................................................... 16
Question 14 ............................................................................................................... 17
Question 15 ............................................................................................................... 18
Question 16 ............................................................................................................... 19
Question 17 ............................................................................................................... 20
Question 18 ............................................................................................................... 21
Draft 3: March 1, 2010
2
FAC-003-2 — Transmission Vegetation Management
Question 1
In response to industry comments, the Requirement for documentation of a TVMP was revised to clarify
that the objective of the TVMP is to improve reliability by preventing Sustained Outages due to
vegetation. Additionally the SDT assigned Time Horizons, Violation Risk Factors, and Violation
Severity Levels. Do you agree? If not, please explain and propose an alternative.
Second draft of proposed R1:
R1.
Each Transmission Owner shall have a documented transmission vegetation management
program that describes how it conducts work on its Active Transmission Line Rights of
Way to prevent Sustained Outages due to vegetation, considering all possible locations the
conductor may occupy under the effects of sag and sway throughout its operating range
under rated conditions. The transmission vegetation management program shall: [Violation
Risk Factor – Lower][Time Horizon – Long-term planning]
1.1.
Specify the methods that the Transmission Owner may use to control vegetation. 1
1.2.
Specify a Vegetation Inspection frequency of at least once per calendar year that
takes into account local 2 and environmental factors.
1.3.
Require an annual work plan. An annual work plan shall:
1.3.1. Identify the applicable lines to be maintained
1.3.2. Identify the work to be performed and methods to be used
1.3.3. Be flexible to adjust to changing conditions and to findings from Vegetation
Inspections. Adjustments to the plan within the year are permissible.
1.3.4. Take into consideration permitting and scheduling requirements from
landowners or regulatory authorities.
1.4.
Require a process or procedure for response to an imminent threat of a vegetationrelated Sustained Outage. The process or procedure shall specify actions which
shall include communication of the threat to the responsible control center.
1.5.
Specify an interim corrective action process for use when the Transmission Owner
is temporarily constrained from performing vegetation maintenance as planned.
1.6.
Specify the maintenance strategies used (such as minimum vegetation-to-conductor
distance or maximum vegetation height) to ensure that Table 1 clearances in
Attachment 1 are never violated. The maintenance strategies shall consider the sag
and sway of the conductor throughout its operating range under rated conditions.
Summary Consideration: The vast majority of comments for this Question related to the
Annual Vegetation Inspection frequency. Those commenters believed that a once/year mandate
was too prescriptive and preferred to let the Transmission Owner choose a frequency.
1
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices,
while not a requirement of this standard, is considered to be an industry best practice.
2
Local factors include items such as treatment cycle, extent and type of treatment, and their relationship to the
normal growth rate.
Draft 3: March 1, 2010
3
FAC-003-2 — Transmission Vegetation Management
After reviewing Order 693 in its entirety, the SDT set the frequency at once/year to avoid a fillin-the-blank requirement and establish a reasonable frequency for most regions. However, the
SDT also made it explicitly clear that this Vegetation Inspection can be combined with other line
inspections to allow maximum flexibility in meeting this requirement. The vast majority of other
comments dealt with specific wording in the Draft 2, Requirement 1. In an effort to be less
prescriptive, the new Draft has removed most of the text that commenters wanted changed.
Draft 3: March 1, 2010
4
FAC-003-2 — Transmission Vegetation Management
Question 2
In response to industry comments, the Requirement for implementation of Imminent Threat
process/procedure was revised. Additionally the SDT assigned Time Horizons, Violation Risk
Factors, and Violation Severity Levels. Do you agree? If not, please explain and propose an
alternative.
Second draft of proposed R2:
R2. Each Transmission Owner shall implement its imminent threat process or procedure when
the Transmission Owner has actual knowledge of such a threat, obtained through normal
operating practices. [Violation Risk Factor – Medium][Time Horizon – Real Time]
Summary Consideration: Ninety percent of respondents agreed with Requirement 2
(Implementation of the Imminent Threat Process). No major themes of disagreement surfaced.
Two respondents expressed confusion between the NERC defined term “Operating Process” and
the language “operating practices” used in R2. Two respondents preferred more specificity in
the requirement for audit purposes, one respondent suggested changing “actual knowledge” to
“confirmed” and one respondent expressed concerns about proving a negative. Two other
respondents had comments that were more appropriate for questions 1 & 4 and are answered
there.
The SDT considered all comments and essentially retained all the previous language in the new
draft. Of note, the term “actual knowledge” was changed to “verified knowledge” based on the
guidelines for Requirements with the new standard format. This change still retains its meaning
that the Transmission Owner “confirmed” the potential threat prior to initiating the Imminent
Threat process.
Proposed requirement in Draft 3 of FAC-003-2:
R5. Each Transmission Owner shall take interim corrective action when it is temporarily
constrained from performing planned vegetation work, where a Transmission Line is put at
potential risk due to the constraint.
Draft 3: March 1, 2010
5
FAC-003-2 — Transmission Vegetation Management
Question 3
In response to industry comments, the Requirement for conducting Vegetation Inspections was
revised. Additionally the SDT assigned Time Horizons, Violation Risk Factors, and Violation
Severity Levels. Do you agree? If not, please explain and propose an alternative.
Second draft of proposed R3:
R3. Each Transmission Owner shall conduct Vegetation Inspections of all applicable lines (as
measured in line miles) in accordance with the frequency specified in its transmission
vegetation management program, unless constrained by natural disasters. When constrained
by a natural disaster, the Transmission Owner shall conduct the Vegetation Inspection(s)
within six months or a period agreed to by its Regional Entity, whichever is greater.
[Violation Risk Factor – Medium][Time Horizon – Operations Planning]
Summary Consideration: Eight commenters perceived an inconsistency in the inspection
frequency required between Requirement 1.2 and Requirement R3. Eleven (11)respondents felt
an inspection frequency of longer than once per calendar year should be acceptable, the required
frequency for inspection was unclear, or that the requirement should simply state an inspection
interval of once per calendar year. Five comments (5) noted that the Requirement R3 exception
for non performance due to natural disasters should be expanded, re-organized, or re-worded to
be more clear or include a number of additional situations including disease or species
epidemics. Several entities (6) expressed a concern over the use of the term “line miles” in the
performance measures for this requirement. Finally, a few comments (2) were received that
suggested the phrase “all applicable lines” be removed from the requirement.
With this new Draft, the Standards Drafting Team has removed 1.2 which eliminates any
perceived confusion. After reviewing Order 693 in its entirety, the SDT re-established the
frequency at once/year to avoid a fill-in-the-blank requirement and establish a reasonable
frequency for most regions. However, the SDT also made it explicitly clear that this Vegetation
Inspection can be combined with other line inspections to allow maximum flexibility in meeting
this requirement. The FAC-003-2 Draft 3 includes a general, and more inclusive, Force Majeure
section which applies to the entire Standard. The Standards Drafting Team responded to industry
comments about the term “line miles”. There is now more explanation of this term in the VSL
for R6.”
Draft 3: March 1, 2010
6
FAC-003-2 — Transmission Vegetation Management
Question 4
In response to industry comments, the Requirement for preventing vegetation encroachments
was revised. Additionally the SDT assigned Time Horizons, Violation Risk Factors, and
Violation Severity Levels. Do you agree? If not, please explain and propose an alternative.
Second draft of proposed R4:
R4. Each Transmission Owner shall prevent encroachment of vegetation into the Minimum
Vegetation Clearance Distances (MVCD) listed in FAC-003-2 - Attachment 1 for its
applicable lines as observed in real-time operating between no-load and their Rating, with
the following exceptions: [Violation Risk Factor – Medium][Time Horizon – Real Time]
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting from
natural disasters. 3
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting from
human or animal activity. 4
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting from falling
vegetation.
Summary Consideration: Fifty-two percent (32 of 62) of the respondents disagreed with
various aspects of Requirement 4 (Preventing Vegetation Encroachments). A major theme from
19 responses requested clarification on the fall-in tree exemption particularly when a fall-in tree
may be lodged in another tree. The following six minor themes were identified:
Requested the use of the word “critical” rather than “minimum” to aide with public
perception (7 responses)
Clarification on operating beyond emergency ratings (7 responses)
Clarification on what is meant by “observed in real-time”( 6 responses)
Requested a force majeure exemption be added (5 responses)
Requested observations be done by qualified observers (4 responses)
Requested to eliminate R4 (4 responses).
Requested an interpolation in the clearance tables for altitude(2 responses)
Identified “Double Jeopardy” concern between Requirement 4 and the outage
Requirements(1 response)
The SDT considered all comments and determined that two of these were significant enough to
change the standard - the SDT combined the outage requirements (R5, R6, R7 and R8) with the
encroachment requirement (R4). The SDT determined the other comments could be adequately
addressed as modifications for clarity to the Technical Reference Document.
3
Examples include, but are not limited to, earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale,
major storms as defined either by the Transmission Owner or an applicable regulatory body, ice storms, and floods.
4
Examples include, but are not limited to, logging, animal severing tree, vehicle contact with tree, arboricultural
activities or horticultural or agricultural activities, or removal or digging of vegetation.
Draft 3: March 1, 2010
7
FAC-003-2 — Transmission Vegetation Management
Question 5
In response to industry comments, the Requirement for preventing Sustained Outages due to
grow-ins on IROL or Major WECC Transfer Paths was developed. Additionally the SDT
assigned Time Horizons, Violation Risk Factors, and Violation Severity Levels. Do you agree? If
not, please explain and propose an alternative.
Second draft of proposed R5:
R5. Each Transmission Owner shall prevent Sustained Outages 5 of applicable lines that are
identified as an element of an Interconnection Reliability Operating Limit (IROL) (or
Major WECC Transfer Path) due to vegetation growing into a conductor operating between
no-load and its Rating, with the following exceptions: [Violation Risk Factor – High][Time
Horizon – Real Time]
Sustained Outages of applicable lines that result from natural disasters.
Sustained Outages of applicable lines that result from human or animal activity.
Summary Consideration: Commenters generally agreed with R5 in draft 2. The most
significant issues that the SDT needed to consider were: the addition of other exclusionary
conditions, the prima facie double jeopardy that exists with this requirement and R4, the lack of
robust VSLs, and the need for further clarity on terms and concepts (e.g. rating, minimum).
Finally, a few commenters noted that this requirement is structured unlike other conventional
NERC standard requirements in that it does not say what must be accomplished for reliability
(and compliance) but rather says what must NOT be done.
The SDT considered these comments and determined that two of these were significant enough
to change the standard - the SDT combined the outage requirements (R5, R6, R7 and R8) with
the encroachment requirement (R4), with one combined Requirement for IROLs/Major WECC
Transfer Paths and another combined Requirement for all other lines. A broadened Force
Majeure section was added to the applicability section of the standard. Additionally, the new R1
and R2 in this Draft were reworded to describe what must be done.
5
Multiple Sustained Outages on an individual line, if caused by the same vegetation, shall be considered as one
outage regardless of the actual number of outages within a 24-hour period.
Draft 3: March 1, 2010
8
FAC-003-2 — Transmission Vegetation Management
Question 6
In response to industry comments, the Requirement for preventing Sustained Outages due to
grow-ins on non-IROL or Major WECC Transfer Paths was developed. Additionally the SDT
assigned Time Horizons, Violation Risk Factors, and Violation Severity Levels. Do you agree? If
not, please explain and propose an alternative.
Second draft of proposed R6:
R6. Each Transmission Owner shall prevent Sustained Outages of applicable lines that are not
an element of an IROL (or major WECC Transfer Path) due to vegetation growing into a
conductor operating between no-load and its Rating, with the following exceptions:
[Violation Risk Factor – Medium][Time Horizon – Real Time]
Sustained Outages of applicable lines that result from natural disasters.
Sustained Outages of applicable lines that result from human or animal activity.
Summary Consideration: Commenters generally agreed with R6 in draft 2. The most
significant issues that the SDT needed to consider were: the addition of other exclusionary
conditions, the prima facie double jeopardy that exists with this requirement and R4, the lack of
robust VSLs, and the need for further clarity on terms and concepts (e.g. rating, minimum).
Finally, a few commenters noted that this requirement is structured unlike other conventional
NERC standard requirements in that it does not say what must be accomplished for reliability
(and compliance) but rather says what must NOT be done.
The SDT considered these comments and determined that two of these were significant enough
to change the standard and have combined the outage requirements (R5, R6, R7 and R8) with
this encroachment requirement (R4), with one combined Requirement for IROLs/Major WECC
Transfer Paths and another combined Requirement for all other lines. A broadened Force
Majeure section was added to the applicability section of the standard. Additionally, the new R1
and R2 in this Draft were reworded to describe what must be done.
Draft 3: March 1, 2010
9
FAC-003-2 — Transmission Vegetation Management
Question 7
In response to industry comments, the Requirement for preventing Sustained Outages due to
blowing together of vegetation and transmission line conductors was developed. Additionally the
SDT assigned Time Horizons, Violation Risk Factors, and Violation Severity Levels. Do you
agree? If not, please explain and propose an alternative.
Second draft of proposed R7:
R7. Each Transmission Owner shall prevent Sustained Outages of applicable lines due to the
blowing together of vegetation and a conductor within an Active Transmission Line Right
of Way (operating within design blow-out conditions) with the following exception:
[Violation Risk Factor – Medium][Time Horizon – Real Time]
Sustained Outages of applicable lines that result from natural disasters or wind-blown
debris.
Summary Consideration: Approximately 70% of the respondents agreed with Requirement
R7. Among the commenters who disagreed, a major comment issue pertains to the definition of
the Active Transmission Line ROW which is further split into two sub issues.
The first sub issue relates to a desire for a more descriptive definition of Active ROW.
The other sub issue suggests the elimination of Active ROW.
A minority comment area pertains to altering the requirement to become more performance
based with a graduated set of VSLs.
The SDT believes that the definition of “active transmission right-of-way” is appropriate for
meeting the objectives of the Standard. This topic is addressed in the Guideline and Technical
Basis section of this of FAC-003-2 Draft 3. The SDT considered the other comments and
determined that two of these were significant enough to change the standard - the SDT combined
the outage requirements (R5, R6, R7 and R8) with this encroachment requirement (R4), with one
combined Requirement for IROLs/Major WECC Transfer Paths and another combined
Requirement for all other lines. A broadened Force Majeure section was added to the
applicability section of the standard. Additionally, the new R1 and R2 in this Draft were
reworded to describe what must be done.
Draft 3: March 1, 2010
10
FAC-003-2 — Transmission Vegetation Management
Question 8
In response to industry comments, the Requirement for preventing Sustained Outages due to fallins of vegetation was developed. Additionally the SDT assigned Time Horizons, Violation Risk
Factors, and Violation Severity Levels. Do you agree? If not, please explain and propose an
alternative.
Second draft of proposed R8:
R8. Each Transmission Owner shall prevent Sustained Outages of applicable lines due to
vegetation falling into a conductor from within an Active Transmission Line Right of Way
with the following exceptions: [Violation Risk Factor – Medium] [Time Horizon – Real
Time]
Sustained Outages of applicable lines that result from natural disasters or wind-blown
debris.
Sustained Outages of applicable lines that result from human or animal activity.
Summary Consideration: Approximately 78% of the respondents agreed with the Requirement
R8. Among the commenters who disagree, a major comment pertains to the definition of Active
Transmission Line ROW which is further split up into two sub issues.
The first sub issue relates to a desire for a more descriptive/quantitative definition of the
Active Transmission Line ROW.
The other sub issue suggests the elimination of Active Transmission Line ROW.
A minority comment area pertains to altering the requirement to become more performance
based with a graduated set of VSL’s.
The SDT believes that the definition of “active transmission right-of-way” is appropriate for
meeting the objectives of the Standard. This topic is addressed in the Guideline and Technical
Basis section of FAC-003-2 Draft 3. The SDT considered the other comments and determined
that two of these were significant enough to change the standard and have combined the outage
requirements (R5, R6, R7 and R8) with this encroachment requirement (R4), with one combined
Requirement for IROLs/Major WECC Transfer Paths and another combined Requirement for all
other lines. A broadened Force Majeure section was added to the applicability section of the
standard. Additionally, the new R1 and R2 in this Draft were reworded to describe what must be
done.
Draft 3: March 1, 2010
11
FAC-003-2 — Transmission Vegetation Management
Question 9
In response to industry comments, the Requirement for implementation of annual work plan was
developed. Additionally the SDT assigned Time Horizons, Violation Risk Factors, and Violation
Severity Levels. Do you agree? If not, please explain and propose an alternative.
Second draft of proposed R9:
R9. Each Transmission Owner shall implement its annual work plan for vegetation
management to accomplish the purpose of this standard. [Violation Risk Factor – Medium]
[Time Horizon – Operations Planning]
Summary Consideration: A majority of commenters requested the restoration of the phrase
“subject to legal rights,” citing that doing so would improve the ability of TO’s in expediting
approvals for access. A few comments objected to the phrase “to accomplish the purpose of the
standard” citing it was superfluous. A minority of comments pertained to the extent and effect of
the phrase “within the year”. Commenters pointed out that carryover work into the next year is
not possible with the requirement 1.3 as written.
In response to overwhelming industry comments from the first posting of the draft standard, the
SDT removed the words “within the extent of its easements and/or legal rights”. The concern
expressed by the first commenters pertained to avoiding the situation where the expectation is for
the transmission Owner to exercise its fullest legal rights when not needed. The SDT did remove
the two phrases for clarity and in keeping with the guidelines for this new form of standard
development. And sections 1.3.3 and 1.3.4 which were subject to misinterpretation have been
removed.
Draft 3: March 1, 2010
12
FAC-003-2 — Transmission Vegetation Management
Question 10
In response to industry comments, the Requirement for the preparation of list for sub 200kV
transmission lines by the Planning Coordinator was developed. Additionally the SDT assigned
Time Horizons, Violation Risk Factors, and Violation Severity Levels. Do you agree? If not,
please explain and propose an alternative.
Second draft of proposed R10:
R10.
Each Planning Coordinator shall prepare and review annually, a list of
lines that are operated below 200kV, if any, which are subject to this standard. Each
Planning Coordinator shall consult with its Transmission Owner(s) and neighboring
Planning Coordinators to obtain input to develop the list. [Violation Risk Factor – Lower]
[Time Horizon – Long-term Planning]
Summary Consideration: An overwhelming majority of respondents agreed with this
requirement as found in the second draft. For those commenters that disagreed with the
requirement, three concepts arose. First, some commenters note that a similar identification of
important circuit exists in FAC-014 and as such this requirement is unnecessary. The second
issue expressed involves the interaction between the TO and the PC. There was concern that the
word “consult” was ambiguous and that the mere preparation of the list did not ensure that the
TO would be provided the list. The last group opined that this requirement for the actual
preparation of the list could be combined with the requirement to establish a methodology (R11)
since either one is toothless without the other.
After reviewing these comments as well as a complete analysis of Draft 2 with respect to the
guidelines for this new results-based standard development process, the Requirements dealing
with the Planning Coordinator have been removed. For sub-200 kV lines, the applicability will
derive from identification of Transmission Lines associated with IROLs or as Major WECC
Transfer Paths - analysis already exists for both of these.
Draft 3: March 1, 2010
13
FAC-003-2 — Transmission Vegetation Management
Question 11
In response to industry comments, the Requirement for the Planning Coordinator to document
method for identification of applicable sub-200kV transmission lines was developed.
Additionally the SDT assigned Time Horizons, Violation Risk Factors, and Violation Severity
Levels. Do you agree? If not, please explain and propose an alternative.
Second draft of proposed R11:
R11. Each Planning Coordinator shall develop and document its method for assessing the
reliability significance of sub-200kV transmission lines whose loss would place the grid at
an unacceptable risk of instability, separation, or cascading failures. [Violation Risk Factor
– Lower] [Time Horizon – Long-term Planning]
Summary Consideration: An overwhelming majority of respondents agreed with this
requirement as found in the second draft. For those commenters that disagreed with the
requirement the most common concern was that a similar identification of important circuit
exists in FAC-014 and as such this requirement is unnecessary or duplicative. Two minor
opinions also arose, one that all lines should be included in this standard, regardless of voltage,
the other that no lines operating at voltage less than 200kV should be included.
After reviewing these comments as well as a complete analysis of Draft 2 with respect to the
guidelines for this new results-based standard development process, the Requirements dealing
with the Planning Coordinator have been removed. For sub-200 kV lines, the applicability will
derive from identification of Transmission Lines associated with IROLs or as Major WECC
Transfer Paths - analysis already exists for both of these.
Draft 3: March 1, 2010
14
FAC-003-2 — Transmission Vegetation Management
Question 12
The SDT received suggestions from commenters to re-sequence the requirements contained in
the standard to improve the logical flow of this document. The SDT submits for consideration a
proposed alternative sequence. Do you agree with the proposed alternative sequencing? If not,
please recommend a suggested sequence.
Summary Consideration: With only one exception, every commenter agreed that some resequencing was logical and appropriate. All others that disagreed with the SDT proposal
included alternative sequences.
The SDT has rewritten the Requirements and re-sequenced those remaining by Results-based type requirements, i.e., competency-based, risk-based, or performance-based.
Draft 3: March 1, 2010
15
FAC-003-2 — Transmission Vegetation Management
Question 13
The Implementation Plan proposes an effective date that gives entities at least a year to become
fully compliant. Do you agree with this implementation plan? If not, please indicate what
should be changed and indicate why.
Summary Consideration: Most commenters felt that the proposed implementation was
acceptable. However, a sizable number found this proposed Revision to be far superior to the
current in-force standard and would like the SDT to consider options to expedite the
implementation. One commenter indicated they would need more time.
The SDT has chosen to retain the implementation plan, rather than attempt an expedited
schedule, with FAC-003-2 Draft 3.
Draft 3: March 1, 2010
16
FAC-003-2 — Transmission Vegetation Management
Question 14
Do you have further questions about the standard that the Technical Reference document (White
Paper) does not clear up? If so, please elaborate and propose additions.
Summary Consideration: The most prevalent comment requested revisions to the Diagrams to
eliminate trees in impermissible areas. Another popular comment dealt with a change to the
Active Transmission Line Right of Way. Some commenters wanted the SDT to address the
Generator Interconnection Facility (GIF) issue. And finally, a few commenters wanted a change
in the phrase “operating range” and in an expanded Force Majeure section.
The SDT will modify the Drawings as requested and they will be provided in the Technical
Reference Document which is planned to be posted on March 23rd 2010.
The SDT slightly modified the definition of Active Transmission Line Right of Way as shown:
Active Transmission Line Right of Way — A strip or corridor of land that is occupied by
active Transmission facilities. This corridor does not include the parts of the Right-of-Way that
are unused or intended for other facilities.
The SDT is aware of the GIF issue, i.e. 200 kV, and above, circuits owned by Generator Owners
which have in some instances been considered Transmission Lines. NERC created a team to
address this issue for all NERC standards. The product of that team was a report of suggested
changes that will be addressed by a NERC drafting team. As such this draft of FAC-003 does not
include any of those recommendations as they may apply to this standard.
The phrase “operating range” has been re-written to use all NERC terms and a general Force
Majeure section has been added to the applicability section of the standard.
Draft 3: March 1, 2010
17
FAC-003-2 — Transmission Vegetation Management
Question 15
In response to industry comments, the applicability section is revised to replace Reliability
Coordinator with Planning Coordinator. Do you agree with these changes? If not, please explain
and propose an alternative.
Summary Consideration: The vast majority of commenters agreed the Planning Coordinator
was the appropriate entity. A common concern of those who disagreed was that the Planning
Coordinator role is not defined, not well defined, or duplicated in practice. (The SDT believes
that this is registration/Functional Model problem not suited for resolution in this standard.) Only
one commenter suggested the Reliability Coordinator was more appropriate for technical
reasons, opining that the Reliability Coordinator was better suited to determine the importance of
lines.
After reviewing these comments as well as a complete analysis of Draft 2 with respect to the
guidelines for this new results-based standard development process, the Requirements dealing
with the Planning Coordinator have been removed. For sub-200 kV lines, the applicability will
derive from identification of Transmission Lines associated with IROLs or as Major WECC
Transfer Paths - analysis already exists for both of these.
Draft 3: March 1, 2010
18
FAC-003-2 — Transmission Vegetation Management
Question 16
In response to industry comments, changes were made to the definitions. Do you agree with
these changes? If not, please explain and propose an alternative.
Definitions proposed with FAC-003-2 Draft 2:
Active Transmission Line Right of Way — A strip of land that is occupied by active
transmission facilities. This corridor does not include the inactive or unused part of the
Right of Way intended for other facilities.
Vegetation Inspection — The systematic examination of vegetation conditions on an
Active Transmission Line Right of Way. This inspection may be combined with a general
line inspection. The inspection includes the documentation of any vegetation that may
pose a threat to reliability prior to the next planned inspection or maintenance work,
considering the current location of the conductor and other possible locations of the
conductor due to sag and sway for rated conditions.
Summary Consideration: A majority of commenters expressed a concern with the Active
Transmission Line ROW definition ranging from unnecessary to requiring modification. Those
who recommended modification cited an issue with the phrase “intended for other facilities”.
The belief is this phrase might preclude certain parts of a ROW from being considered inactive.
A minority comment pertains to the concern of abuse in the application of the concept of Active
Transmission Line ROW.
The SDT has revised the definition to attempt to address some of the concerns and in keeping
with the guidelines for this new results-based standard development process.
Active Transmission Line Right-of-Way
A strip or corridor of land that is occupied by active transmission facilities. This corridor
does not include the parts of the Right-of-Way that are unused or intended for other
facilities.
The majority of commenters held concern with two aspects of Vegetation Inspection definition.
One concern relates to the phrase “poses a threat” and offered the alternative phrase “poses an
unacceptable risk” in its place. The other concern questions the necessity of the last sentence of
the definition which contains “requirement-like” text about documentation. The SDT changed
the definition as shown below:
Vegetation Inspection
The systematic examination of vegetation conditions on an Active Transmission Line
Right-of-Way and may be combined with a general line inspection.
Draft 3: March 1, 2010
19
Summary Consideration of Comments Submitted in Response to Draft 2 of FAC-003-2
Question 17
When compared to Version 1, does this proposed Version 2 of the standard either maintain or
improve overall electric reliability? Please provide a technical basis for your response?
Summary Consideration: The majority of the commenters agreed that Draft 2 improved
reliability. Of those who disagreed, the primary objection was the elimination of Clearance 1 and
removal of the qualification requirement. The commenters cited a reduce leverage with
landowners in the rationale for disagreement. A majority comment insists that the standard ought
to require the application of best management practices. A majority comment insists that the
standard ought to require the application of best management practices.
The SDT thanks the commenters for their support. With this new Draft, the essential concepts in
Draft 2 are retained with wording better suited to the new Results-based standards development
process. The SDT believes that the qualification issue is better left to a SAR team for PER
standards. The SDT considered requiring ANSI A300 as part of this standard but opted to
include it in the Guideline and Technical Basis section.
20
Summary Consideration of Comments Submitted in Response to Draft 2 of FAC-003-2
Question 18
Besides the comments you have already provided for the preceding questions, do you have
further suggestions for improving this standard? If so, please elaborate.
Summary Consideration: Many commenters repeated concerns expressed in other sections.
The most cited items were: the purpose statement, the definition of applicable lines, double
jeopardy for encroachments and outages, the GO/GOP/DP line issue, the necessity for a general
force majeure statement, and the reference to ANSI A300.
The SDT has replaced the purpose statement with an Objective statement retaining the same
concept.
The Applicability section has been revised to address commenters concerns, except relating to
Generator Interconnection Facilities. (Please see response to Question 14.)
The Double Jeopardy concerns were addressed by combining requirements to produce the new
Draft R1 and R2.
A general Force Majeure section was added to the applicability section of the standard that
covers all Requirements. The reference to ANSI 300 has been added to the Guideline and
Technical Basis section.
21
Consideration of Comments on 3rd Draft of FAC-003-2 Transmission
Vegetation Management — Part of Project 2007-07 Vegetation
Management
The Vegetation Management Standard Drafting Team and the Standards Committee’s Process
rd
Subcommittee thank all those who submitted comments on the 3 Draft of FAC-003-2 Transmission
Vegetation Management. The standard was posted for a 30-day public comment period from March 1,
2010 through March 31, 2010. Stakeholders were asked to provide feedback on the standard and its
proposed format through a special Electronic Comment Form. There were 13 questions posed, and most
of the questions were developed to collect stakeholder feedback on the proposed “results-based format”
for the standard. There were 55 sets of comments, including comments from more than 100 different
people from over 60 companies representing 8 of the 10 Industry Segments as shown in the table on the
following pages.
On January 14, 2010, the NERC Standards Committee endorsed the use of Project 2007-07 Vegetation
Management as the prototype for the proof-of-concept for using the results-based criteria for developing a
reliability standard. The results-based initiative is intended to focus the collective effort of NERC and
industry participants on improving the clarity and quality of NERC reliability standards by developing
performance, risk and competency-based requirements that accomplish a reliability objective through a
defense-in-depth strategy, while eliminating documentation-driven requirements that do not have an
impact on bulk power system reliability.
This report provides a copy of each of the questions that was posted for stakeholder comment with the
third draft of FAC-003-2, a summary indicating how the drafting team or the Process Subcommittee used
stakeholder comments submitted in response to that question, and the comments received. The
comments may be viewed in their original format at the following site:
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission, you
can contact the Vice President and Director of Standards, Gerry Adamski, at 609-452-8060 or at
1
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Index to Questions, Comments, and Responses
1.
In response to comments received regarding potential for “double jeopardy” and to provide
differentiation between transmission lines designated as having IROLs and Major WECC transfer
paths from those that are not, the SDT consolidated requirements R4 though R8 found in the August
2009 draft of FAC-003-2 into two requirements in the latest draft of FAC-003-2 (new requirements
R1 and R2). Do you agree? Please explain. ...................................................................................... 10
2.
The results-based reliability standard criteria focus on striving to achieve a portfolio of performancebased, risk-based, and competency-based mandatory reliability requirements that provide an
effective defense-in-depth strategy for achieving an adequate level of reliability of the bulk power
system in lieu of prescriptive requirements. Consequently, the SDT revised R1 and its subparts
found in the August 2009 draft of FAC-003-2 in favor of the text in the latest draft of FAC-003-2 (new
requirement R3). Do you agree? Please explain. .............................................................................. 19
3.
Do you agree with the overall layout of the proposed template? If not, please suggest an alternative
layout. ................................................................................................................................................. 28
4.
Do you agree with grouping the standard development timeline (previously called roadmap) with the
revision history, and the effective date(s) and putting this administrative information up front before
the Introduction Section? Please explain. .......................................................................................... 36
5.
Do you agree with grouping the Requirements and Measures together, in one Section now called
Requirements and Measures? Please explain. .................................................................................. 41
6.
Do you agree with grouping VRFs, Time Horizons and VSLs together, and putting them in a table
separate from the Requirements and Measures Section? Please explain. ....................................... 46
7.
Do you agree with the insertion of text boxes, where necessary, to help readers better understand
the basis of the Definitions and Requirements? Please explain. ....................................................... 51
8.
Do you agree with the addition of a Guideline and Technical Basis Section to place technical
materials and other related information that assists entities in understanding how to comply with the
standard but does not contain mandatory actions/activities? Please explain. ................................... 58
9.
Do you prefer putting URL links to reference materials in the Guideline and Technical Basis Section,
or do you prefer putting the additional technical/information materials in appendices, where needed,
to supplement the Guideline and Technical Basis Sections? Please explain. ................................... 65
10.
Do you agree with the addition of the Background Section to allow provision of background
information, and to elaborate on the reliability-related drivers for the standard/change? Please
explain. ............................................................................................................................................... 71
11.
Do you agree with the addition of an Administrative Procedure Section to place
administrative/procedural requirements that are contained in the existing standards but which do not
meet the results-based or risk-based criteria? Please explain. ......................................................... 77
12.
Is there any other information that should be included in the standard document? If so, please
explain why you feel that this information should be included. .......................................................... 83
13.
Do you have any other comment regarding the draft FAC-003-2 Transmission Vegetation
Management standard that have not been addressed above? If yes, please provide a reference to
the section, requirement, or subrequirement that you believe should be changed, added or deleted
and the rationale for your proposal..................................................................................................... 89
2
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Commenter
1.
Group
Guy Zito
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
Northeast Power Coordinating Council
Additional Member
10
X
Additional Organization
Region
Segment Selection
1. Alan Adamson
New York State Reliability Council
NPCC
10
2. Gregory Campoli
New York Independent System Operator
NPCC
2
3. Roger Champagne
Hydro-Quebec TransEnergie
NPCC
2
4. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
5. Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
6. Ben Eng
New York Power Authority
NPCC
4
7. Brian Evans-Mongeon
Utility Services
NPCC
8
8. Mike Garton
Dominion Resources Services, Inc.
NPCC
5
9. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC
5
10. David Kiguel
Hydro One Networks Inc.
NPCC
1
11. Michael R. Lombardi
Northeast Utilities
NPCC
1
12. Randy MacDonald
New Brunswick System Operator
NPCC
2
13. Greg Mason
Dynegy Generation
NPCC
5
14. Bruce Metruck
New York Power Authority
NPCC
6
15. Michael Schiavone
National Grid
NPCC
1
16. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
10
3
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
17. Robert Pellegrini
2.
Group
Organization
The United Illuminating Company
Jim Case
SERC OC Standards Review Group
Additional Member
Industry Segment
1
2
3
4
5
6
NPCC
X
Additional Organization
7
Region
Segment Selection
SERC
1, 3
2. Alvis lanton
Southern Illinois Power Cooperative
SERC
1, 3, 5
3. Melinda Montgomery
Entergy
SERC
1, 3
4. Ken Parker
Entegra
SERC
5
5. Larry Rodriquez
Entegra
SERC
5
6. Gwen Frazier
Gulf Power
SERC
1, 3, 5
7. Stephen Mizelle
Southern
SERC
1, 3, 5
8. Brad Young
E.ON.US
SERC
1, 3, 5
9. John Troha
SERC
SERC
10
Louis Slade
Dominion
Additional Member
X
Additional Organization
X
Region
X
X
Segment Selection
1. Jalal Babik
Electric Market Policy
SERC
6, 5
2. Mike Garton
Electric Market Policy
MRO
6, 5
3. John Loftis
NERC compliance
SERC
1, 3
4. Angela Park
NERC compliance
SERC
1, 3
5. Aaron Jonas
Forestry
SERC
1
4.
Group
Carol Gerou
MRO's NERC Standards Review Subcommittee
Additional Member
10
X
Ameren
Group
9
1
1. Gerald Beckerle
3.
8
X
Additional Organization
Region
Segment Selection
1. Chuck Lawrence
American Transmission Company
MRO
1
2. Tom Webb
Wisconsin Public Service Company
MRO
3, 4, 5, 6
3. Terry Bilke
Midwest ISO Inc.
MRO
2
4. Jodi Jenson
Western Area Power Administration
MRO
1, 6
5. Ken Goldsmith
Alliant Energy
MRO
4
6. Dave Rudolph
Basin Electric Power Cooperative
MRO
1, 3, 5, 6
7. Eric Ruskamp
Lincoln Electric System
MRO
1, 3, 5, 6
8. Joseph Knight
Great River Energy
MRO
1, 3, 5, 6
4
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
9. Joe DePoorter
Madison Gas & Electric
MRO
3, 4, 5, 6
10. Scott Nickels
Rochester Public Utilties
MRO
4
11. Terry Harbour
MidAmerican Energy Company
MRO
1, 3, 5, 6
5.
Group
Denise Koehn
Bonneville Power Administration
Additional Member
X
X
Additional Organization
Region
X
WECC
1
2. Don Swanson
BPA Transmission Line Maintenance
WECC
1
Joe Spencer (SERC staff)
and Jack Gardner (VMS
chair)
X
SERC Vegetation Management Sub-committee
Additional Member
Additional Organization
Region
1. Randy Gann
Alabama Power Company
SERC
2. Gerald Beckerle
Ameren Services Company
SERC
3. Jeffrey Hackman
Ameren Services Company
SERC
4. John Neagle
Associated Electric Cooperative, Inc.
SERC
5. Billy George
Duke Energy Carolinas
SERC
6. Ron Adams
Duke Energy Carolinas
SERC
7. Robert Trimble
E.ON U.S. Services Inc. for LG&E & KU
SERC
8. Jim Case
Entergy
SERC
9. Ralph Hale
Entergy
SERC
10. Marc Tunstall
Fayetteville Public Works Commission
SERC
11. Reggie Wallace
Fayetteville Public Works Commission
SERC
12. Terry Wilson
PowerSouth Energy Cooperative
SERC
13. Jack Gardner
Progress Energy Carolinas
SERC
14. John Wolfmeyer
SERC Reliability Corporation
SERC
15. Jerry Lindler
South Carolina Electric & Gas Company
SERC
16. Richard Dearman
Tennessee Valley Authority
SERC
7.
Group
Ben Li
Additional Member
10
Segment Selection
BPA Transmission Field Services
Group
9
X
1. Chuck Sheppard
6.
8
IRC Standards Review Committee
Additional Organization
Segment Selection
X
Region
Segment Selection
5
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
1. Bill Phillips
MISO
MRO
2
2. James Castle
NYISO
NPCC
2
3. Charles Yeung
SPP
SPP
2
4. Matt Goldberg
ISO-NE
NPCC
2
5. Mark Thompson
AESO
WECC
2
6. Patrick Brown
PJM
RFC
2
7. Steve Myers
ERCOT
ERCOT
2
8.
Group
Richard Kafka
Pepco Holdings, Inc. - Affiliates
Additional Member
X
Additional Organization
X
X
Region
RFC
1
2. Dave Paduda
Potojmac Electric Power Company
RFC
1
3. Steve Benn
Delmarva Power & Light
RFC
1
4. Olivia Watts
Atlantic City Electric
RFC
1
5. Steve Genua
Pepco Holdings, Inc
RFC
1
Sam Ciccone
FirstEnergy
Additional Member
X
Additional Organization
X
X
X
X
Region
Segment Selection
1. Rebecca Spach
FE
RFC
1
2. Katrina Schnobrich
FE
RFC
1
3. Dave Folk
FE
RFC
1, 3, 4, 5, 6
4. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
10.
Group
Carter B. Edge
Ad Hoc Group subteam formed to review draft
standard
Additional Member
X
Additional Organization
Region
1. Peter Heidrich
FRCC
FRCC
2. Pat Huntley
SERC
SERC
3. Roman Carter
NERC
NA - Not Applicable
4. Steve Ruekert
WECC
WECC
5. Chris Hajovsky
RRI Energy
NA - Not Applicable
11.
Group
Frank Gaffney
Florida Municipal Power Agency (FMPA) and Some
10
Segment Selection
Pepco Holdings, Inc
Group
9
X
1. Pat Byrne
9.
8
X
X
X
Segment Selection
X
X
6
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
Members
Additional Member
Additional Organization
Region
Segment Selection
1. Tim Byerle
New Smyrna Beach
FRCC
1, 3, 4
2. Jim Howard
Lakeland Electric
FRCC
1, 3, 5
3. Greg Woessner
Kissimmee Utilities Authority
FRCC
1, 3, 5
4. Lynne Mila
Clewiston
FRCC
1, 3, 4
5. Joe Stonecipher
Beaches Energy Services
FRCC
1, 3, 4
6. Cairo Venegas
Fort Pierce Utilities Authority
FRCC
1, 3, 4, 5
12.
Individual
Thomas Glock
Arizona Public Service Company
13.
Individual
Chip Turner
Tampa Electric Company
X
14.
Individual
Stephen Mizelle
Southen Company
X
15.
Individual
Silvia Parada Mitchell
TO/TOP
X
16.
Individual
John Buckley
Omaha Public Power District
X
17.
Individual
Howard Gugel
NERC Staff (12 staff members)
18.
Individual
Gary Cox
Tucson Electric Power Co.
X
19.
Individual
Edward Bedder
Orange and Rockland Utilities, Inc.
X
20.
Individual
Greg Lange
GCPD
21.
Individual
Christopher M. Crane
Westchester County Board of Legislators
22.
Individual
Robert Beadle
North Carolina EMC
23.
Individual
Mary Hetz
Ameren
X
24.
Individual
James W. Smith
ITC Holding
X
25.
Individual
Alan Gale
City of Tallahassee (TAL)
26.
Individual
Virginia Cook
JEA
X
27.
Individual
Weston Davis
Central Maine Power, Iberdrola USA
X
28.
Individual
Eric Senkowicz
FRCC Manager of Operations
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
7
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
29.
Individual
Samuel Stonerock
Southern California Edison Company
X
X
X
X
30.
Individual
Jon Kapitz
Xcel Energy
X
X
X
X
31.
Individual
Chris Scanlon
Exelon
X
X
X
X
32.
Individual
Jody Nelson
Ga Transmission Corp
X
33.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
X
X
34.
Individual
Greg Rowland
Duke Energy
X
X
X
X
35.
Individual
Laura Zotter
ERCOT ISO
Individual
Gerald T. Paulson
Western Area Power Administration - Upper Great
Plains Region
X
37.
Individual
Louis C. Guidry
Cleco
X
X
X
38.
Individual
Tom Hayes
East Kentucky Power Cooperative, Inc.
X
X
X
39.
Individual
Jack Gardner
Progress Energy Carolinas
X
X
X
40.
Individual
Kevin Howard
Western Area Power Administrtaion
X
41.
Individual
James Sharpe
South Carolina Electric and Gas
X
42.
Individual
George Czerniewski
Consolidated Edison Company of New York, Inc.
X
43.
Individual
Michael Pakeltis
CenterPoint Energy
X
44.
Individual
Darryl Curtis
Oncor Electric Delivery
X
45.
Individual
Thad Ness
American Electric Power (AEP)
X
46.
Individual
Dan Rochester
Independent Electricity System Operator
47.
Individual
Richard Dearman
Tennessee Valley Authority
X
Individual
Jim Fulton
BGE (on behalf of parent/affiliate companies: CEG,
CPSG, CECG, CNE & CENG)
X
49.
Individual
Edward Davis
Entergy Services
X
50.
Individual
Jason Shaver
American Transmission Company
X
36.
48.
7
8
9
X
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
8
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
Organization
51.
Individual
David Rocchio
Utility Risk Management Corporation
52.
Individual
Earl Burnside
PPL Electric Utilities Corporation (NCR00884)
53.
Individual
Jianmei Chai
Consumers Energy
54.
Individual
John Humphrey
Nebraska Public Power District
55.
Individual
Christopher M. Crane
Westchester County Board of Legislators
56.
Individual
Mike Gammon
KCPL
Industry Segment
1
X
2
3
5
X
X
6
7
8
9
X
X
X
4
X
X
9
10
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
1. In response to comments received regarding potential for “double jeopardy” and to provide differentiation between transmission
lines designated as having IROLs and Major WECC transfer paths from those that are not, the SDT consolidated requirements R4
though R8 found in the August 2009 draft of FAC-003-2 into two requirements in the latest draft of FAC-003-2 (new requirements R1
and R2). Do you agree? Please explain.
Summary Consideration: There were 43 comment forms indicating agreement with the proposed Requirement R1 and R2 and 8 comment
forms indicating disagreement.
The major comment issues covered:
•
The differentiation of IROL/WECC Major Transfer Path and other lines subject to this standard is defensible in the context of VRF. While
vegetation outages to lines covered in R2 are preventable and as such violations, the practical impact to the BES is no different than an
outage caused by other factors
•
WECC Transfer Path criteria should not be included in a national standard.
The VMSDT considerations for the major comment issues are:
•
The new R1 and R2 requirements have eliminated the double jeopardy problem. NERC’s Standards don’t allow two VRF’s for the same
requirement so the SDT created two requirements with different VRF’s.
•
The VM SDT believes that WECC criteria for Major Transfer Paths is not applicable in other RE’s and assumed this to be common
knowledge.
Some minor comment issues are:
•
Encroachment of the MVCD should not be a violation. A sustained outage should be the grounds for a violation.
•
MVCD should be defined.
•
Lines which cannot impact the BES, regardless of voltage, should be exempted from the standard
The VM SDT considerations for the minor issues are:
•
The team has concluded encroachment into the MVCD or ‘spark-over’ distance is a clear indication of improper or negligent vegetation
management and further that such encroachment creates an imminent threat condition.
•
MVCD is defined in both the Requirement and the Rationale.
FERC has directed the ERO to develop a methodology or test to designate “operationally significant” facilities in the March 18, 2010 Order 733.
The test is intended for application in PRC-023-1; however it can be extended for FAC-003-2 use.
Organization
Westchester County Board of
Legislators
Yes or No
Question 1 Comment
Do not have enough knowledge on this to provide response.
10
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
Nebraska Public Power District
No
Although it does provide some flexibility to the TO, it will be difficult to determine an encroachment into the
MVCD. It would easier to implement if R1 and R2 were only applicable when there was an outage on the
transmission system.
Dominion
No
Dominion does not agree with the inclusion of facilities that WECC designates as ‘major transfer paths’ in a
continent-wide standard. We suggest that, if the SDT wishes to include such reference and these facilities are
meant to be treated or synonymous with either IROL or SOL, that the SDT add a proposal to adopt and define
a suitable term for inclusion into the Glossary of Terms
Cleco
No
Encroachment into the MCVD should require the owner to take immediate corrective action to mitigate the
threat. Such an encroachment should not be reportable as a violation. Owners may be hesitant to
communicate possible vegetation threat conditions to the TOP or proper authority if they believe it will be
reported as a violation. We recommend the SDT consider modifying the measure for R1 and R2 to be
applicable only in the interruption of the transmission facility.
NERC Staff (12 staff members)
No
NERC Staff does not see a need to have two requirements (R1 and R2) which differentiation between
transmission lines designated as having IROLs and Major WECC transfer paths from those that are not with
two different Violation Risk Factors. The standard as drafted applies to all 200kv and above lines. The
Violation Risk Factor for all 200 kV and above lines should be “High”. R2 should be deleted and R1 should be
rewritten to be:R1. The Transmission Owner shall prevent vegetation from encroaching within the Minimum
Vegetation Clearance Distance (MVCD) of applicable Transmission line conductors to avoid a Sustained
Outage.
Xcel Energy
No
Requirements 1 & 2 are identical except for their applicability (R1 for IROL elements and elements in the
WECC Transfer Paths; R2 for all other lines =>200 KV). It is not readily apparent as to why there is a need to
distinguish between the two. Referencing the Table 2 "VRF" and "VSL" matrix indicates that R1 has a "High"
VRF and R2 has a "Medium" VRF. If this is the only reason, then consider adding, at a minimum, a
"Rationale" box explaining that reasoning.Also, the definition of MVCD needs to be a defined term or included
in R 1 & 2, e.g., “Minimum Vegetation Clearance Distance is the calculated minimum distanced stated in feet
(meters) to prevent spark-over between conductors and vegetation for various altitudes and operating
voltages as set forth in Table 2.” See comments to # 7 and # 13.
Arizona Public Service Company
No
This is a reliability standard for 230 kV and above and those lower voltages designated by the RRO. An
outage is an outage and the utility should be held accountable no matter if they are or are not designated.
SERC OC Standards Review
No
While we agree with the development of a second requirement to provide for the distinction between line
segments that are critical for reliability, in R1, a regional distinction should not be embedded in a national
11
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Group
Question 1 Comment
standard. We also strongly disagree that perfect compliance with R2, as stated, would improve reliability. If a
line is operated to avoid projected post contingent overloads, then the tripping thereof due to any cause has
no effect on BES reliability. A more prudent approach for the lines covered by R2 could be the requirement to
achieve 3 sigma or 4 sigma performance over a year’s time. Requirement 2, as stated, is not cost effective,
and may produce an unjust and unreasonable outcome to rate payers.While this draft clarifies (from version
FAC-003-1) that sustained outages are compliance violations and eliminates the “double jeopardy” which was
errantly introduced in the last draft of FAC-003-2 (when sustained outages were clearly defined as
compliance violations), we suggest that the team adjust R2 as previously mentioned. This draft provides a
mechanism to address the difference in outages that have impact to grid reliability from those that have an
impact only to local lines and associated customer reliability. The use of observed MVCD as a violation and in
the violation severity level matrix: o drives the right behaviors for improving reliability (by proactively
identifying and removing vegetation before it can become an imminent threat or cause an outage) o
eliminates the need to perform detail engineering/surveying/theoretical calculations before cutting vegetation,
o formalizes the informal interpretations that have resulted from FAC-003-1 enforcement and o allows the
vegetation field operations to focus on facts and remain practical rather than theoretical.
KCPL
No
American Transmission
Company
Yes
Bonneville Power Administration
Yes
Central Maine Power, Iberdrola
USA
Yes
City of Tallahassee (TAL)
Yes
Consumers Energy
Yes
The measures for R1 and R2 are zero tolerance for encroachments into the MVCD that did not result in a
“contact” with the transmission facility. Considering the substantial number of miles of transmission involved,
the complexities in anticipation of vegetation growth with numerous growth variables, vegetation management
limitations imposed by other regulations or requirements, and unexpected transmission events that require
substantial efforts regarding physical restoration, it is not reasonable or practical for the measures here to
include encroachments that do not result in an interruption of transmission service. Recommend the SDT
consider modifying the measures for R1 and R2 to be applicable only in the interruption of a transmission
facility.
12
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Duke Energy
Yes
Florida Municipal Power Agency
(FMPA) and Some Members
Yes
FRCC Manager of Operations
Yes
Ga Transmission Corp
Yes
GCPD
Yes
ITC Holding
Yes
Manitoba Hydro
Yes
Omaha Public Power District
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southen Company
Yes
TO/TOP
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Question 1 Comment
1. NSRS agrees with the revisions that the drafting team has made and agrees with the combining of four
requirements into two. NSRS prefers the MVCD methodology to the minimum clearance distance
13
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
methodology due to the fact that there is only one measurement to contend with versus two.2. If a company
has a line with a standing IROL could they be found in violation of both the requirements R1 and R2? If so,
the NSRS recommends combining R1 and R2.3. Please clarify the need for R1 and R2. Why were lines with
IROL separated out from lines without IROLs?
American Electric Power (AEP)
Yes
American Electric Power agrees with this change.
IRC Standards Review
Committee
Yes
Because real-time observation in Measurement 1 would require an actual measurement for comparison to
Table 2 to be defendable as a violation, the SRC suggests replacing observation with measurement.
The
SRC would suggest deleting the phrase "to avoid a sustained outage" as that phrase does not add any clarity
to either of the two requirements.
There do not seem to be any encroachments that the SDT will allow. If
there are encroachments that are considered allowable, who is responsible for making that consideration?
And what would be considered a "sustained" outage?Minimum Vegetation Clearance Distance (MVCD) is a
capitalized term used in Requirements 1, 2 and 7 but is not defined in the NERC Glossary of Terms Used in
Reliability Standards nor is a definition proposed in this standards action. Either a definition should be
proposed or the capitalization should be removed.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE agrees with the consolidation of R4 through R8 into two requirements in the FAC-003-2 draft.
Ameren
Yes
Creating two specific requirements removes the potential for double jeopardy.
Southern California Edison
Company
Yes
SCE agrees that the consolidation of Requirements R4-R* resolves the "double jeopardy" issue.
Tampa Electric Company
Yes
The change in the draft serves to consolidate, clarify and remove the “double jeopardy” as stated above. This
is an improvement in the standard.
CenterPoint Energy
Yes
The differentiation in the Violation Risk Factor for R1 versus R2 seems appropriate.
Consolidated Edison Company of
New York, Inc.
Yes
The elements that comprise IROLs must be clearly communicated to each Transmission Owner and must be
consistent across North America.
Orange and Rockland Utilities,
Inc.
Yes
The elements that comprise IROLs must be clearly communicated to each Transmission Owner and must be
consistent across North America.
14
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
Northeast Power Coordinating
Council
Yes
The most recent draft of the standard consolidated R4-R8 results in clearer requirements that meet the results
based criteria and addresses the “double jeopardy” issue. However, there is concern with the differentiation
of lines designated as having IROLs and Major WECC transfer paths from those that are not, as is proposed
in the Applicability section 4.2 and subsequently in requirements R1 and R2. As stated in the background
section: “This Standard focuses on transmission lines to prevent those vegetation related outages that could
lead to Cascading. It is not intended to prevent customer outages due to tree contact with lower voltage
distribution system lines. For example, localized customer service might be disrupted if vegetation were to
make contact with a 69kV transmission line supplying power to a 12kV distribution station. However, this
Standard is not written to address such isolated situations which have little impact on the overall Bulk Electric
System.” It must be recognized that in some systems, outages on lines operated at voltages greater than 69
kV, 200 kV for example, have localized impact only and do not lead to Cascading. Concurring with the
background, a line should be subject to this standard only if a vegetation related outage “could lead to
Cascading”, or could have a “significant impact” on the system. It does not depend on whether it is an IROL
line or not.A performance based methodology is used in NPCC to determine if an outage on a line can cause
a “significant impact” on the system. The lines identified by this methodology are not identified according to
their voltages, but rather by their impact on the system, regardless of the voltage.The introduction of “two”
subcategories of BES - an IROL and a non-IROL - appears to just differentiate between high VRF and
medium VRF. Furthermore, in the Applicability section, the IROL “variable” is mentioned only for lines
operated below 200 kV. What about lines operated at or above 200 kV lines? Why not have a single
Application item stating: overhead transmission lines operated at any voltage whose outages have a
significant impact on the system? A Table could define what is considered “significant”.There are standards
for vegetation management on the distribution system, and there are standards for higher voltage systems.
This standard should focus on lines with high impact on the system when a vegetation outage occurs.Utilities
will not let the vegetation encroach on other lines, but an importance will be given to vegetation management
on “critical” lines for the reliability of the whole system. On other lines, if an outage occurs, it will have
localized impact.A “Results-Based Reliability Standard” should first focus on the “critical” lines.If it is the intent
of NERC or the industry to ensure that a vegetation outage causes no more than a fixed level of load loss, it
should say so in a requirement.If the IROL “variable” is retained, identification of the transmission elements
that comprise IROLs must be officially communicated to the Transmission Owners. This must be done either
through a requirement in this, or another standard.
Progress Energy Carolinas
Yes
The previous version (FAC-003-1) was not developed with individual outages listed as a requirement or a
violation. The previous drafts of version 2 (FAC-003-2) have improved on FAC-003-1 by defining sustained
outages from within the Right-of-Way as violations. However, the recent drafts of FAC-003-2 also introduced
a potential for ‘double jeopardy’ when clarifying that sustained outages and MVCD encroachments were
(‘binary’) requirements/violations. This latest draft clarifies the expected performance into two concise
requirements that provide for differentiation in severity levels and risk factors, eliminating the unintended
15
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
‘double jeopardy’. The inclusion of the use of observed MVCD as a violation of R1/R2 and in the violation
severity level matrix drives the right behaviors for improving reliability (by proactively identifying and removing
vegetation before it can become an imminent threat or cause an outage) , eliminates the need to perform
detail engineering/surveying/theoretical calculations before cutting vegetation, formalizes the informal
interpretations that have resulted from FAC-003-1 and allows the vegetation field operations to focus on facts
(and remain practical rather than theoretical). Progress Energy believes that the R1 and R2 changes to this
draft are a significant improvement over FAC-003-1. This version draft: clarifies real-time MVCD and
sustained outages as a requirement; provides for differentiation between grid impacting outage events and
outage events to lines primarily associated with customer reliability; introduces a performance barrier/defense
that is fact based - eliminating the need to determine compliance through theoretical calculations that rely on
design assumptions (e.g., mechanical behavior of aged conductor), prior design criteria/code versions (i.e.,
code clearances in effect at time of design) and detail site measurements (e.g., “survey” quality
measurements and local environmental conditions at time of measurement/event).
JEA
Yes
The simplification and clarification improves the ability of Registered Entities to comply thereby enhancing
reliability.
Independent Electricity System
Operator
Yes
This change addresses the perceived “double jeopardy” risk.
Oncor Electric Delivery
Yes
This does not reduce the Standards effectiveness on the cascading issue or discount any outage on
applicable lines subject to this Standard in the electric Transmission system.
East Kentucky Power
Cooperative, Inc.
Yes
This draft adequately addresses the "double jepoardy" issue. The use of the Minimum Vegetation Clearance
Distances simplifies recommended maintenance process for field personnel and eliminates the need to
perform costly and time consuming engineering studies prior to trimming or removing vegetation.
SERC Vegetation Management
Sub-committee
Yes
This draft clarifies (from version FAC-003-1) that sustained outages are compliance violations and eliminates
the “double jeopardy” which was errantly introduced in the last draft of FAC-003-2 (when sustained outages
were clearly defined as compliance violations). This draft provides a mechanism to address the difference in
outages that have impact to grid reliability from those that have an impact only to local lines and associated
customer reliability. The use of observed MVCD as a violation and in the violation severity level matrix: o
drives the right behaviors for improving reliability (by proactively identifying and removing vegetation before it
can become an imminent threat or cause an outage) o eliminates the need to perform detail
engineering/surveying/theoretical calculations before cutting vegetation, o formalizes the informal
interpretations that have resulted from FAC-003-1 enforcement and o allows the vegetation field operations
to focus on facts and remain practical rather than theoretical.
16
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
Western Area Power
Administrtaion
Yes
This is a very efficient and logical consolidation of requirements.
Western Area Power
Administration - Upper Great
Plains Region
Yes
This is not a critical issue for the WAPA - UGPR.
Tennessee Valley Authority
Yes
This method effectively recognizes the difference in reliabilty risks among various lines based on their value to
the transmission grid.
Entergy Services
Yes
We agree that R1 and R2 are beneficial, but believe that they should be explained in greater detail for much
greater clarity to reflect their intent. Our understanding is that R1 applies to ALL IROL's and ALL Major
WECC Transfer Path lines, regardless of voltage, and R2 is centered around ALL lines operated at voltages
200 kV and above but are not classified as IROL/WECC lines. Our understanding of the term "applicable line
conductor" in R2 refers back to the facilities defined in Facilities - Section 4.2 and as modified by the phrase in
R2: "which are not elements of an IROL and are not a Major WECC transfer path, (operating within Rating
and Rated Electrical Operating Conditions)". However the appropriateness of our assumed reference back to
Section 4.2 and the modification contained in R2 is not clear. It also is not clear that the term "applicable line
conductor" in R2 is the same as "applicable line conductor" in R6. We suggest the term "applicable line
conductor" be specifically defined as that term is intended to be applied in R2, and the term "applicable line
conductor" be defined as that term is intended to be applied in R6.
FirstEnergy
Yes
We agree that the new R1 and R2 alleviate the potential double jeopardy issue as well as differentiate the
high and medium risk factor transmission lines. However, we offer the following comments and suggestions
for improvement:It is not clear how the Transmission Owner (TO) will determine which lines are associated
with IROLs. Upon reviewing standard FAC-014 Req. R5, which requires the communication of SOLs and
IROLs, the required communication of IROLs to the TO is not specified. There needs to be a tie between this
standard and the FAC-014 standard, which will require a revision to FAC-014. Unfortunately, this issue will
create a gap if FAC-014 is not revised and submitted to FERC in parallel with the submittal of FAC-003-2 to
FERC. This may require immediate action such as an urgent action SAR or other appropriate actions.If our
suggestion to revise FAC-014 is not possible at the present time, then we suggest an alternative course of
action to include language in R1 of FAC-003 to aid the TO in obtaining the information regarding lines
associated with IROLs. We propose adding the following sentence to R1: "The Transmission Owner can
request information regarding transmission lines associated with an IROL from its Planning Coordinator."
Ad Hoc Group subteam formed to
Yes
We understand the differentiation to be around the intent that those transmission lines designated as having
IROLs and Major WECC transfer paths pose a more significant threat to the reliability of the BES and that
17
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
review draft standard
Yes or No
Question 1 Comment
encroachment of the MVCD in these cases are relatively more significant. We suggest that this be clarified in
the rationale.
18
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
2. The results-based reliability standard criteria focus on striving to achieve a portfolio of performance-based, risk-based, and
competency-based mandatory reliability requirements that provide an effective defense-in-depth strategy for achieving an adequate
level of reliability of the bulk power system in lieu of prescriptive requirements. Consequently, the SDT revised R1 and its subparts
found in the August 2009 draft of FAC-003-2 in favor of the text in the latest draft of FAC-003-2 (new requirement R3). Do you agree?
Please explain.
Summary Consideration: There were 41 comment forms that indicated agreement with revising Requirement R1 found in the August 2009 draft
of FAC-003-2 in favor of the text in the latest draft (new requirement R3) and 12 forms indicating disagreement.
The major comment issues covered:
•
Several respondents felt R3 lacked clarity and needed more definition. However there were a large number of commenters who
specifically pointed out an appreciation for the requirement being less prescriptive and allowing the Transmission Owner flexibility in
developing its program.
•
Several respondents felt encroachment of the MVCD should not be a violation.
•
There were several concerns raised with citing the Rating and Rated Conditions to describe the conditions the Transmission Owner
should use to develop its clearances and avoid encroaching into the MVCD.
•
The term “Bulk Power System” should not be used in this Requirement.
The VM SDT considerations for the major comment issues are:
•
Due to the large number of respondents who expressed a positive opinion of eliminating prescriptive items in R3 using the Results-based
approach the SDT felt R3 is appropriate as written.
•
The team has concluded encroachment into the MVCD or ‘spark-over’ distance is a clear indication of improper or negligent vegetation
management and further that such encroachment creates an imminent threat condition.
•
The team has further described Rating and Rated Conditions in the Guideline and Technical Basis Section under Requirement R3.
•
This term “Bulk Power System” has been removed from every instance in the Standard.
Some minor comment issues are:
•
Make Standard dependant on R1 and R2 only. Remove all other requirements.
•
Add NESC clearance requirements to R3.
The VMS SDT considerations for the minor comment issues are:
•
One of the tenets of the Results-based framework is a set of building blocks which support each other. While R1 and R2 are the ultimate
test of reliability they are an insufficient number of building blocks for an Results-based Standard.
•
While adding NESC clearance requirements to R3 may clarify what is needed to develop the document, the SDT felt that Rating and
Rated Conditions adequately cover this.
19
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
Tampa Electric Company
No
A more in-depth technical review of this requirement is required. Our response is predicated upon the
following quote from the draft standard; “...considering all possible locations the conductor may occupy
assuming operation within Rating and Rated Electrical Operating Conditions.”
NERC Staff (12 staff members)
No
As written, R3 does not provide enough clarity as to what should be included in a documented transmission
vegetation management program. R3 should be expanded to include what should be included in the
transmission plan. Such as:R3. Each Transmission Owner shall have a documented transmission vegetation
management program that describes how it conducts work on its Active Transmission Line Rights of Way to
avoid Sustained Outages due to vegetation, considering all possible locations the conductor may occupy
assuming operation within Rating and Rated Electrical Operating Conditions. The transmission vegetation
management program shall:3.1 Specify the methodologies that the Transmission Owner uses to control
vegetation.[1] 3.2 Specify a Vegetation Inspection frequency of at least once per calendar year that takes
into account local[2] and environmental factors. 3.3 Require an annual work plan that identifies the
applicable lines to be maintained and associated work to be performed during the year. It shall be flexible to
adjust to changing conditions and to findings from Vegetation Inspections. Adjustments to the plan within the
year are permissible. The plan shall take into consideration permitting and scheduling requirements from
landowners or regulatory authorities. It shall support the objectives of the transmission vegetation
management program and utilize the methodologies outlined in the transmission vegetation management
program. 3.4 Require a process or procedure for response to imminent threats[3] of a vegetation-related
Sustained Outage. The process or procedure shall specify actions which shall include immediate
communication of the threat to the Transmission Operator or proper operating authority. The process or
procedure shall specify what conditions warrant a response.3.5 Specify an interim corrective action process
for use when the Transmission Owner is constrained from performing vegetation maintenance as planned.
3.6 Specify the maintenance approach used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that Table 1 clearances in Attachment 1 are never violated. The
maintenance approach shall consider the sag and sway of the conductor throughout its operating range under
rated conditions.[1] ANSI A300, Tree Care Operations - Tree, Shrub, and Other Woody Plant Maintenance Standard Practices, while not a requirement of this standard, is considered to be an industry best practice.[2]
Local factors include treatment cycle, extent and type of treatment, and their relationship to the normal growth
rate.[3] The term “imminent threat” refers to a vegetation condition which is placing the transmission line at a
significant risk of a Sustained Outage. Refer to Technical Reference for examples of imminent threat
procedures and conditions for implementation.
Consumers Energy
No
Consumers Energy strongly disagrees with the MVCD as presented in this version of the standard. These
distances do not provide an adequate safeguard to prevent outages since the conductor position relative to
the vegetation is sensitive to electric load and wind at any particular moment while vegetation height is not.
Measurements M1 and M2 require real-time observation of a violation of MVCD to be reportable. As
20
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
presented, vegetation growing beneath the conductor with a clearance of MVCD + 1 foot is not reportable.
However, this same conductor may sag due to load increase or move due to wind displacement within hours
of the real-time observation. If great enough, the sag or displacement may move the conductor in contact
with the vegetation resulting in an outage just hours after being deemed compliant.At a minimum the MVCD
should be designed to provide the Gallet clearance distance at maximum sag or wind displacement
(whichever is greater) at all times. No matter when the line is cleared of vegetation or inspected for
vegetative conditions, if the enhanced MVCD is being met an outage cannot occur until further vegetative
growth occurs. Furthermore, for line clearing operations, tree crews do not and cannot determine in the field
the maximum potential sag or wind displacement to know how much vegetation to clear. They require much
clearer instructions with a set amount of clearing distance to obtain at the time of work. This distance must
account for maximum sag, wind displacement and the Gallet distance at a minimum.
Cleco
No
Encroachment into the MCVD should require the owner to take immediate corrective action to mitigate the
threat. Such an encroachment should not be reportable as a violation. Owners may be hesitant to
communicate possible vegetation threat conditions to the TOP or proper authority if they believe it will be
reported as a violation. We recommend the SDT consider modifying the measure for R1 and R2 to be
applicable only in the interruption of the transmission facility.
GCPD
No
Grant believes that R1 and R2 should be the entire standard and the rest of the requirements should be in
guidelines and supplementary materials to assist in meeting the two results based requirements. We
understand that some risk-based and competency based requirements are necessary for some standards.
Not this one. No grow-in caused outages is the objective. Requiring a specific plan does not show
competency, it just shows you have a plan. Feels very much like the existing standards. "Show us your
Documentation".
Northeast Power Coordinating
Council
No
R3 specifies “...considering all possible locations the conductor may occupy assuming operation within Rating
and Rated Electrical Operating Conditions.” Although both “Rating” and “Rated Electrical Operating
Conditions” appear in the NERC Glossary, inspection of these definitions shows that they are very vague, and
“Rated Electrical Operating Conditions” uses the word “reasonably”, a term FERC has previously indicated as
being unacceptable. From a practical standpoint this seems to allow too much latitude to an entity to do the
least amount of trimming and not consider the extra sag and swing caused by some of the more extreme
operating conditions that “may” occur, such as loading to an STE or DAL limit during a higher velocity wind
than normal, coupled with a higher ambient temperature. An entity could potentially claim that vegetation was
trimmed to normal load levels, normal facility loading sag, and minimum velocity wind speed swings, and be
within the tolerance of the standard as we interpret it. The Drafting Team should clarify what the expectation
is with regard to line loading, sag, and swing due to wind speed and the types of operating conditions it
deems to be justified to create a more exact requirement.
21
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
Nebraska Public Power District
No
same concern as item 1.
Central Maine Power, Iberdrola
USA
No
The TVMP must include clearances bewteen trees and conductors at time of vegetation management
work.Suggest that the TVMP require the use of qualified personnel to manage this program.
Arizona Public Service Company
No
This standard lacks accountability and transparency. This is a reliability standard and the industry is to
prevent outages within the active ROW. It doesn’t matter if the vegetation grows-in, blows-in or falls into the
conductor these are all outages. One is no less of an outage than the other one. They should be treated
equally and the utility should be held accountable for lack of maintaining the transmission system.
FirstEnergy
No
We agree that the previous R1 was too prescriptive and are in favor of the new Requirement R3. However,
we do not agree with all the wording of R3 as well as the Rationale box for R3. 1. Requirement R3 - The
phrase "considering all possible locations the conductor may occupy assuming operation within Rating and
Rated Electrical Operating Conditions" is confusing. We like the wording from the previous (Draft 2) of FAC003-2 and suggest the following rewording of this phrase: "considering all possible locations the conductor
may occupy throughout its operating range under all rated conditions."2. Rationale box for Req. R3 - We
suggest removing the first sentence in the Rationale box for R3. The need to provide a basis on the intent and
competency of the TO in maintaining vegetation is not explicitly stated in the requirement. Also, we are not
sure what is meant by "competency". If it is referring to minimum required competencies for personnel
performing vegetation management, that is outside the scope of this standard.
Ameren
Yes
Bonneville Power Administration
Yes
City of Tallahassee (TAL)
Yes
Consolidated Edison Company of
New York, Inc.
Yes
Duke Energy
Yes
Entergy Services
Yes
Exelon
Yes
22
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
FRCC Manager of Operations
Yes
Ga Transmission Corp
Yes
Manitoba Hydro
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
Orange and Rockland Utilities,
Inc.
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Tennessee Valley Authority
Yes
TO/TOP
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Xcel Energy
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Question 2 Comment
1. NSRS agrees with the revisions to R3. With regard to operations within Ratings and Rated Conditions, are
operations after a contingency considered to be within Ratings and Rated Conditions?2. Could wording be
added to R3 to specify rated conditions include National Electric Safety Code conditions or assumptions?
23
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
Florida Municipal Power Agency
(FMPA) and Some Members
Yes
Although FMPA agrees with the intent of the Measures, FMPA is concerned that the measures M1 and M2
may not meet the purpose of the measures as stated in the latest draft version of the Standard Processes
Manual, which states that that a Measure “(p)rovides identification of the evidence or types of evidence
needed to demonstrate compliance with the associated requirement.” Instead, M1 and M2 provide examples
of evidence that would be used to determine non-compliance, not used to determine compliance.
American Electric Power (AEP)
Yes
American Electric Power agrees with this change.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE agrees with the R3 text in the latest draft of FAC-003-2.
Dominion
Yes
Dominion agrees and finds this approach superior to existing which sometimes appears to be more
administratively focused.
JEA
Yes
Given the basic performance required in R1 and R2 of this version, I agree that specifics about what is
included in the plan are not needed. Each entity should be encouraged to write their plan so that the
occasional human errors and failures that are inevitable still lead to compliance with the performance aspects
of this standard. The team should be sure that the measures do not require unfailing perfect execution of this
procedure so that entities are encouraged to minimize this document.
ITC Holding
Yes
ITC feels that this draft is an improvement by clarifying the action expected by this requirement (“competencybased” program specific methodology documentation) and separating other implementing (“risk based”)
actions from FAC-003-1 as new requirements within this draft version. ITC also agrees with results-based
reliability, a standard principle that is driven by relevant reliability requirements and measureable results
rather than prescriptive requirements driven by documentation.The term “bulk power system” should not be
used in the comment form or any other documentation associated with FAC-003-2.
Independent Electricity System
Operator
Yes
Old Requirement R1 has been distilled down to its essential elements with the removal of the detailed subrequirements that were previously included. This places the onus of developing an effective transmission
vegetation management program (TVMP) on the asset owners where it ought to be, since they have the
requisite expertise. Guidance is however provided in the Technical Reference document to assist
Transmission Owners in developing a TVMP that in their view works for them, and achieves the overall
objective of preventing those vegetation related outages that could lead to Cascading. By specifying the
“what” appropriately and leaving the “how” to the entity, the entity is now in the best position to determine the
most effective deployment of its resources for meeting the goals of the standard.
24
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
CenterPoint Energy
Yes
R3 focuses on its intended impact on Sustained Outages without being overly prescriptive.
Southern California Edison
Company
Yes
SCE prefers the results-based approach to crafting reliability standards because it provides utilities with the
necessary flexibility to develop internal criteria based on widely accepted best practices and industry
innovations.
Western Area Power
Administrtaion
Yes
The old Draft 2 version of R1 was developed to give the regulatory entities substantial and tangible
information from which to judge the adequacy of a TO's overall approach to program management. The old
Draft 2 version of R1 was purposely crafted in this detailed manner as an alternative to attempting to manage
the problematic CCZ concepts contained in Draft 1. Industry strongly rejected the CCZ management
concepts contained in Draft 1 in the first comment period. It appears that the current Draft 3 version of R3
has lost some of the content needed to fully substitute for the management of Draft 1 CCZ concepts. The
addition of an implementation requirement intended to measure the full execution and success of the overall
management approach identified by a TO in response to the new R3 may help to address this shortcoming.
As currently worded, the requirement to simply execute a flexible annual work under the new R7 in Draft 3
does appear extensive enough to fulfill this need.
Oncor Electric Delivery
Yes
The RBS defense-in-depth strategy for this Standard does provide an adequate level of reliability. The
Standards purpose statement refers to the electric Transmission system and corresponding applicable lines
not the BPS or BES as currently defined in the NERC glossary or being proposed (NOPR) RM09-18-000.
Removing prescriptive requirements allows utilities flexibility to document their program and perform their
vegetation management to achieve the goal of no outages that lead to cascading.
IRC Standards Review
Committee
Yes
The SRC agrees with the intent of R3, but questions the need for inspection postponements to be limited to
natural "disasters". A well-planned inspection may be delayed by a common lighting storm. While there is a
need to conduct the inspections and those inspections could be done anytime within the TO's own plans - the
SDT may want to modify the exception to be natural disasters or other conditions that are reported within 5
business days and agreed to as an excused condition by the Regional Reliability Organization.
Southen Company
Yes
The term “bulk power system” should not be used in the comment form or any other documentation
associated with FAC-003-2.
Progress Energy Carolinas
Yes
This separates implementing actions such as inspections, annual plans and imminent threat procedures from
TVMP methodology (which proves competency of the program).This draft is an improvement by clarifying the
action expected by this requirement (“competency-based” program specific methodology documentation) and
separating other implementing (“risk based”) actions from FAC-003-1 as new requirements within this draft
25
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
version.
SERC OC Standards Review
Group
Yes
This separates implementing actions such as vegetation inspections, performing annual work plans and
responding to imminent threats from the required documentation of the TVMP methodology (which proves
competency of the program).This draft is an improvement by clarifying the action expected by this
requirement (program specific methodology documentation requirement) and separating other implementing
actions from FAC-003-1 as new requirements in this draft version.
SERC Vegetation Management
Sub-committee
Yes
This separates implementing actions such as vegetation inspections, performing annual work plans and
responding to imminent threats from the required documentation of the TVMP methodology (which proves
competency of the program).This draft is an improvement by clarifying the action expected by this
requirement (program specific methodology documentation requirement) and separating other implementing
actions from FAC-003-1 as new requirements in this draft version.
Western Area Power
Administration - Upper Great
Plains Region
Yes
WAPA - UGPR agrees with a reliability based standard. In the plains states, we have fewer trees than many
utilities, so having prescriptive requirements that assume we have lines running through forested areas
seems to mandate an excessive amount of detail. We prefer to keep our program very simple -- perform
periodic inspections to identify vegetation problems and then direct applicable resources in to take care of the
problem. Our hope is that a results-based reliability standard will provide some flexibility for those utilities with
smaller scale vegetation encroachments.
Ad Hoc Group subteam formed to
review draft standard
Yes
While the new R3 is less prescriptive than the old R1, it appears to stray from criteria #4 for developing
results-based standards, as described in this comment form. It appears to require only the development of a
document. We understand that in some cases this cannot be avoided. We believe that this is one of those
cases where the reliability objective of building competency in considering all possible locations the conductor
may occupy and assuming operation within Rating and Rated Electrical Operating Conditions over-rides our
reluctance in requiring a registered entity to produce a document rather than a result. We suggest that in a
future revision to standard that this can be combined with R7 to create a comprehensive requirement that the
entity have a vegetation management program that demonstrates it is able to perform those actions
necessary to keep vegetation out of the MVCD.
KCPL
No
The measures for R1 and R2 are zero tolerance for encroachments into the MVCD that did not result in a
“contact” with the transmission facility. Considering the substantial number of miles of transmission involved,
the complexities in anticipation of vegetation growth with numerous growth variables, vegetation management
limitations imposed by other regulations or requirements, and unexpected transmission events that require
substantial efforts regarding physical restoration, it is not reasonable or practical for the measures here to
include encroachments that do not result in an interruption of transmission service. Recommend the SDT
26
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
consider modifying the measures for R1 and R2 to be applicable only in the interruption of a transmission
facility.
27
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
3. Do you agree with the overall layout of the proposed template? If not, please suggest an alternative layout.
Summary Consideration: Most comment forms (43 out of 53) indicated agreement with the overall layout of the proposed template. However,
some expressed concerns over individual parts of the template. The Vegetation Management SDT and the Standards Committee Process
Subcommittee (SCPS) appreciate the commenters’ comments and suggestions.
Some commenters do not agree with grouping Measures and Requirements together on the basis that Measures are compliance related elements
and hence should be grouped with the compliance elements. This suggestion was not adopted. The SCPS asked a specific question about
putting the requirements and measures together, and 50 of the 52 comment forms indicated support for this change.
Some commenters proposed that the Text Boxes are not needed if standards are written clearly; others expressed a concern that the material in
the text boxes may be taken as mandatory, or used by the auditors as guidelines for assessing compliance. Some suggested that it is necessary
to have a clear declaration on which parts/elements in the standards are mandatory. While the rationale for a requirement may be clear to most
people who are familiar with the topic addressed by the standard, as the industry grows and people unfamiliar with the industry try to understand
each requirement, documenting the rationale for each requirement is expected to be useful. The Text Boxes that provide the “rationale” for each
requirement and other explanatory information will remain in the body of the standard until it is balloted, but will be removed from the approved
version of the standard. Their content will be moved to the Guideline and Technical Basis Section.
The subcommittee will ask that NERC’s legal department to write a statement for addition to each standard to clarify which parts/elements of the
standard are mandatory and enforceable and which are provided only as information.
Some commenters raised a concern over the administrative elements. Some are unsure whether or not these elements are mandatory and asked
if they are mandatory, then why they are not included in the Requirement Section. These commenters suggested that if the administrative
reporting is not mandatory, does it belong in the standard, or should the Rules of Procedure Section 1600 be used to collect the data or document.
Some suggested that the Guideline and Technical Basis Section does not belong to a standard; others suggested that the material in the
Guideline and Technical Basis Section be moved to appendices. Some suggested that the materials in the text boxes can also be regarded as
providing the ‘technical basis’ and as such, can also be moved to appendices. Some commenters suggested moving the Guideline and Technical
Basis Section to immediately after the Requirements and Measures section for ease of reference and this suggestion was not adopted. The
compliance elements of the standard include evidence retention as well as other information that is mandatory, and the SCPS believes this should
appear before the elements of the standard that aren’t mandatory.
Some commenters do not support moving VRFs and Time Horizons away from the Requirements to be grouped together with the VSLs. They
expressed a desire to be able to see the VRF associated with each Requirement to know the violation impact. The SCPS will modify the format to
put the information in both places – adjacent to the requirement and in a separate table.
Some commenters expressed a concern with putting the Development Plan, Definitions, Effective Dates and Revision History at the front end
since the readers must screen through 4-5 pages before getting to the standard itself. Some commenters suggested that these housekeeping
items be moved to the end, other commenters suggested putting the Background Section before the Applicability Section in the Introduction. The
28
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
table with effective dates was removed as this will be challenging to keep up to date, however the other sections of the standard will remain where
proposed with the exception that the Definitions Section will be moved ahead of the Background Section.
Some commenters indicated that there appears to be some redundant verbiage in the Background Section and the Guideline and Technical Basis
Section. The SCPS will bring this to the attention of the VM SDT. These two sections were intended to have two distinctly different purposes – the
Background Section identifies “why” the standard exists, and the Guideline and Technical Basis Section provides information that may be useful to
entities in applying the standard.
Some commenters suggested using color code to differentiate between the information that is meant to be temporary and the information that is
expected to stay with the standards. This suggestion was not adopted.
Organization
Yes or No
Question 3 Comment
American Transmission
Company
No
a.) ATC believes that the “Guideline and Technical Basis” section does not belong within the NERC Standard.
ATC feels there are parts of this section that appear to obligate the TO with additional mandatory
requirements. (please refer to additional details in Question #8 below) b.) ATC believes the “Measures”
section immediately following the Requirement is helpful and placement is appropriate, however, the
introductory statement in R1 and R2 is poorly worded. For example, M1 currently states: “ Evidence of
violation of Requirement R1 is limited to:” ATC feels this is a negative approach and recommends that it be
stated in a positive manner such as”” Evidence of compliance to R1 would be to: o Not have any vegetationrelated Sustained Outages due to a grow-in.” c.) ATC would like to clarify whether the “Rational” boxes
remain within the final standard. It seems appropriate to have this information but that it would be better to
have this information appear in the “Guideline and Technical Basis” section.
GCPD
No
Don't need all the extra requirements beyond R2.
Florida Municipal Power Agency
(FMPA) and Some Members
No
FMPA appreciates the improvements and has additional suggestions. Please see responses to the remainder
of the questions, and below, for suggestions:The evidence retention should be grouped with the Measures for
ease of creating a records retention schedule for the standards and requirements.Do we really need a
“Compliance Monitoring and Enforcement Processes” section of the standards? Are there any standards that
don’t have all of these activities?
City of Tallahassee (TAL)
No
I would delete the Rationale in favor of keeping the Guideline and Technical Basis. The Guideline appears to
be more in-depth than the Rationale. This makes the Rationale unnecessary.
Northeast Power Coordinating
Council
No
NPCC participating members want to thank the drafting team for the hard work devoted to developing this
standard, and recognize the difficult issues of producing the first “results based” proof of concept standard
and offer the following, not as criticism, but as helpful suggestions for their consideration based on a cross
section of stakeholder reactions to the draft. 1) Measures are compliance related elements and should not
29
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
appear immediately after the requirements. The older template had the compliance elements grouped
together in a separate section, and we suggest this continues. In the past there have been instances of
RSAW (Reliability Standards Audit Worksheets) not clearly matching the standard’s requirements or
measures. We suggest that this initiative with a results based requirement consistently involve the
development of the associated RSAWs to ensure coordination, and also that the requirement results in a
performance based, competency, or risk based reliability criterion. 2) Effective dates have become a
complex issue. We suggest that rather than having an effective date table in the standard, this type of
information be restricted to the implementation plan and ultimately reside in a NERC relational database
which is currently under discussion/development. NPCC participating members suggest that the “Effective
Dates” section be replaced with “NERC BOT Adopted Date”. Due to their complexities, FERC and Provincial
approvals are something best left to implementation plans and databases. 3) “Rationale” boxes appearing in
the Requirements section are problematic. If a “Rationale” box is required to explain part of the requirement
then the requirement needs to be revised. For example, in R7 the requirement states that a TO shall execute
a flexible annual vegetation management plan. Flexible in this context could have many different
interpretations, yet in the “Rationale” box the use of the word flexible is clearly delineated to mean work may
be deferred if not an imminent threat. In general we believe these boxes add little value, and if the
requirement can’t be understood without the “Rationale” then the requirement needs to be worded
appropriately. Suggest these types of explanatory statements go into guidance documents, or supporting
technical documents, and do not appear in the “Requirements” sections. 4) Also, there seems to be some
confusion regarding the Administrative Procedure section. There seems to be requirements embedded within
it, e.g. “The Transmission Owner will submit a quarterly report to its Regional Entity, or the Regional Entity’s
designee, identifying all Sustained Outages of transmission lines determined by the Transmission Owner....”
Is this an enforceable aspect of the standard? If so, are there any other documents such as the NERC Rules
of Procedure “ROP” or compliance related documents such as the CMEP that have to be changed? NPCC
participating members recognize that this is a results based standard. Administrative requirements should be
removed from the standards, and dealt with elsewhere (such as the ROP). 5) The Guideline and Technical
Basis section contains valuable information, but this adds to the volume of the document. The Drafting Team
should consider moving this to a separate document. In viewing the standards as a whole, the FAC-003
standard is relatively straightforward when compared to the developing of other standards such as the TPL
standard. A similar approach, if applied to the TPL would result in a standard with potentially hundreds of
pages. If the type of work appearing in this section is envisioned for other more complex standards such as
TPL, the DT should consider separating out this section as a single supporting document. 6) Do FERC and
the Provincial governmental authorities approve just the requirements in the Standard, or the whole package?
FRCC Manager of Operations
No
See responses to #8, 10, 11 and 13.
IRC Standards Review
No
The proposal to move the time horizon and the VRF to a separate independent section is not useful. Take
for example R1 and R2 of the proposed standard. A careful read of the two requirements and measurements
30
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Committee
Question 3 Comment
would indicate that there is no difference between them and that it would be better to have one requirement
for all conductors. It is not until the reader gets to the compliance section does the VRF difference show up.
There is no savings to removing the previous format's parenthetical inclusion of time horizon and VRF at the
end of the requirement. The Independent Section can contain all of the proposed information but don't remove
it from the requirement. The format of the standard would not be an issue if NERC would develop a
standards database. Then, the database could be queried in any format the user desires.
ERCOT ISO
No
The Standard itself is several pages into the document. The VRFs/VSLs should be in the
Requirements/Measures Section. The Background, Rationale, Administrative Procedures are additional
information and should be located in an Appendix so it doesn’t clutter the Standard.
CenterPoint Energy
No
We suggest combining and moving the Rationale, Background, Guideline and Technical Basis, and Technical
Reference to a consolidated appendix because there is much duplication in the wording within each of these
sections, and independently they may be misinterpreted as being an integral part of the Requirements and
Measurements which they are not. The Requirements and Measurements should stand clearly on their own.
The appendix should contain examples of how to meet the requirements under various circumstances. The
appendix should be supplementary and optional to the Standard.It is also not clear if the Administrative
Procedure is a mandatory activity. It would be helpful if the intent of this section was stated within the
Standard.
NERC Staff (12 staff members)
No
We suggest using two colors for explanatory information - yellow for information that is temporary - such as
the information explaining the difference between the approved and proposed definitions of “Vegetation
Inspection” - and using blue for all boxes that are intended to remain in the approved standard.We feel that
the Standards Committee Process Subcommittee should pursue adding a statement from NERC’s legal
department indicating which parts of the standard are enforceable. In the meantime, we suggest using the
standard template in order to clearly define the enforceable parts of the standard. The section identified as
“Guideline and Technical Basis” is not really a guideline (typically a proposed process for completing work)
and is not really a “technical basis” (typically a summary of research or engineering judgment, etc. used to
explain the reasoning for something). The information in this section is explaining how the drafting team
expects compliance with the requirements to be measured. We suggest revising the heading to “Application
Guidelines.” This is the term that was originally proposed by the Results-based team and is the heading
identified in the proposed Standard Processes Manual.
Ad Hoc Group subteam formed to
review draft standard
Yes
Arizona Public Service Company
Yes
31
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Bonneville Power Administration
Yes
Central Maine Power, Iberdrola
USA
Yes
Cleco
Yes
Consumers Energy
Yes
Duke Energy
Yes
Entergy Services
Yes
Exelon
Yes
Independent Electricity System
Operator
Yes
Manitoba Hydro
Yes
Nebraska Public Power District
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Orange and Rockland Utilities,
Inc.
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Question 3 Comment
32
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
Southen Company
Yes
Southern California Edison
Company
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Xcel Energy
Yes
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE is supportive of the proposed template.
JEA
Yes
Coupling the measures and rationale with each requirement make the standard easier to follow and to
implement.
Dominion
Yes
Dominion agrees, but suggests that reference(s) to figure(s) and table(s) contain links that can take reader to
that section of the document. This is superior to having to scroll through document. If the reference(s) is
external to this standard document, links may be harder to manage but should at least reference a common
webpage(s) used by NERC for the posting of such documents.
ITC Holding
Yes
ITC feels that the overall layout of the standard (a) improves readability, (b) clarifies expectations, (c) reduces
confusion associated with referencing between pages, and (4) allows for background information and the SDT
rationale to accompany the standards but we would suggest locating Guideline and Technical Basis after
Requirements and Measures for better reference accessibility.
MRO's NERC Standards Review
Subcommittee
Yes
N/A
Tampa Electric Company
Yes
None
Western Area Power
Administration - Upper Great
Yes
None
33
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
FirstEnergy
Yes
Overall, we like the layout of the standard, especially the Effective Date table in the front of the standard, the
combination of Requirements and Measures, and the grouping of the VRF, Time Horizons, and VSL into one
table. However, we would like to see a clearer delineation between the mandatory requirements and the
guidance and rationale information. The standard should explicitly be clear as to what is mandatory and what
is not, which may even require moving the "Rationale" text boxes out of the Requirements and Measures
section. FE believes the information presented in the Rationale text boxes can be effectively covered in the
"Guidelines and Technical Basis".
Western Area Power
Administrtaion
Yes
The format could be enhanced by moving the Guidelines and Technical Basis section forward to be included
with the corresponding Requirement, Measure, and Rationale. This would be helpful because it is awkward
flipping back and forth between these two sections when trying to fully understand a requirement.
Pepco Holdings, Inc. - Affiliates
Yes
The general layout is quite effective. Still, it would be good to keep the VRFs and time horizons within the text
of the requirement.
Ga Transmission Corp
Yes
The layout is adequate but many things are needing further explanation such as the MVCD.
Progress Energy Carolinas
Yes
The overall layout improves readability, clarifies expectations, reduces confusion associated with referencing
between pages, and allows for background information and SDT rationale to accompany the standards
(reducing the need for interpretation).
SERC OC Standards Review
Group
Yes
The overall layout improves readability, clarifies expectations, reduces confusing references between pages,
and allows for background and rationale to accompany standards.
SERC Vegetation Management
Sub-committee
Yes
The overall layout improves readability, clarifies expectations, reduces confusing references between pages,
and allows for background and rationale to accompany standards.
East Kentucky Power
Cooperative, Inc.
Yes
The overall layout is greatly improved. This draft is easier to read and understand and clarifies the expected
actions required in the standard.
American Electric Power (AEP)
Yes
The overall template layout is acceptable
Tennessee Valley Authority
Yes
This aids the understanding of the standard.
Plains Region
34
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
Ameren
Yes
This draft is much more user friendly and easier to follow; appreciate the follow up information.
Consolidated Edison Company of
New York, Inc.
Yes
We do believe the overall layout is effective but the SDT should consider putting the Background Section
before the Applicability Section in the Introduction and also try to reduce any redundant verbiage in the
Background Section and the Guideline and Technical Basis Section. A twenty-one page Standard is too
lengthy and the supporting Technical Reference document properly addresses many of the issues mentioned
in the Guideline and Technical Basis Section.
KCPL
Yes
35
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
4. Do you agree with grouping the standard development timeline (previously called roadmap) with the revision history, and the
effective date(s) and putting this administrative information up front before the Introduction Section? Please explain.
Summary Consideration: A vast majority of the comment forms (48 out of 52 who responded to this question) indicated support for grouping the
Development Timeline, Revisions History and Effective Dates and putting them up front before the introduction Section.
Some commenters suggested moving this group of information to the end, other commenters suggested that the Definition Section be taken out of
the group and placed just before Introduction. The SCPS does not think that moving the grouped information to the end will result in much
improved readability. Readers can get to the beginning of a standard as quickly by scrolling or flipping through the pages.
The SCPS agrees with moving the Definition Section to just before the Introduction Section since Definitions are part of the balloted materials and
the team adopted this suggestion. Note that after the standard is balloted, the definitions, if approved, are moved out of the standard and into the
Glossary of Terms Used in Reliability Standards.
Some commenters suggested adding a table of contents. The SCPS will consider this in the next posting.
Organization
Yes or No
Question 4 Comment
IRC Standards Review
Committee
No
For this standard one must read through 7 pages before getting to the reason for the posting. The
administrative information should be relegated to the end of the posting not the beginning.Under exceptions in
the Effective Dates section of the standard, IROLs are referenced as only being created by the Planning
Coordinator. Because Reliability Coordinators must also establish IROLs per FAC-011 and FAC-014, we
suggest that reference to the Planning Coordinator should be redacted and IROLs should be discussed
regardless of whether the Planning Coordinator or Reliability Coordinator creates them.
Consolidated Edison Company of
New York, Inc.
No
The only issue we have with the administrative information being before the Introduction Section is with the
Definition of Terms Used in the Standard Section. We feel this should be part of the Introduction and not a
stand alone section.
Orange and Rockland Utilities,
Inc.
No
The only issue we have with the administrative information being before the Introduction Section is with the
Definition of Terms Used in the Standard Section. We feel this should be part of the Introduction and not a
stand alone section.
ERCOT ISO
No
This information should be located at the end so that it doesn’t distract from the main purpose of the
Standard. It is cumbersome to read through several pages before getting to the actual language of the
Standard.
Ad Hoc Group subteam formed to
Yes
36
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
review draft standard
American Transmission
Company
Yes
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
Central Maine Power, Iberdrola
USA
Yes
City of Tallahassee (TAL)
Yes
Cleco
Yes
Consumers Energy
Yes
Duke Energy
Yes
Exelon
Yes
GCPD
Yes
JEA
Yes
Manitoba Hydro
Yes
Nebraska Public Power District
Yes
NERC Staff (12 staff members)
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
37
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
Oncor Electric Delivery
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southen Company
Yes
Tennessee Valley Authority
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Western Area Power
Administrtaion
Yes
Ameren
Yes
Appreciate the ability to reference up front.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE agrees with the proposed grouping and placement of these items.
Dominion
Yes
Dominion agrees that the new format is superior to the old. However, we suggest a table of contents be
added to include at a minimum, sections for (1) Definitions of Terms Used in Standard (2) Effective dates, (3)
Introduction, (4) requirements and measures (5) Compliance (6) Time Horizons, VRF and VSLs (7)
Administrative (8+) guidelines, technical basis, tables or figures referenced in standard.
Entergy Services
Yes
Easy to follow.
Ga Transmission Corp
Yes
I do not see a problem with this change.
38
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
Xcel Energy
Yes
It is acceptable to do so, however it is not clear as to how the effective date portion will be incorporated in a
final version of the standard. Will there be some kind of cover page to at least indicate the standard or will it
just be a small title bar at the top? (i.e. - what does page 1 of the standard look like?)
ITC Holding
Yes
ITC agrees with locating the revision history and administrative information before the introduction. This
alignment improves clarity and readability by providing a single location for this information.
Florida Municipal Power Agency
(FMPA) and Some Members
Yes
Just a question, when the standard becomes effective, how will it be posted? FMPA assumes that this section
will move to the end of the standard instead of the front when approved.
CenterPoint Energy
Yes
No preference.
Tampa Electric Company
Yes
None
Northeast Power Coordinating
Council
Yes
NPCC participating members believe this is acceptable. However our previous response to question 3 above
still applies regarding the Effective Date section. It should be removed from the standard, and either appear
in an implementation plan, or more effectively in a NERC relational database.
Independent Electricity System
Operator
Yes
Since in this case the effective dates of all requirements are all the same, we believe the effective dates table
could be significantly condensed.
East Kentucky Power
Cooperative, Inc.
Yes
The format provides for better clarification and is easier to read and comprehend.
MRO's NERC Standards Review
Subcommittee
Yes
The NSRS likes the way the standards is now formatted and finds it more user friendly.
American Electric Power (AEP)
Yes
These changes make sense to American Electric Power.
SERC OC Standards Review
Group
Yes
This format adds clarity and improves readability.
SERC Vegetation Management
Sub-committee
Yes
This format adds clarity and improves readability.
39
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
Progress Energy Carolinas
Yes
This grouping improves clarity and readability by providing a single location for this information.
Western Area Power
Administration - Upper Great
Plains Region
Yes
WAPA - UGPR is neutral on location of these items.
Southern California Edison
Company
Yes
We agree that grouping the administrative information up front is logical and makes for a cleaner
presentation.
FirstEnergy
Yes
We agree with having a detailed table showing the effective dates of each requirement. However, we would
like to see NERC go back into the table and specify the dates of NERC and FERC effective dates once they
are known. Having the statement "1st day of the 1st quarter one year after applicable regulatory approval" in
the standard does not help the user of the standard when they are working towards compliance, and requires
them to go elsewhere to find when the approvals took place. All this information should be in the standard
when available and NERC staff should be afforded the latitude to do so even without needing to use its Errata
process. Placing the dates directly within the standard is more convenient for the end user.
KCPL
Yes
40
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
5. Do you agree with grouping the Requirements and Measures together, in one Section now called Requirements and Measures?
Please explain.
Summary Consideration: A vast majority of the comment forms (50 out of 52) indicated support for grouping the Requirements and Measures in
one Section.
Some commenters suggested moving the Measures back to the Compliance Section and adding a reference to each Measure stating which
Requirement it refers to. The SCPS does not think that moving the Measures back to the Compliance Section will result in any improvement in
readability. Keeping the Measures together with the Requirements provides readers with a clear and easy view of what evidence needs to be
provided to demonstrate compliance with the Requirements.
Organization
Yes or No
Xcel Energy
Question 5 Comment
We are indifferent as to the placement of the Measures, however it does appear to create awkward shaped
paragraphs when Requirements and Measures are place around Rationale boxes.
Northeast Power Coordinating
Council
No
Bonneville Power Administration
Yes
Cleco
Yes
Duke Energy
Yes
IRC Standards Review
Committee
Yes
Manitoba Hydro
Yes
Nebraska Public Power District
Yes
NERC Staff (12 staff members)
Yes
As commented earlier in question 3, this is a compliance related issue and should be in the Compliance
section. NPCC participating members believe clear concise requirements should be the focus, and inserting
measures immediately after the requirements adds little value. In addition, RE compliance staffs who use the
metrics find no value to moving it as well. This format would ease working with the document as a working
draft, but should not be in an adopted document. Consider moving Measures back to the compliance section,
and add a reference to a Measure’s wording stating which requirement the measure refers to. Only adding a
statement when the Requirement and Measure numbering don’t line up could be considered.
41
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
North Carolina EMC
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southen Company
Yes
Southern California Edison
Company
Yes
TO/TOP
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Western Area Power
Administrtaion
Yes
Central Maine Power, Iberdrola
USA
Yes
Adds clarity between requirements and measures .
Arizona Public Service Company
Yes
APS doesn’t agree with all of the requirements.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
Yes
BGE agrees it makes sense to group these two sections together.
42
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
CNE & CENG)
JEA
Yes
Coupling the measures and rationale with each requirement make the standard easier to follow and to
implement.
Dominion
Yes
Dominion finds this format improved over the existing as reader can more easily correlate the requirement
(process/procedures) to the measure (evidence).
Exelon
Yes
Exelon agrees this is a good practice that will help ensure Requirements and Measures are aligned
Florida Municipal Power Agency
(FMPA) and Some Members
Yes
FMPA agrees that grouping the Requirements and Measures together in one section is a great idea; however,
to realize even more benefit, we now have the opportunity to eliminate redundant wording, e.g., M3 can be
shortened to: “A documented transmission vegetation management program” and eliminate the rest of the
words that are redundant with R3.
Entergy Services
Yes
Great addition and improvement!! Much clearer and easier to follow.
City of Tallahassee (TAL)
Yes
However, if you keep the Rationale text boxes, keep the Measures in the same column as the requirement.
This will result in a more consistent “look and feel” to all the requirements (M3 for R3 is the example).
FRCC Manager of Operations
Yes
In addition the DT could also eliminate redundant wording in the standard requirement, e.g., M3 can be
shortened to: “A documented transmission vegetation management program” and eliminate the rest of the
words that are redundant with R3 or use words in the measure that refer back "to the requirement above".
ERCOT ISO
Yes
Including a specific measure with each requirement adds clarity; however, it isn’t clear whether each measure
is exclusive to the requirement that it follows. Is it possible that some requirements will have multiple
measures that are not listed immediately following the requirement?
ITC Holding
Yes
ITC agrees with Requirements and Measures grouped together
GCPD
Yes
Makes the standard template much easier to read and use.
Consumers Energy
Yes
Much easier to follow in this format.
Ameren
Yes
Much more user friendly to be able to see the requirement and the measurement together for clarification.
43
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
CenterPoint Energy
Yes
No preference.
MRO's NERC Standards Review
Subcommittee
Yes
NSRS prefers to have the requirements, measures, VRFs, VSLs and Time Horizons together instead of
referencing to another page or part of the standard.
American Transmission
Company
Yes
See ATC’s comment on “Measures” in Question #3 above.
Tennessee Valley Authority
Yes
This aides in understanding of the standard. Grouping the VSL and VRF for each requirement along with the
measurement could be beneficial too.
Ga Transmission Corp
Yes
This also is OK no problem with the layout.
Progress Energy Carolinas
Yes
This change also improves readability and improves understanding of the requirement.
SERC OC Standards Review
Group
Yes
This format adds clarity and improves readability.
SERC Vegetation Management
Sub-committee
Yes
This format adds clarity and improves readability.
East Kentucky Power
Cooperative, Inc.
Yes
This format provides for better readability and clarification.
Tampa Electric Company
Yes
This improves the clarity and understanding to the requirements.
Independent Electricity System
Operator
Yes
This is useful to avoid having to move back and forth between separate sections to find out what is needed to
show that a requirement is met. We do not have a strong preference for this re-grouping however.
Western Area Power
Administration - Upper Great
Plains Region
Yes
WAPA - UGPR believes this makes it easier to identify the requirement and what we need to provide to
demonstrate with are in compliance with the requirement.
FirstEnergy
Yes
We agree that grouping the Requirements and Measures together is convenient when utilizing the document
for compliance.
44
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
Consolidated Edison Company of
New York, Inc.
Yes
We agree with grouping the Requirements and Measures together since it does add another level of clarifying
description for our field forces who are ensuring compliance during vegetation management activities. The
Measures for R1 and R2 describe evidence of violation while the Measures for the remaining Requirements
R3 - R7 describe evidence of compliance. All Measures should be written consistently as either evidence of
compliance or evidence of violation.
Orange and Rockland Utilities,
Inc.
Yes
We agree with grouping the Requirements and Measures together since it does add another level of clarifying
description for our field forces who are ensuring compliance during vegetation management activities. The
Measures for R1 and R2 describe evidence of violation while the Measures for the remaining Requirements
R3 - R7 describe evidence of compliance. All Measures should be written consistently as either evidence of
compliance or evidence of violation.
Ad Hoc Group subteam formed to
review draft standard
Yes
We agree with the understanding that the specific requirements of the standard are the enforceable elements
of the standard. The rationale and measures add clarity to support a results-based requirement.
American Electric Power (AEP)
Yes
Yes, this is a more readable format.
KCPL
Yes
45
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
6. Do you agree with grouping VRFs, Time Horizons and VSLs together, and putting them in a table separate from the Requirements
and Measures Section? Please explain.
Summary Consideration: A vast majority of the comment forms (47 out of 54) indicated support with grouping VRFs, Time Horizons and VSLs
together.
Some commenters suggested moving the VERs and Time Horizon back to the Requirements.
Some commenters agree with grouping VRFs, VSLs and Time Horizons together, but expressed a desire to also see the VRFs and Time Horizons
in the Requirements as well. The SCPS adopted this suggestion in the next posting.
Some commenters suggested listing the applicable table rows with each requirement to consolidate all pertinent information with the requirement.
The SPCS believes that this will convolute the Requirements and Measures Section with little added value.
Some suggested adding the penalty matrix to facilitate discussions with property owners/agencies resisting maintenance activates. The SCPS
does not believe the penalty matrix is a standard element or technical reference material. This suggestion was not adopted.
Some commenters indicated that although a non-binding poll is taken of the VRFs and VSLs, it appears that the Time Horizons are part of the
standard that is still subject to stakeholder ballot. Commenters suggested that the SDT should explain how this will be made clear to balloters and
asked if there is an intent to modify the standards process to remove the time horizons from the portions of the standard that are subject to ballot.
In response to the above suggestions, the SCPS will retain the grouping as proposed, but will also put Time Horizons and VRFs adjacent to their
associated Requirements.
Organization
Yes or No
Question 6 Comment
Pepco Holdings, Inc. - Affiliates
No
Agree that the grouping of the subject material is appropriate, but it is not necessary to also remove the
VRFs and time horizons from the requirement.
JEA
No
I would prefer to have the VRF’s and time horizons together with the requirements and measures section. The
VSL’s separate is appropriate as that is not information needed while complying, but only after a failure.
Manitoba Hydro
No
If the VRF’s Time Horizons and VSLs were listed in with each requirement and measure section, it would
eliminate the need for cross referencing 2 sources of information.
Oncor Electric Delivery
No
It would be nice to see the associated VRF’s and Time Horizon with the requirements. No text, but
referenced.
ERCOT ISO
No
The associated VRFs/Time Horizons/VSLs should be identified alongside each Requirement so that all
relevant criteria for a given Requirement are organized together.
46
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
IRC Standards Review
Committee
No
While we agree that the grouping of the subject material is appropriate, it is not necessary to also remove the
VRFs and time horizons from the requirement.
Duke Energy
No
While we like grouping VRFs, Time Horizons and VSLs together in a table, we would also like to see each
VRF and Time Horizon listed with its requirement. It’s a small amount of information that we think adds value
in both places.
Ad Hoc Group subteam formed to
review draft standard
Yes
Ameren
Yes
American Transmission
Company
Yes
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
Central Maine Power, Iberdrola
USA
Yes
Cleco
Yes
Consolidated Edison Company of
New York, Inc.
Yes
Consumers Energy
Yes
Dominion
Yes
East Kentucky Power
Cooperative, Inc.
Yes
Exelon
Yes
47
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
FRCC Manager of Operations
Yes
Independent Electricity System
Operator
Yes
Nebraska Public Power District
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
Orange and Rockland Utilities,
Inc.
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southern California Edison
Company
Yes
TO/TOP
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Western Area Power
Administrtaion
Yes
Xcel Energy
Yes
MRO's NERC Standards Review
Yes
Question 6 Comment
Again it is good to have this information together in place of referencing some other page or part of the
48
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Subcommittee
Question 6 Comment
Standard.
Tennessee Valley Authority
Yes
Also please consider parsing out a copy of each VSL/VRF with in each individual requiremnt and measure
part of the standard as mentioned in question 5 above.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE supports grouping VRFs and VSLs together in a separate table.
Southen Company
Yes
Consider putting the appropriate line from the table with each requirement in the body of the standard in
addition to the table format. This does make the standard longer and does introduce some redundancy, but it
would make each requirement easier to read and interpret on a “standalone” basis.
City of Tallahassee (TAL)
Yes
I believe this makes it easier to follow the Requirements.
ITC Holding
Yes
ITC Agree's
Florida Municipal Power Agency
(FMPA) and Some Members
Yes
Much easier to find and understand
CenterPoint Energy
Yes
No preference.
Entergy Services
Yes
This grouping helps to clarify the manner in which the violations will be ranked.
Progress Energy Carolinas
Yes
This grouping improves the template used by previous versions by providing a single view of the impact and
risk that has been associated with each requirement. Progress Energy believes that this change would also
be improved if the applicable VRF/VSL/Time Horizon table rows were also listed with each requirement
(consolidating pertinent info with the requirement). Another improvement would be including the penalty
matrix (or including a URL link) to facilitate Transmission Owner discussions with property owners and other
governmental agencies.
SERC OC Standards Review
Group
Yes
This improves the template used by previous versions by providing a single view of the impact consideration
of each requirement. An improvement would be also listing the applicable table rows with each requirement
which consolidates all pertinent info with the requirement. Also, adding the penalty matrix would facilitate
discussions with property owners/agencies resisting maintenance activates.
49
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
SERC Vegetation Management
Sub-committee
Yes
This improves the template used by previous versions by providing a single view of the impact consideration
of each requirement. An improvement would be also listing the applicable table rows with each requirement
which consolidates all pertinent info with the requirement. Also, adding the penalty matrix would facilitate
discussions with property owners/agencies resisting maintenance activates.
GCPD
Yes
This is audit stuff that does need to stay together.
Northeast Power Coordinating
Council
Yes
This is consistent with FERC’s determination that these are compliance elements and not part of the standard
requirements. It will also assist with compliance determinations.
Western Area Power
Administration - Upper Great
Plains Region
Yes
WAPA - UGPR is neutral on location of these items.
FirstEnergy
Yes
We agree with grouping these items together. It may also be beneficial to include links directly in the table to
explanations of VRFs, Time Horizons, and VSLs so that someone unfamiliar with, for instance, what a "LongTerm Planning" horizon means, they could look it up.
NERC Staff (12 staff members)
Yes
We agree with the idea behind the grouping. However, according to the Reliability Standard Development
Procedure - Version 7, although a non-binding poll is taken of the VRFs and VSLs, it appears that the Time
Horizons are part of the standard that is still subject to stakeholder ballot. The SDT should explain how this
will be made clear to balloters. Is there intent to modify the standards process to remove the time horizons
from the portions of the standard that are subject to ballot? This issue needs to be addressed by the
Standards Committee Process Subcommittee.
Tampa Electric Company
Yes
With all of the VRFs, Time Horizons and VSLs grouped together it facilitates the overall understanding of
these factors as they relate to the standard.
Ga Transmission Corp
Yes
Yes this was a good change.
American Electric Power (AEP)
Yes
Yes; this format is more user-friendly.
KCPL
Yes
50
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
7. Do you agree with the insertion of text boxes, where necessary, to help readers better understand the basis of the Definitions and
Requirements? Please explain.
Summary Consideration: The majority of comment forms (43 out of 54) agree with the insertion of text boxes.
Some commenters disagree with the insertion as the material in the text boxes will be subject to FERC’s review and approval.
Other commenters raised a concern that the materials may become pseudo requirements; others are concerned that the material in the text boxes
is also mandatory, or may be used by auditors as guidelines to assess compliance.
Some believed that text boxes are not necessary given there is a Guideline and Technical Basis Section. Some suggested removing the text
boxes and moving the material to the Guideline and Technical Basis Section.
Some commenters indicated that some text boxes can be temporary (for example, those associated with a definition). More clarity is needed to
distinguish this type of text box in the drafting stage, with the expectation that they will be removed after a standard is approved and the definition
becomes effective (and removed from the standard).
The SCPS appreciates these comments and the commenters’ concerns. The SCPS agreed to post the text boxes with the working document but
move the text boxes into the Guideline and Technical Basis Section to support the standard until it is balloted, but will be removed from the
approved version of the standard before it is submitted for adoption and filing with regulatory and governmental authorities. Their content will be
moved to the Guideline and Technical Basis Section. The material in the Guideline and Technical Basis Section is intended to provide guidance
but is not intended to expand on any of the requirements and is not intended to include any mandatory performance. A legal statement will be
added to the standard to make this clear.
Organization
Yes or No
Question 7 Comment
Exelon
No
Additional clarifications should be included in appendices or reference documents. Including them with the
requirements and measures will cause confusion concerning what the compliance obligation is. This will
introduce uncertainty to the compliance monitoring process.
American Transmission
Company
No
Although the test boxes provide some addition help, ATC believes that these text boxes should appear in the
Guideline and Technical Basis section and that whole section should appear in a companion document to the
standard but not be included as part of the standard. Also, see ATC’s comment on Rational in Question #3
above.ATC believes that guidance information should not be reviewed and approved by FERC and the
inclusion of such information within the standard opens this language up to FERC’s oversight and approval.
Northeast Power Coordinating
Council
No
As stated in question 3 above, NPCC participating members believe crisp, clear results based requirements
require no further explanation. Requirements must be written so they are clearly understood. Text boxes
clutter up the standard. Questions could arise if these add “pseudo” requirements to the standards, and there
is any inconsistency in what is stated about requirements. NPCC strongly suggests their removal in favor of
51
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
clear, measurable, and high quality results based requirements.
City of Tallahassee (TAL)
No
I would delete the Rationale in favor of keeping the Guideline and Technical Basis. The Guideline appears to
be more in-depth than the Rationale. This makes the Rationale redundant and unnecessary.
CenterPoint Energy
No
It is not clear how the information in the text boxes will be used to determine compliance with the
Requirements and Measures. It appears that in the Definition of Terms Used in Standard section that the text
boxes add to the definitions or are footnotes to historical information. The Definitions should stand on their
own and be robust enough to ensure they are helpful in determining compliance with the Requirements and
Measures. In the Requirements and Measures section, the text boxes appear to contain partial information
from the Guideline and Technical Basis, and Technical Reference. In all cases the information is not helpful
and provides incomplete information. The text boxes should be deleted and pertinent information to
compliance should be incorporated into the Definitions, Requirements, and Measures. Any explanatory text
or examples should be moved to an appendix as supplementary and optional to the Standard.
ERCOT ISO
No
It is not clear whether the information in the text boxes is “For Information Only.” While the additional
information may be helpful, it appears to add sub-requirements within the Standard. This information could
be included under a “Rationale” section in an Appendix. However, if the information clouds the purpose of the
Requirements or dictates how to comply, then it should be eliminated completely.
Consumers Energy
No
Not necessary given the “Guidelines and Technical Basis”.
Nebraska Public Power District
No
Text boxes and other supporting information are a benefit to the reader as a clarification guide, but should be
placed in something other than the Standard.
IRC Standards Review
Committee
No
The concept of text boxes needs further discussion. The idea of using text boxes for clarity and explanation is
valuable, but is the material in the text box mandatory? If it includes mandatory material than it is not a good
idea - all mandatory requirements must be in the requirement. If the text boxes are retained to explain how a
phrase is being used (e.g. to make clear what compound actions apply to what compound time frames), then
yes, this approach can be invaluable.
Cleco
No
The inclusion of the text implies additional requirements. Keep quidance to a separate paper.
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
52
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Consolidated Edison Company of
New York, Inc.
Yes
Duke Energy
Yes
FRCC Manager of Operations
Yes
Manitoba Hydro
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Orange and Rockland Utilities,
Inc.
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
Southen Company
Yes
Tennessee Valley Authority
Yes
TO/TOP
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Question 7 Comment
1. We agree. The rationale boxes will cut down on interpretations. 2. Are the rationale boxes part of the
approved standards for which registered entities will be audited. Are the rationale boxes federal law?3. Under
R3, a reference to the National Electric Safety Code in the rationale box would be helpful. (The goal is to
53
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
verify that utilities will not be held in violation of this standard when operating beyond the NESC conditions.)
North Carolina EMC
Yes
Additional background in the test boxes is very helpful.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE agrees this would help clarify the basis of the Definitions & Requirements.
Dominion
Yes
Dominion agrees, but suggests that reference to figure(s) and table(s) contain links that can take reader to
that section of the document. This is superior to having to scroll through document. If the reference(s) is
external to this standard document, links may be harder to manage but should at least reference a common
webpage(s) used by NERC for the posting of such documents.
Xcel Energy
Yes
However, the boxes should be adding clarity, not "defining' terms or stipulating further requirements/criteria
that must be met. See MVCD in R1 & R2 and the incorporated Table 2, and comments to #1 & #13 in this
form. The standard should be able to convey the requirements without the text boxes or, if the text boxes are
used, the purpose and legal import of such boxes should be clarified. Further, it should be clarififed that for
text boxes that provide examples (e.g., the boxes on page 2 in the definitions section), such boxes should
clearly state that the examples are in no way limitations.
Ga Transmission Corp
Yes
I do like the text boxes.
ITC Holding
Yes
ITC agrees, but would like to suggest that the text boxes include additional pertinent information from the
Technical Reference that would be helpful as reliability talking points to the public. Example: (R3): The
following is a sample description of one combination of strategies which may be utilized by a Transmission
Owner. A Transmission Owner’s basic maintenance approach could be to remove all incompatible vegetation
from the right of way if it has the right to do so and has no constraints
Ameren
Yes
It's helpful to understand the SDT's logic for requirements, clarification is always appreciated.
GCPD
Yes
May help in cutting down the volume of SAR interpretation requests.
Central Maine Power, Iberdrola
USA
Yes
R3 - this may be a good place to describe clearances at time of vegetation management work
Florida Municipal Power Agency
Yes
The clarification is important and will reduce the number of requests for interpretation if interpretation is
already provided to some extent. Just a caution about how the text boxes will be used in the audit process,
54
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
(FMPA) and Some Members
Question 7 Comment
clarification concerning their use during compliance monitoring would be great.
NERC Staff (12 staff members)
Yes
The explanatory information posted with the proposed definitions, like the definitions, is only relevant to this
standard, and some of the information is only relevant to the point where the definition becomes enforceable.
What is the expectation for what will happen to this information in the future? We suggest that the text boxes
associated with requirements include a reference to that requirement. (Change “Rationale” to “Rationale for
R1”)
Western Area Power
Administrtaion
Yes
The format could be enhanced by moving the "Guidelines and Technical Basis" section forward to be included
with the corresponding Requirement, Measure, and Rationale. Perhaps the "Guidelines and Technical Basis"
could also be combined with the corresponding "Rationale" text box. This would be helpful because it is
awkward flipping back and forth between these two sections when trying to fully understand a requirement.
SERC OC Standards Review
Group
Yes
This format adds clarity and improves readability.
SERC Vegetation Management
Sub-committee
Yes
This format adds clarity and improves readability.
East Kentucky Power
Cooperative, Inc.
Yes
This format is simpler, easier to read, understand and implement.
Progress Energy Carolinas
Yes
This format provides clarity and improves readability. Progress Energy believes that having SDT basis
information for a requirement in the standard will reduce the need for interpretation and improve the
interpretation process for a requirement, if necessary.
Tampa Electric Company
Yes
This improves the clarity and understanding to the requirements.
American Electric Power (AEP)
Yes
This is a good change.
JEA
Yes
This is extremely helpful in understanding the intent of the requirement
Western Area Power
Administration - Upper Great
Plains Region
Yes
WAPA - UGPR believes that the expanations within the text boxes provided additional useful information.
55
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
Entergy Services
Yes
We agree that text boxes being used for additional clarity is a benefit if used in a correct and clear manner. It
needs to be specifically stated in the document that the text boxes are to be used for reference only, entities
will not be required to specifically follow the language in the Rationale box, and that each utility should specify
their own process for addressing each Requirement. For example....the Rationale box for R4 states that
"Verified knowledge includes observations by journeyman lineman, utility arborist, or other qualified
personnel.......". Our process will specify exactly who that qualified personnel is (Transmission Specialist or
another qualified Entergy Employee in the Transmission Vegetation Group, for example). We will specify this
in our internal processes.
FirstEnergy
Yes
We agree that text boxes can be useful for requirements and definitions. However, the SDT may want to
consider eliminating the text boxes since this information is already provided in the Guidance and Technical
Basis section. Also, we have the following additional comments:General:1. With respect for the rationale text
boxes for definitions, it is not clear if these boxes will be retained once the definitions are moved out of the
standard and added to the NERC Glossary.2. The rationale text boxes can be beneficial for the
requirements, but some of the text boxes in this current draft of FAC-003-2 seem to include prescriptiveness
that is not found in the requirement. An example is in the text box for Req. R4, which implies timeliness of
notification of an imminent threat with the use of the word "rapid". In the case of R4, the requirement should
state that notification be carried out immediately (see our suggested rewording of R4 in Question 13). 3.
Although these text boxes are not enforceable for compliance, we are not convinced that an auditor will view
this as simply guidance.Specific:1. Definition for Active Transmission Line ROW - Example 3 of Inactive
ROW - Consider removing this example; situations where vegetation is left unmanaged on portions of the
ROW where double-circuit structures exist with only one circuit strung with conductors poses an unnecessary
increased risk for vegetation related outages. 2. Rationale box for Req. R3 - See our comments in Question
23. Rationale box for Req. R4 should be revised to state: "To ensure rapid notification of the responsible
control center when an occurrence of an imminent threat condition is verified. Evidence of verified knowledge
includes observations by journeyperson, lineperson, utility arborist, or other qualified personnel, or a report
verified by these personnel. This notification allows the responsible control center to take the appropriate
action until the threat is relieved. Appropriate actions may include a temporary reduction in the line loading or
switching the line out of service."4. Rationale box for Req. R5 - (1) The last statement of this box seems
incomplete. It should be revised to state: "This requirement is not intended to address situations where the
transmission line is not at immediate risk and the work event can be rescheduled or re-planned using an
alternate work methodology."; and (2) We suggest revising the first statement to "Legal actions filed by
property owners, easement restrictions and other events...."
Southern California Edison
Company
Yes
We agree that the insertion of text boxes aids readers in understanding the basis for the Definitions and
Requirements.
56
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
Independent Electricity System
Operator
Yes
We agree that the side-bars give useful contextual information that is not part of standard. This is good and
avoids the reader’s attention being completely redirected to a reference document when seeking clarification
of the intent of a requirement. We believe however that these text boxes should be used sparingly and the
content should also be brief to minimize possible distractions to the reader.It should also be made clear in the
standard that these text boxes are not intended to impose additional requirements and in the event of any
perceived conflict, the text of the requirement will take precedence.
South Carolina Electric and Gas
Yes
We agree, however we would like clarification on whether entities can be held accountable for rationale
portions of the standard as they are for interpretations that are added to a standard.
Ad Hoc Group subteam formed to
review draft standard
Yes
We understand this question to refer to the “rationale” text boxes in this standard. Additional information such
as this is useful to the entity in explaining and clarifying the understanding of the drafting team in articulating
the requirement and thus supports a fuller understanding of the entity in achieving compliance with the
requirement.
KCPL
No
I like information that helps to “guide” and “provide guidance”, however, we already having trouble with
information from FAQ’s, White Papers, and other guiding documents creeping into the requirements by
auditing teams. The inclusion of “guiding information” in the text of the Standard itself may promote adding to
requirements. Although helpful, I recommend removing this text from within the body of the Standard.
57
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
8. Do you agree with the addition of a Guideline and Technical Basis Section to place technical materials and other related information that
assists entities in understanding how to comply with the standard but does not contain mandatory actions/activities? Please explain.
Summary Consideration: Most of the comment forms (38 out of 54) indicated agreement with the addition of the Guideline and Technical Basis
Section.
Some commenters expressed a concern over how the materials contained in this Section may be used in compliance monitoring and
enforcement.
Some commenters suggested that it should be expressly stated that this section is for information purposes only and is not part of the Standard
Requirements. They further suggested compiling all of the “Information Only” materials into an Appendix as a preferred alternative. Others
suggested that guideline materials be moved into a separate document.
Some commenters suggested that while this Section contains useful materials, NERC should consider developing a separate set of Guideline
documents to afford the industry a knowledge base that is not directly sanctionable for non-compliance.
Some commenters expressed a concern that being located within the standard, the Guideline Section will imply additional requirements for
mandatory compliance, or get used by auditors as compliance issues.
The SCPS assesses that the industry likes the idea of having technical guidelines for standards. Guideline materials, whether they are put in a
separate document or included in a standard, can be used by anyone to assess compliance with standards. Putting them outside of the standard
does not eliminate this possibility.
The material in the Guideline and Technical Basis Section is intended to provide guidance but is not intended to expand on any of the
requirements and is not intended to include any mandatory performance. A legal statement will be added to the standard to make this clear. The
SCPS believes that as long as it is made clear that only the requirements and provision of evidence are mandatory, any supporting materials can
be provided in a standard to aid readers better understand the standard without binding them to complying with the supporting materials. The
intent of the description of the elements of a standard in the proposed Standard Processes Manual is to make it clear that there is a distinction
between the enforceable sections of the standard and the compliance and supporting information sections of the standard.
Organization
Florida Municipal Power Agency
(FMPA) and Some Members
Yes or No
Question 8 Comment
No
Although FMPA agrees that a Guideline and Technical Basis document is important, FMPA has concerns
about how this section might be used in compliance monitoring and enforcement. For instance, R4 has a time
requirement somewhat embedded in the Guideline and Technical Basis that is not in the requirement in the
standard: “The imminent threat process should be implemented in terms of minutes or hours as opposed to a
longer time frame for interim corrective action plans”. How many minutes or hours? This adds ambiguity to the
standard. If a time limit is desired, it should be in the requirement. There are other examples of items that
could be interpreted as requirements in the Guidelines. It should be made clear what the purpose of the
Guidelines is in compliance monitoring and enforcement. FMPA suggests publishing two documents in the
same fashion that the Functional Model has two documents, one for the standards (e.g., the requirements),
and another for technical guidance to the standards (e.g., the Guideline and Technical Basis section) to
58
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
parallel the structure of the Functional Model and Functional Model Technical Document, which will help
make the distinction between CMEP and guidance more distinct.
American Transmission
Company
No
ATC disagrees with the above statement that it only assists in understanding how to comply. ATC believes
that parts of this section are written so they could be interpreted to contain mandatory actions/ activities. To
demonstrate, see example on pg.15, R4, 2nd paragraph states...Two key elements of an acceptable
imminent threat procedure are outlined below:..........) It should not be more than a preferred method for
implementation or supporting how the TO can meet the standard. NERC needs to clarify how this section
was intended to be used. (This as written could become part of a Compliance Audit process)Also, refer to
ATC’s comment on this section in Question #3 above.
Bonneville Power Administration
No
Consider referencing ANSI A300 part 7 as best management practices for R3. It is currently referenced in the
White Paper, and would lend more credibility to the standard if it was inserted in the text box for R3.
ERCOT ISO
No
For the same reasons stated in the comments to Question 7, it should be expressly stated that this section is
for information purposes only and is not part of the Standard Requirements. Compiling all of the “Information
Only” materials into an Appendix would be the preferred method of organization.
Northeast Power Coordinating
Council
No
NPCC participating members do not believe that publishing more information as part of the standard is
appropriate. For the same reasons as stated in the preceding response related to “Text Boxes” in question 7,
any inconsistency may result in a conflict with a requirement. The information in the Guideline and Technical
Basis section is valuable, however, and should be available to the industry in the form of guidelines. NPCC
participating members suggest that NERC assemble a comprehensive set of “Guideline” documents into one
bookmarked pdf publication to be updated as standards change. This will afford the industry a knowledge
base that is not directly sanctionable for non-compliance, but a set of industry best practices, background,
and reference for the standards development activities. Also, concern exists that FERC and Provincial
governmental authorities will have jurisdiction over “Guidelines”, and when the standard is approved it will
become a mandatory “rule”.
Nebraska Public Power District
No
Same as item 7.
CenterPoint Energy
No
See answer to Q3.
GCPD
No
Should be separate documents. If located with the standard it will get used by the auditors as compliance
issues. NO matter how much text you provide to the contrary it will become part of the standard over time.
59
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
Consolidated Edison Company of
New York, Inc.
No
Since the SDT has developed a complete Technical Reference Document for this Standard, there seems to
be redundancy with the Guideline and Technical Basis Section. This Standard has become too lengthy with
all of the additional details and information that has been added. We prefer to have a shorter Standard and a
more detailed stand alone supporting reference document.
Orange and Rockland Utilities,
Inc.
No
Since the SDT has developed a complete Technical Reference Document for this Standard, there seems to
be redundancy with the Guideline and Technical Basis Section. This Standard has become too lengthy with
all of the additional details and information that has been added. We prefer to have a shorter Standard and a
more detailed stand alone supporting reference document.
Cleco
No
The inclusion of the text implies additional requirements. Keep quidance to a separate paper.
IRC Standards Review
Committee
No
This change also requires some additional explanation. What level of importance will be given to such
materials? If an SDT inserted a Best Practices document, does that allow auditors to refer to that document
for purposes of holding an entity non-compliant?
Are these materials there to help entities who do not
know how to comply? If these materials are self-help guides, then it would be better to include them as URL
references that are stored in the NERC library. That way there can be not confusion about whether the
material is there as a self-help guide, or as a reference for auditors.
FRCC Manager of Operations
No
We agree that this is valuable information and important to convey with the standard. This should be a
separate companion document balloted, approved and posted with the standard but not be a part of the
standard.
TO/TOP
No
We agree that this is valuable information and important to convey with the standard. This should be a
separate companion document balloted, approved and posted with the standard but not as part of the
standard.
SERC OC Standards Review
Group
No
We recommend that the text “grid reliability” be substituted for “Bulk Electric System” on page 6 of the
draft.The inclusion of non-mandatory guidelines in a standard that will ultimately be approved by FERC gives
undue credence to “guidelines” that will lead undoubtedly to mis-application by future compliance auditors.
We suggest separation of this information from the mandatory reliability standard that will be filed at FERC. It
could be held in a repository on the NERC website.
Arizona Public Service Company
Yes
Central Maine Power, Iberdrola
Yes
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
USA
Consumers Energy
Yes
Duke Energy
Yes
Exelon
Yes
Manitoba Hydro
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Tennessee Valley Authority
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Tampa Electric Company
Yes
Aids in improved understanding of FAC-003-2.
FirstEnergy
Yes
Although we agree that guidelines are good to have and agree that having them in the body of the standards
is convenient, we question how this section will be viewed from a compliance standpoint. We understand this
section is not intended to be mandatory, but does that mean that regulatory authorities will only approve the
other sections of the standard and not this section? Also, it should be clear and explicitly stated in the lead-in
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
to this section that this is guidance which is not mandatory and enforceable. Additionally, terms such as
"shall", "should", and "require" should not be used in the guidance section because the information presented
in this section could be construed as mandatory by an auditor. An example of this is in the guidance
information for Requirement R7 which states "Documentation is required when the annual work plan is
adjusted...". This mandatory-type language should not be included in the Guidelines section.
MRO's NERC Standards Review
Subcommittee
Yes
Another good addition to the standard and will help clarify parts of the standard without referring to another
document or set of guidelines.
Southern California Edison
Company
Yes
Assuming that the "Guideline and Technical Basis Section" will be retained and revised in future revisions to
the standard, such information should prove very useful.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE agrees with the addition of a Guidance & Technical Basis section.
JEA
Yes
Having the information in the same document makes the information more accessible to the entity attempting
to comply with the standard.
Ga Transmission Corp
Yes
I do however believe that each utility should have the flexibility to manage there program the way they feel is
the most effective method. I do not want the technical basis section to limit options. Should this be in a white
paper format?
East Kentucky Power
Cooperative, Inc.
Yes
I have no preference one way or the other on this issue.
ITC Holding
Yes
ITC agrees with Guidelines and Technical Basis section, but recommend including useful Technical
Reference actions and activities that would support defense-in-depth strategy. We also feel that to avoid any
confusion with the applicability section and interpretations in the future, any references to the Bulk Electric
System in the standard sections and guidance/technical reference document should be reviewed and
changed.
Entergy Services
Yes
Language should be added to the Guideline and Technical Basis Section to clarify or re-state that this section
is for assisting entities in understanding how to comply with the standard but does not contain mandatory
actions/activities, and a statement that entities are not required to use the information in the Guideline and
Technical Basis Section.
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
Western Area Power
Administrtaion
Yes
The format could be enhanced by moving the "Guidelines and Technical Basis" section forward to be included
with the corresponding Requirement, Measure, and Rationale. Perhaps the "Guidelines and Technical Basis"
could also be combined with the corresponding "Rationale" text box. This would be helpful because it is
awkward flipping back and forth between these two sections when trying to fully understand a requirement.
NERC Staff (12 staff members)
Yes
There is no language in the body of the standard to clarify that the information in the Guideline and Technical
Basis Section of the standard is not subject to enforcement. We suggest revising the heading to “Application
Guidelines.” This is the term that was originally proposed by the Results-based team and is the heading
identified in the proposed Standard Processes Manual.
SERC Vegetation Management
Sub-committee
Yes
This format adds clarity and improves readability.
Xcel Energy
Yes
This is all good information to add a depth of understanding for the user. It's not clear as to how modifications
to the Guideline and Technical Basis would come about - it is the same as the standards revision process?
Does this section replace the white paper? Will it actually be deemed to be part of the Standard? We are
curious as to the legal weight if this is not part of the Standard and believe that key provisions are in this
section. It seems it should be part of the Standard.
Ameren
Yes
This is helpful information to have that does not clutter up the requirements and measurements. Under R6,
the third paragraph, there is a typo: ..."230kv transmission lines at least once 'line' during the calendar year".
City of Tallahassee (TAL)
Yes
This is very useful information and will minimize misinterpretations by the entities and the compliance teams.
Progress Energy Carolinas
Yes
This new section provides additional information and SDT rationale that is critical to understanding how to
comply with the requirements in the standard and will also provide SDT intent/basis for the interpretation
process when necessary. Progress Energy believes that any references to the Bulk Electric System in the
standard sections and guidance/technical reference document should be reviewed and changed (e.g. “grid
reliability”) to avoid confusion with the applicability section in this draft and avoid the potential for applicability
interpretations once this version is adopted.
Independent Electricity System
Operator
Yes
This section should be placed in an appendix preceded by a statement that clearly states the purpose of the
Section and indicates that the Guideline and Technical Basis Section does not in any way add to the
requirements of the standard. Also, this section appears to be a summary of the Technical Reference
Document but we could find no reference to the Technical Reference within the standard. This reference
should be cited for the benefit of anyone seeking further detail.
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
Western Area Power
Administration - Upper Great
Plains Region
Yes
WAPA - UGPR agrees with the concept of placing the background technical information in a separate section.
We were a bit concerned with the Guideline for R7 because it seems to mandate many more items than were
called for in the actual requirement in the body of the standard. Our belief is that the Guideline section should
not infer or list any more requirements than the actual requirement dictates.
Ad Hoc Group subteam formed to
review draft standard
Yes
We agree with the additional material as an aide to entities to further understand the basis for the
requirements. In this spirit the information should support compliant behavior and thus the reliability
objectives of the standard.
Dominion
Yes
While we agree that these can be useful, we are concerned about the ‘last minute’ change (March 24th) to the
technical reference document being used by those reviewing the materials for this project.
Southen Company
Yes
Would it be better to have an official white paper associated with the standard rather than having this
information in the standard? A white paper can be changed without seeking industry comments and approval
from NERC, while information in the standard must go through the entire approval process. As it is
structured now, information-only updates to the Technical Basis Section would require the entire standards
approval process to be completed.
American Electric Power (AEP)
Yes
Yes, although American Electric Power does question whether auditors will be able to avoid reading and
applying such text.
KCPL
No
I like information that helps to “guide” and “provide guidance”, however, we already having trouble with
information from FAQ’s, White Papers, and other guiding documents creeping into the requirements by
auditing teams. The inclusion of “guiding information” in the text of the Standard itself may promote adding to
requirements. Although helpful, I recommend removing this text from within the body of the Standard.
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
9. Do you prefer putting URL links to reference materials in the Guideline and Technical Basis Section, or do you prefer putting the
additional technical/information materials in appendices, where needed, to supplement the Guideline and Technical Basis Sections?
Please explain.
Summary Consideration: Out of the 52 comment forms received, 28 forms indicated a preference for use of URLs, 22 indicated a preference for
appendices and 5 indicated no preference. These results indicate that either approach would be acceptable. The SCPS agreed to put the
information in an appendix rather than in a URL because it is difficult to maintain the accuracy of URLs over time, and because keeping the
information in the body of the standard is less work for end users as all information would be in one place.
Organization
Yes or No
Question 9 Comment
MRO's NERC Standards
Review Subcommittee
If there is background information contained in a URL link pertaining to a particular Requirement, that
link should be with the Requirement that it pertains to.
Ad Hoc Group subteam
formed to review draft
standard
Judicious and correct use of citations should allow the proper documentation of references without the
hazard of expired URLs or expansion from using appendices.
Tennessee Valley Authority
No preference, either way will work.
Consumers Energy
Prefer appendices
Exelon
Prefer appendices
PPL Electric Utilities
Corporation (NCR00884)
Prefer appendices
South Carolina Electric and
Gas
Prefer appendices
TO/TOP
Prefer appendices
Tucson Electric Power Co.
Prefer appendices
Western Area Power
Administrtaion
Prefer appendices
65
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 9 Comment
Xcel Energy
Prefer appendices
GCPD
Prefer appendices
Actually we prefer that they are separate from the standard entirely. See question 8.
Cleco
Prefer appendices
An appendix ensures the information is available and original at the time the document it supports was
prepared.
ERCOT ISO
Prefer appendices
An Appendix would probably be easier to use, but either type of reference would suffice. Regardless of
which is used, it should include a footnote that the information is “For Information Purposes Only” and
are not a part of the Standard’s Requirements. If the information causes confusion, then it should be
eliminated completely. Also, what types of materials are contemplated to be “reference materials”?
Oncor Electric Delivery
Prefer appendices
Appendices would memorialize documents vs URL links to reference materials that may change over
time. This Standard was crafted from “todays” point of view and background information. Reference
material might change and the URL would point to material not validating the current form, logic, and
background of the Standard.
Entergy Services
Prefer appendices
Appendices, or reference to a single site for all referenced material, would be the most helpful from the
standpoint of keeping the information together and more readily available.
BGE (on behalf of
parent/affiliate companies:
CEG, CPSG, CECG, CNE &
CENG)
Prefer appendices
BGE prefers that such materials be included in the appendices.
NERC Staff (12 staff
members)
Prefer appendices
It is not clear what part of the standard is being balloted and what part is not. In addition, it is not clear
what process will be used to modify the guideline/technical basis section of the standard. This needs to
be determined before this standard can be balloted.
FRCC Manager of Operations
Prefer appendices
Links can get broken - official records (ie. standards) need to stand alone.
City of Tallahassee (TAL)
Prefer appendices
The fewer places I have to navigate to the better I like it. I find too many “broken” URLs. This will also
make it easier when I download a “complete set” of standards from the NERC website.
Dominion
Prefer appendices
Unless a ‘failsafe’ process is developed to insure URL links are keep up-to-date, preference is to locate
all referenced materials within the standard (same URL). However, there are a number of ways that
66
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 9 Comment
URL linkage could be done. One would be to locate all Guideline and Technical Basis documents on a
webpage dedicated to such documents. This would allow URL linkage at a higher level than if there is
URL linkage for each Guideline or Technical Basis document. This is probably the easiest to maintain.
Another would be to link each Guideline or Technical Basis document referenced in a standard to the
same URL as that standard. Maintaining URL linkage is probably medium. Yet another is to have the
URL link to a webpage created specifically for that Guideline or Technical Basis document. This is likely
to be the hardest (require most effort) to maintain.
CenterPoint Energy
Prefer appendices
URL links tend to change over time due to administrative requirements. Moving them to the appendix
will avoid revisions to the Standard. See also answer to Q3 regarding the Guideline and Technical
Basis Section.
Florida Municipal Power
Agency (FMPA) and Some
Members
Prefer appendices
URLs can break
Nebraska Public Power District
Prefer appendices
URLs change periodically.
North Carolina EMC
Prefer appendices
Will need to put something in place to make sure that the links get properly updated if they change.
Ameren
Prefer the inclusion
of URL links
Arizona Public Service
Company
Prefer the inclusion
of URL links
Bonneville Power
Administration
Prefer the inclusion
of URL links
Consolidated Edison Company
of New York, Inc.
Prefer the inclusion
of URL links
Duke Energy
Prefer the inclusion
of URL links
Ga Transmission Corp
Prefer the inclusion
67
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 9 Comment
of URL links
IRC Standards Review
Committee
Prefer the inclusion
of URL links
Manitoba Hydro
Prefer the inclusion
of URL links
Omaha Public Power District
Prefer the inclusion
of URL links
Pepco Holdings, Inc. Affiliates
Prefer the inclusion
of URL links
Southern California Edison
Company
Prefer the inclusion
of URL links
Utility Risk Management
Corporation
Prefer the inclusion
of URL links
Progress Energy Carolinas
Prefer the inclusion
of URL links
Additional reference documents provide additional information that may be needed to understand how
to comply and the basis of requirements, but they should not be included as appendices. The use
appendices could result in a SDT process/effort for minor revisions to the reference document.
American Transmission
Company
Prefer the inclusion
of URL links
Also see ATC’s comment on “Guideline and Technical Basis Section” in Question #3 above.
Independent Electricity System
Operator
Prefer the inclusion
of URL links
In general the additional reference materials may make the document extremely voluminous so we
prefer URL links.
Northeast Power Coordinating
Council
Prefer the inclusion
of URL links
Links are preferable to alleviate the concerns expressed in question 8 above, especially with respect to
FERC approval.
JEA
Prefer the inclusion
of URL links
No strong preference.
68
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 9 Comment
Tampa Electric Company
Prefer the inclusion
of URL links
None
Western Area Power
Administration - Upper Great
Plains Region
Prefer the inclusion
of URL links
None
Orange and Rockland Utilities,
Inc.
Prefer the inclusion
of URL links
Prefer the inclusion of URL links
East Kentucky Power
Cooperative, Inc.
Prefer the inclusion
of URL links
Provides for clarity and readability.
Southen Company
Prefer the inclusion
of URL links
See answer to number 8.
American Electric Power
(AEP)
Prefer the inclusion
of URL links
The use of URL links is probably most appropriate for an increasingly web-based reference repository.
SERC OC Standards Review
Group
Prefer the inclusion
of URL links
This format adds clarity and improves readability.
SERC Vegetation
Management Sub-committee
Prefer the inclusion
of URL links
This format adds clarity and improves readability.
ITC Holding
Prefer the inclusion
of URL links
URL links provide immediate access, are less cumbersome, and usually provide additional research
material when accessed.
FirstEnergy
Prefer the inclusion
of URL links
We prefer URL links. Although, we are not clear what this question is asking regarding "additional
technical/information materials". Is the team referring to "supplemental" reference documents such as
the technical reference white paper that was recently posted for stakeholder review on March 24,
2010? If so, we agree that supplemental reference material be included through URL links, perhaps at
the end of the "Guidelines and Technical Basis" section of the standard.
KCPL
Prefer appendices
Although a good idea generally, too many times URL links change name or something else that makes
the imbedded link unusable or takes you to the wrong place. Having an appendix ensures the
69
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 9 Comment
information is available and original at the time the document it supports was prepared.
70
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
10. Do you agree with the addition of the Background Section to allow provision of background information, and to elaborate on the
reliability-related drivers for the standard/change? Please explain.
Summary Consideration: Most of the comment forms (42 out of 54) indicate agreement with the addition of the Background Section.
Some commenters expressed similar concerns as those for Text Boxes and the Guideline and Technical Basis Section that the information should
not be subject to FERC’s review and approval, and that the Background may contain Requirement material that is enforceable. Other commenters
suggested that this Section is not needed given the addition of the Guideline and Technical Basis Section.
The SCPS believes that the Background Section serves a different purpose than the Guideline and Technical Basis Section. The Background
Section provides the background that led to the development of the standard, tying it to the reliability drivers and principles. In essence, the
Background Section gives readers the reasons for and the events that led to the development of the standard. The Guideline and Technical Basis
Section serves a very different purpose as it provides readers with the technical background, general guidelines, and general practices or
technical merits that the responsible entities could take or consider to help them meet the reliability requirements. The Guideline and Technical
Basis Section can also be used to provide some examples to illustrate the coverage or intent of the requirements.
On this basis, the SCPS believes it is in the interest of the majority of commenters to keep the Background Section. The SCPS will communicate
to the standard drafting team that the Background Section must not contain requirement material, and should not include any technical information
that should be provided in the Guideline and Technical Basis Section. The Background Section will remain at the front of the standard. As noted
in response to other questions, a legal statement will be added to clarify which sections of the standard are mandatory and enforceable.
Organization
Yes or No
Question 10 Comment
ERCOT ISO
No
Again, it is preferable to include this type of information in an Appendix as long as it is made clear that this is
additional information and is not a part of the Standard’s Requirements. However, if there is a chance that
the additional information included in the Appendix is going to cloud the Requirements spelled out in the
Standard, then our preference is to eliminate the additional information completely.
SERC OC Standards Review
Group
No
Inclusion of a background section in a document that will be approved wholly by FERC give undue credence
and weight to statements which may be included that are not necessarily factual 100% of the time. For
example, the first sentence of the last paragraph of the background section reads as follows: “Since
vegetation growth is constant and always present, unmanaged vegetation poses an increased outage risk,
especially when numerous transmission lines are operating at or near their Rating.” Obviously, woody stems
do not grow during the dormant season, yet the background asserts that it does. There are other areas in this
sentence that are not completely factual and should not be in a reliability standard. We recommend that the
text “grid reliability” be substituted for “Bulk Electric System” on page 6 of the draft.
Consumers Energy
No
Not necessary.
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
Northeast Power Coordinating
Council
No
NPCC participating members believe this is more informational and appropriate on the individual standard’s
NERC Website “Under Development” page, in an announcement, cover letter, or to be distributed with the
standard drafts.
Nebraska Public Power District
No
Same as item 7.
CenterPoint Energy
No
See answer to Q3.
Florida Municipal Power Agency
(FMPA) and Some Members
No
The background belongs in the Guidelines and not as part of the standard.
FRCC Manager of Operations
No
The background section should be re-named "Technical Basis". Trim content and leave only the first and last
paragraphs. In addition, all 5 paragraphs of the section as written should be moved to the front of the
Guidelines and Technical Basis document as a "Background" section of that separate document. NERC
should limit its use of "background" information within the reliability standard itself.
TO/TOP
No
The background section should be re-named "Technical Basis". Trim content and leave only the first and last
paragraphs. In addition, all 5 paragraphs of the section as written should be moved to the front of the
Guidelines and Technical Basis document as a "Background" section. NERC should limit its use of
"background" information in reliability standards.
Cleco
No
The inclusion of the text implies additional requirements. Keep quidance to a separate paper.
Exelon
No
This information should be in appendices or reference documents available on the NERC standards site.
Ameren
Yes
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
Central Maine Power, Iberdrola
USA
Yes
City of Tallahassee (TAL)
Yes
72
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Duke Energy
Yes
East Kentucky Power
Cooperative, Inc.
Yes
Ga Transmission Corp
Yes
JEA
Yes
Manitoba Hydro
Yes
MRO's NERC Standards Review
Subcommittee
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southen Company
Yes
Tennessee Valley Authority
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Question 10 Comment
73
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
Western Area Power
Administrtaion
Yes
SERC Vegetation Management
Sub-committee
Yes
Allows for a more informed interpretation of the standard.
American Electric Power (AEP)
Yes
American Electric Power agrees with this change.
American Transmission
Company
Yes
ATC agrees that the Background Section is helpful; however, NERC should define its purpose and goal.
What is currently written is more than necessary to be included in this standard.
Dominion
Yes
Dominion agrees but suggests it be moved towards end (suggest between Administrative and
Guideline/Technical basis sections).
Ad Hoc Group subteam formed to
review draft standard
Yes
Great help in showing intent and reliability goal of the standard.
Southern California Edison
Company
Yes
Including a background section should prove useful for future editions. However, at some point such
information could be made accessible through URL links.
ITC Holding
Yes
ITC agrees with the addition of Background Section
GCPD
Yes
May help in iterpretations and in explaining to stakeholders in our organizations.
Tampa Electric Company
Yes
None
Western Area Power
Administration - Upper Great
Plains Region
Yes
None
Progress Energy Carolinas
Yes
Progress Energy agrees and believes that the background section will allow relevant background information
that provided direction/guidance for the SDT to be readily available after the standard revision is adopted.
Entergy Services
Yes
The Background Section is helpful, but the last sentence states....."Thus, this Standard's emphasis is on
vegetation grow-ins.". This statement seems to conflict with the outage Category 2 "Fall In" classification,
74
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
even though it is a fall in from within the ROW.
Xcel Energy
Yes
The Background section should be moved to the back, in front of the Guideline and Technical Basis.
IRC Standards Review
Committee
Yes
This background is important for insertion at the beginning of a SAR. But for a standard-posting, it is
suggested that this section is redundant and better inserted after the requirement and measures with the
other Administrative materials.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
This makes sense to BGE.
NERC Staff (12 staff members)
Yes
This provides a context for the requirements and is very beneficial in understanding the intent of the standard.
Independent Electricity System
Operator
Yes
This section expands on the purpose statement and will promote a uniform understanding of the fundamental
drivers for the standard and its requirements, as well as its philosophy and scope.
Consolidated Edison Company of
New York, Inc.
Yes
We agree but believe the Background Section should be situated before the Applicability Section in the
revised Standard and redundant verbiage should be removed.
Orange and Rockland Utilities,
Inc.
Yes
We agree but believe the Background Section should be situated before the Applicability Section in the
revised Standard and redundant verbiage should be removed.
FirstEnergy
Yes
We agree that a Background section is beneficial. However, we believe it may be more appropriate to move
this information to the Guidelines section as a lead-in. Also, we suggest a rewording of the first sentence of
the first paragraph on Pg. 2 which states: "Major outages and operational problems have resulted from
interference between overgrown vegetation and transmission lines located on many types of lands and
ownership situations". We agree that vegetation can contribute to outages, but it cannot be the sole cause of
major outages. Major outages can be prevented if other measures required by other NERC standards are
implemented when vegetation causes a line or other equipment to malfunction. We suggest a rewording of
this statement as follows: "Interference between vegetation and transmission lines located on many types of
land have contributed to significant outages and operational challenges."
KCPL
No
I like information that helps to “guide” and “provide guidance”, however, we already having trouble with
information from FAQ’s, White Papers, and other guiding documents creeping into the requirements by
auditing teams. The inclusion of “guiding information” in the text of the Standard itself may promote adding to
75
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
requirements. Although helpful, I recommend removing this text from within the body of the Standard.
76
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
11. Do you agree with the addition of an Administrative Procedure Section to place administrative/procedural requirements that are
contained in the existing standards but which do not meet the results-based or risk-based criteria? Please explain.
Summary Consideration: Most comment forms (36 out of 52) indicated agreement with this addition.
Some commenters questioned whether or not these Administrative Procedures are mandatory and if so, why they are not placed in the
Requirements and Measures Section or at least renamed “Administrative Requirements”. They asked, if the administrative requirements are
mandatory, are they subject to compliance audit and if so, would a monetary penalty be applied?
Some suggested that if the administrative procedures are not mandatory requirements, they should not be included in standards and proposed the
alternative approach of collecting data/reports through the Rules or Procedure Section 1600.
The intent of creating the Administrative Procedure Section is to separate the procedural and administrative requirements from the results-based
reliability requirements since not performing the former tasks does not adversely affect BES control or performance or expose the BES to reliability
risks. The SCPS will provide further clarity to the intent of this Section, and consider the use of Rules of Procedure Section 1600 for data/report
collection as an alternative.
Organization
Yes or No
Question 11 Comment
Consumers Energy
No
Nebraska Public Power District
No
Administrative requirements should not be included in the Standard, they may be construed unintentionally as
a requirement.
GCPD
No
Anything not directly associated with the compliance requirements or for help with interpretations should not
be in the standard.
Northeast Power Coordinating
Council
No
As stated earlier, NPCC participating members don’t understand if this section holds sanctionable
requirements, and if so under what authority. Administrative items are best left to the ROP or Compliance
documents. A results based standard’s primary focus should be on the requirements, and the goal or
reliability objective. Taking administrative requirements out of the formal requirements section, adding them
to another section, and still deeming them to be requirements is of no value to reducing the administrative
burden on the industry. This makes the implementation of the standard more burdensome due to the fact that
these additional “requirements” now reside in different places in the standard document. NPCC participating
members suggest if these are truly valid requirements they need to be together with the other requirements.
If they do not meet the results based criteria, and were included in this “Administrative Procedure” section
strictly because of that, then they need to reside in another document. Their continued appearance in the
document dilutes the integrity of the results based standard initiative.
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 11 Comment
Exelon
No
Exelon is concerned this will raise questions concerning what criterion separates an administrative
requirement from a results or risk based requirement. How are administrative requirements to be treated in
the CMEP?
CenterPoint Energy
No
It is not clear if the Administrative Procedure is a mandatory activity. It would be helpful if the intent of this
section was stated within the Standard.Also, this section in not parallel with the Rating and Rated Electrical
Operating Conditions exception contained in R1 and R2. We recommend the following parallel wording for
the first paragraph of this section:”The Transmission Owner will submit a quarterly report to its Regional
Entity, or the Regional Entity’s designee, identifying certain Sustained Outages of the categories defined
below, while operating within the Rating and Rated Electrical Operating Conditions, determined by the
Transmission Owner to have been caused by vegetation that includes, as a minimum, the following:”Also, the
categories listed in this section do not have parallel language to M1 and M2. We recommend that this section
should adopt the wording in M1 and M2 for the Sustained Outages to be reported. Currently, Category 2 and
Category 4 do not distinguish between an IROL and Major WECC Transfer Path. This may become a
tracking problem since they have different Violation Risk Factors. If this is not important, then Category 1A
and 1B can be combined.
Consolidated Edison Company of
New York, Inc.
No
It is somewhat confusing to have sanctionable requirements located in other sections of the Standard outside
of 'Requirements and Measures.' The section title 'Administrative Procedure' is somewhat misleading; if it was
renamed 'Administrative Requirements' we feel it would be clearer to the industry.
Orange and Rockland Utilities,
Inc.
No
It is somewhat confusing to have sanctionable requirements located in other sections of the Standard outside
of 'Requirements and Measures.' The section title 'Administrative Procedure' is somewhat misleading; if it was
renamed 'Administrative Requirements' we feel it would be clearer to the industry.
SERC OC Standards Review
Group
No
Reporting Outages is not a part of Vegetation Mgmt. Therefore, this reporting belongs in an Administrative
Section or possibly via a NERC 1600 request. In no circumstance should it be a Requirement of the standard.
In the last paragraph this section appears to place a requirement on a regional reliability entity: “The Regional
Entity will report the outage information provided by Transmission Owners, as per the above, quarterly to
NERC, as well as any actions taken by the Regional Entity as a result of any of the reported Sustained
Outages.” Was this really intended? What if the RE fails to make a report?
IRC Standards Review
Committee
No
Some additional explanation is needed.
If the requirement is to do inspections, and compliance is
measured on that basis only then the Administrative Section is OK.
If the entity is mandated to also meet
the actions specified in the Administrative Section, then the change is not acceptable. This standard's
example administrative section is introducing new requirements into the standard, and those requirements
should be in the standard. In short, if there is a reliability requirement than that is what should be mandated.
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 11 Comment
The idea of mandating administrative items that are often designed to make auditing (not operations or
planning) simpler should not be mandated.
FRCC Manager of Operations
No
The "Administrative" section needs to be streamlined - remove the first 2 paragraphs - quarterly reporting is
no longer required and would be an administratively redundant process to the self-reporting of outages.
Leave the outage categories to support consistent self-reports. Delete last paragraph - reporting by the
Regional Entities to NERC is a delegated function that should be governed by the delegation agreements,
rules of procedure or other internal ERO process, not within a reliability standard since REs and the EROs are
not users, operators, etc of the BPS.
TO/TOP
No
The "Administrative" section needs to be streamlined - remove the first 2 paragraphs - quarterly reporting is
no longer required and would be an administratively redundant process to the self-reporting of outages.
Leave the outage categories to support consistent self-reports. Delete last paragraph - reporting by the
Regional Entities to NERC is a delegated function that should be governed by the delgation agreements,
rules of procedure or other internal ERO process, not a reliability standard.
Ad Hoc Group subteam formed to
review draft standard
No
The administrative procedure section is appropriate under results-based requirements. However, we believe
that reporting requirements established under other methods, such as the CMEP, may be confused by
including it. It is unclear how non-conformance with administrative procedures would be handled. Perhaps
administrative procedures would be better handled under ROP Section 1600 data requests or other Rules.
Cleco
No
The inclusion of the text implies additional requirements. Keep quidance to a separate paper.
Florida Municipal Power Agency
(FMPA) and Some Members
No
The reporting requirements really boil down to a self-reporting or self-certification process since the only items
to report would be violations to the standard. If such quarterly reporting is desired, it is really a selfcertification process and should be governed by that process and not through a separate Administrative
Procedure.FMPA recommends deleting the last paragraph - reporting by the Regional Entities to NERC is a
delegated function that should be governed by the delegation agreements, rules of procedure or other internal
ERO process, not within a reliability standard since REs and the EROs are not users, operators, etc of the
BPS, and are not designated in the Applicability section.
Ameren
Yes
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Central Maine Power, Iberdrola
USA
Yes
City of Tallahassee (TAL)
Yes
Dominion
Yes
Entergy Services
Yes
Ga Transmission Corp
Yes
Manitoba Hydro
Yes
MRO's NERC Standards Review
Subcommittee
Yes
NERC Staff (12 staff members)
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southen Company
Yes
Southern California Edison
Company
Yes
Tennessee Valley Authority
Yes
Question 11 Comment
80
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 11 Comment
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Xcel Energy
Yes
Are we to understand that the requirements listed in the Administrative section are not sanctionable from a
NERC compliance perspective?
American Transmission
Company
Yes
ATC feels this adds good will on the part of the entity to submit necessary reports, however, ATC requests
clarification whether this section is subject to NERC violations. (Currently not listed in Table 1 Time Horizons,
VRFs and VSLs)
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE agrees with addition of an Administrative Procedure section.
Duke Energy
Yes
During the WEBINAR, a question was raised regarding how failure to meet an Administrative/Procedural
requirement would be addressed by the Regional Entity. Can the Standard Drafting Team prepare a response
to the question?
JEA
Yes
However, it needs to be made clear whether this is subject to audit, and whether failure to meet the
requirement is subject to the same or different enforcement procedures as the numbered requirements in the
standard.
East Kentucky Power
Cooperative, Inc.
Yes
I do not believe that reporting of outages is a part of development and implementation of a Vegetation
Management Plan. I fail to see how it brings value to the standard.
ITC Holding
Yes
ITC agrees that the “administrative role” such as outage reporting; shouldn’t be a reliability requirement and
are more appropriately defined as an administrative procedure. We would also like some clarification on
whether this section of the standard is subject to NERC violations. Currently it’s not listed in Table 1 Time
Horizons, VRFs and VSLs
Western Area Power
Administration - Upper Great
Plains Region
Yes
None
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 11 Comment
Tampa Electric Company
Yes
Not sure why separating 1.A & 1.B is preferred over 1,2,3,4?
Progress Energy Carolinas
Yes
Progress Energy agrees that “Administrative” functions such as outage reporting should not be listed as a
reliability requirement and are more appropriately defined as an administrative procedure. (Outage reporting
is an administrative function that does not directly improve reliability which should be the focus of reliability
standard requirements.)NERC has other formal information request procedures in place (such as a NERC
1600 request), if that becomes necessary to ensure outage reporting.
SERC Vegetation Management
Sub-committee
Yes
Reporting Outages is not a part of Vegetation Mgmt. Therefore, this reporting belongs in an Administrative
Section or possibly via a NERC 1600 request. In no circumstance should it be a Requirement of the standard.
Western Area Power
Administrtaion
Yes
The Administrative Procedure section could be moved forward following the Background section to better
introduce the general administrative overview for what would then become the following Requirements,
Measures, etc. These general administrative and procedural requirements are more easily overlooked when
they included at the back of the Standard.
American Electric Power (AEP)
Yes
This addition is acceptable
Independent Electricity System
Operator
Yes
This section imposes an additional reporting requirement but there is no associated VRF or VSL. Is this
intentional? How will failure to report on time be treated? This is unclear as is the significance of any such
Administrative “Requirements” within the standard, in general. Is the intention to establish separate
procedures to govern the administrative and reporting obligations of registered entities under the Rules of
Procedure?
FirstEnergy
Yes
We agree with the Administrative Procedure Section. Monetary fines should not be imposed for
noncompliance with administrative requirements.
KCPL
No
It is too easy to unintentionally infer or introduce something that is not intended to be a requirement, but gets
interpreted as a requirement in this section. Standards should be clear in what is a requirement and what is
helpful information. If these are requirements, then propose them as requirements. If not, then remove to
another guiding document.
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
12. Is there any other information that should be included in the standard document? If so, please explain why you feel that this
information should be included.
Summary Consideration: None of the commenters offered any suggestions for including additional information that has not already been
suggested in one or more of the comments provided in Questions 3 to 11.
Some commenters provided comments on the standard content itself.
Some commenters commented on the “Informal Comment” process. While this process may be useful in speeding up the process of developing
standards, it introduces a potential for a given Team to ignore valuable comments (either because the issue is unknown to them, or because the
proposal does not agree with the team’s ideas). They suggested that all comments (both formal and informal) be posted immediately for all to
review. The SCPS agrees with the suggestion however the software currently used to collect stakeholder feedback doesn’t format the data
collected in a manner that is easy to understand. NERC staff is exploring alternatives that would make it easier for stakeholders to view
comments as they are submitted. The informal commenting process is meant to collect industry views in the same manner as the formal
commenting process; it differs only in not requiring the SDTs to provide a response to each comment. Notwithstanding this provision, the SDT is
still obligated to post all comments and provide summary responses to the comments.
Organization
Yes or No
Ad Hoc Group subteam formed to
review draft standard
No
American Transmission
Company
No
Bonneville Power Administration
No
City of Tallahassee (TAL)
No
Cleco
No
Consolidated Edison Company of
New York, Inc.
No
Consumers Energy
No
Dominion
No
Question 12 Comment
83
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Duke Energy
No
East Kentucky Power
Cooperative, Inc.
No
Exelon
No
Florida Municipal Power Agency
(FMPA) and Some Members
No
Ga Transmission Corp
No
Independent Electricity System
Operator
No
ITC Holding
No
JEA
No
Manitoba Hydro
No
Nebraska Public Power District
No
NERC Staff (12 staff members)
No
Northeast Power Coordinating
Council
No
Oncor Electric Delivery
No
Orange and Rockland Utilities,
Inc.
No
Pepco Holdings, Inc. - Affiliates
No
Question 12 Comment
84
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 12 Comment
PPL Electric Utilities Corporation
(NCR00884)
No
South Carolina Electric and Gas
No
Southern California Edison
Company
No
Tennessee Valley Authority
No
Tucson Electric Power Co.
No
Utility Risk Management
Corporation
No
Western Area Power
Administrtaion
No
Tampa Electric Company
No
All areas have been addressed and clarified as needed.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
No
BGE feels no other information is necessary for inclusion.
American Electric Power (AEP)
No
None
Western Area Power
Administration - Upper Great
Plains Region
No
None
GCPD
No
Too much already.
Omaha Public Power District
Yes
SERC OC Standards Review
Yes
As suggested in comment six, an improvement would be also listing the applicable table rows with each
requirement which consolidates all pertinent info with the requirement. Also, adding the penalty matrix would
85
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Group
Question 12 Comment
facilitate discussions with property owners/agencies resisting maintenance activates. This standard indicates
a lack of recognition that vegetation outages are not necessarily reliability events. In the quest for improved
reliability, spending the money necessary to achieve perfect compliance with R2, as stated, either will
increase customer rates unnecessarily or cause the misallocation of maintenance funding away from
maintenance activities that have a substantially higher impact on reliability.
SERC Vegetation Management
Sub-committee
Yes
As suggested in comment six, an improvement would be also listing the applicable table rows with each
requirement which consolidates all pertinent info with the requirement. Also, adding the penalty matrix would
facilitate discussions with property owners/agencies resisting maintenance activates.
Arizona Public Service Company
Yes
Clearance 1 needs to be put back into this requirement as written. This is a vegetation management standard
and there needs to be clear direction on how the system is going to be maintain at the time of maintenance.
This ensures a clear direction to the utility the system has to be maintained. ANSI A-300 part 1 and 7 needs
to be a requirement within the standard. Following this consensus agreement within the Professional Utility
Vegetation Management sector outlines a process for providing a reliable transmission system. At a
minimum ANSI A-300 part 1 and 7 should be incorporated into the Guideline and Technical Basis Section as
a resource for compliance with this standard. Prudence would dictate that it be adopted into this draft as the
foundation of any transmission vegetation management program as it is the accepted standard for
professionals who are responsible for managing vegetation for electric utilities.Personnel qualifications need
to be included in the standard and should include minimum measures such that there is consistency across
the industry. This ensures that personnel are qualified and will have ongoing training and education in utility
vegetation management. For example: The person who manages the field operation should have at least 5
years experience in vegetation management be an International Society of Arboriculture Certified Arborist and
a Utility Specialist.
Ameren
Yes
In 4.3.1, suggest that "ice" be included in circumstances beyond the reasonable control of a TO in addition to
the other "acts of God".
Entergy Services
Yes
More clarifying language throughout the document would be helpful.
Progress Energy Carolinas
Yes
None, other than the comment about potential improvements in question #6.
IRC Standards Review
Committee
Yes
Regarding the new format, the idea of using “Informal Comment Periods” may be useful in speeding up the
process of developing standards, but it also introduces a potential for a given Team to ignore valuable
comments (either because the issue is unknown to them, or because the issue does not agree with their
ideas).
How will the Standards Committee or others ensure the quality of the process does not suffer in
this way? What type of review process is contemplated to detect such behavior?
Having the Formal
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 12 Comment
comments at the end of the process may prevent subject matter experts (SME) from seeing the comments
and perspectives of other SMEs. The SRC suggests that all comments (both formal and informal) be posted
immediately for all to review.
Xcel Energy
Yes
See comments to #1, #7 and #13 of this form
FirstEnergy
Yes
See our other comments.
Central Maine Power, Iberdrola
USA
Yes
Table 2 expand footnote - State that table 2 is intended as a buiding block to develop clearance at time of
vegetation management work. See TVMP for clearances.
CenterPoint Energy
Yes
The detailed rationale for the required one year inspection cycle in R6 should be included in the Technical
Reference. The explanation provided in the Rationale that it “seems to be reasonable” and in the Technical
Reference that it is “reasonable based on upon average growth rates across North America and common
utility practice” are unfounded and arbitrary without a specific reference to a North American study. The
Technical Reference should contain an example diagram of “the portion of the ROW where the corridor edge
zones are designated by regulatory bodies for vegetation to exist” taken from the examples in the Definition of
Terms Used in Standard section. It is unclear how this example should be interpreted for compliance should
a Sustained Outage occur from vegetation growing within this zone. It is common for regulatory bodies to
push utilities to plant trees or maintain trees within transmission rights of way to “hide the lines”, and it is
unclear if this example is attempting to encourage such practice by regulatory bodies at the sacrifice of
reliability.In general, the Technical Reference should contain more specific examples of violations of the
Requirements and highlight specific exceptions related to vegetation related outages.The background and
basis for adding the term “Active Transmission Line Right-of-Way” should be added to the Technical
Reference.The background and basis for 4.2.4 that excludes the Standard from applying to fenced
substations should be added to the Technical Reference.Just as the force majeure statement (4.3.1) was
moved to the Applicability section of the Standard, the exception for applicability beyond the Rating and Rated
Electrical Operating Conditions should be included in the Applicability section as well. Currently, it is only
included in R1 and R2. It should be made clear if the other Requirements and Measurements must consider
conditions beyond the Rating and Rated Electrical Operating Condition.Within the Requirements and
Measures section there should be subheadings for each type of Requirement, performance-based, risk
based, and competency-based. This classification is only indicated in the Technical Reference.
MRO's NERC Standards Review
Subcommittee
Yes
The NSRS believes a section for definitions and abbreviated terms such as, Active ROW, MVCD, and WECC
is needed. Also, See comment above in Question 9 on URL links.
Southen Company
Yes
We feel a definition of Category 3 outages (non reportable outages) should be included under the
87
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 12 Comment
administrative procedures. Although these outages are not reportable, this would provide a mechanism for
classifying these outages so the utility can maintain evidence of its investigation and the rationale for not
reporting them.
KCPL
No
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
13. Do you have any other comment regarding the draft FAC-003-2 Transmission Vegetation Management standard that have not been
addressed above? If yes, please provide a reference to the section, requirement, or subrequirement that you believe should be
changed, added or deleted and the rationale for your proposal.
Summary Consideration:
1. Reasonable control - Some commenters expressed that the phrase “reasonable control” is difficult to enforce, while others wanted it moved
to another section of the standard.
The term “reasonable control” is prevalent in many force majeure clauses. It intends to limit the extent of compliance responsibility to those
conditions that are within the sphere of the TO’s ability. The SDT have determined that eliminating the word “reasonable” would not detract
from the original intent and have made the change to the standard.
The SDT does not have a preference for the location of the force majeure language. This is within the scope of the Standards Committee
Process subcommittee to address.
2.
Differentiate between “human error” versus “human activity” – Some commenters requested further explanation of these terms.
The SDT intended for the term “human activity” to be used in the Background section of the standard and have removed “human error”. The
SDT intends the phrase human activity to describe those human actions that are outside the control of the Transmission Owner such as
logging, vehicle contact with tree, removal or digging of vegetation, horticultural or agricultural or arboricultural activity. The SDT proposes the
following new Force Majeure text:
“This Standard does not apply to any occurrence, non-occurrence, or other set of circumstances that are beyond the control of a Transmission
Owner subject to this reliability standard, including acts of God, flood, drought, earthquake, major storms, fire, hurricane, tornado, landslides,
ice storms, vehicle contact with tree, human activity involving, removal of vegetation, installation of vegetation or digging around vegetation,
animals severing trees, lightning, epidemic, strike, war, riot, civil disturbance, sabotage, vandalism, terrorism, wind shear, or fresh gales (or
higher) that restricts or prevents performance to comply with this reliability standard’s requirements. Nothing in this section should be
construed to limit the Transmission Owner’s right to exercise its full legal rights on the Active Transmission Line ROW.”
3. Competency-based requirement R3: Some commenters expressed that R3 is deficient in detail.
The SDT determined that the following parameters demonstrate competency:
•
•
•
•
•
•
•
Understands the dynamics of conductor movement over its operating range and design conditions, understands the interrelationship between growth rates and inspection frequency and choice growth control method. And successfully
implements the understanding as evidenced by lack of vegetation related outages.
Conducts inspections on a frequency that accounts for vegetation growth rates and local conditions.
Considers scheduling and permit lead times.
Designs work plans that levelizes work load.
Utilizes best industry practices such as ANSI A300.
Develops vegetation maintenance plans that account for vegetation growth rates and local conditions.
Incorporates a feedback mechanism in the program.
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
•
•
•
•
•
•
•
Balancing ROW management with cost and science.
Establishes wire security zones.
Documents non-compatible species.
Exercises full legal rights on the Active Transmission Line ROW to avoid outages.
Knows the condition of its ROW.
Gives clear direction to field personnel so that they know what to do to maintain the clearances.
Addresses an interim corrective action plan.
The SDT proposes the following modification to R3:
“R3. Each TO shall document the procedures, processes, or specifications it uses to prevent the encroachment of vegetation
into the MVCD. Such documentation will incorporate the dynamics of a transmission line conductor’s movement throughout its
Rating and Rated Electrical Operating Conditions and the inter-relationships between vegetation growth rates, vegetation
control methods, and inspection frequency, for the Transmission Owner’s applicable lines.”
4. Flexible annual work plan – Some commenter indicated that the word “flexible” in requirement R7 is difficult to enforce
without more detail.
The SDT modified the requirement as follows:
“R7. Each Transmission Owner shall complete an annual vegetation work plan to ensure no vegetation encroachments
occur within the MVCD. Modifications to the work plan in response to changing conditions or to findings from vegetation
inspections may be made provided they do not put the transmission system at risk.”
5. The SDT revised Section 4.2.2 – The SDT did not agree to the removal of the reference to FAC-014 and have re-inserted it.
“4.2.2. Overhead transmission lines operated below 200kV having been identified as an element of an Interconnection
Reliability Operating Limit (IROL) designated in compliance with NERC Standard FAC-014.”
6. Reporting – Some commenters recommend keeping the outage reporting language in the technical requirements section.
The Standards Committee Process Subcommittee is the appropriate body to address this issue.
7. Gallet distances – Some commenters asked how can reliability be equal or better when Gallet distances are less than IEEE
distances.
At the Gallet distance, the probability of Flashover is zero. The current in-force version of the FERC Transmission Vegetation
Management Program Standard (FAC-003-1) uses the minimum air insulation distance (MAID) without tools formula provided in IEEE Std.
516-2003 to compute the required minimum vegetation clearance distance between a transmission line conductor and vegetation. The
equations and methods provided in IEEE 516 were developed by an IEEE Task Force in 1968 from test data provided by thirteen
independent laboratories. The distances provided in IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap,
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
or in other words, dry laboratory conditions. Consequently, the validity of using these distances in an outside environment application has
been questioned.
The current in-force version of FAC-003-01 allowed the TO’s to use either Table 5 or Table 7 to establish the absolute lowest value for
these minimum clearance distances. Table 5 could be used if the TO knew the maximum transient over-voltage factor for its system.
Otherwise, Table 7 would have to be used. Table 7 represented minimum air insulation distances under the worst possible case transient
over-voltage factor. These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for
500 - 550 kV phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for
concern in this particular application of the distances.
The SDT sought out a different method of establishing these absolute minimum clearance distances that considers both the outside
weather environment and also the realistic maximum transient over-voltages factors for in service transmission lines.
In general, the worst case transient over-voltages occur on a transmission line when the line is open on one end and is opened on the
other and then inadvertently re-energized when trapped charge is present. The intent of FAC-003 is to keep a transmission line that is in
service from becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst
case scenarios mentioned above can be ignored.
For the purposes of FAC-003, the worst case transient over-voltage then becomes the maximum value that can occur with the line
energized. Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are
negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere along the
length of an in-service AC line is approximately 2.0 per unit. This value is a conservative estimate of the transient over-voltage that is
created at the point of application (e.g. a substation) by switching a capacitor bank without a pre-insertion device (e.g. closing resistors).
At voltage levels where capacitor banks are not very common (e.g. 362 kV), the maximum transient over-voltage of an “in-service” ac line
are created by fault initiation on adjacent ac lines and shunt reactor bank switching. These transient voltages are usually 1.5 per unit or
less.
Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order to
be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient overvoltage factor of 2.0 per unit for transmission lines operated at 242 kV and below is considered to be a realistic maximum in this
application. Likewise, for ac transmission lines operated at 362 kV and above a transient over-voltage factor of 1.4 per unit is considered
a realistic maximum.
The Gallet Equation is a proven method of computing the required strike distances for proper transmission line insulation coordination.
These equations were developed for both wet and dry applications and can be used with any value of transient over-voltage factor.
When one compares the Minimum Air Insulation Distances using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical
spark-over distances computed using the Gallet wet equations, for each of the nominal voltage classes using identical transient overvoltage factors it is clear that the Gallet equations yield a more conservative (larger) minimum distance value.
The following table is an example of this comparison:
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Comparison of spark-over distances computed using Gallet wet equations
vs.
IEEE 516-2003 MAID distances
using realistic transient over-voltage factors
( AC )
Nom System
Voltage (kV)
( AC )
Max System
Voltage (kV)
Transient
Over-voltage
Factor (T)
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
IEEE 516
MAID (ft)
@ Alt. 3000 feet
765
800
1.4
8.89
8.65
500
550
1.4
5.65
4.92
345
362
1.4
3.52
3.13
230
242
2.0
3.35
2.8
115
121
2.0
1.6
1.4
8. Definition of Active Transmission Line ROW – Some commenters indicated that the Active Transmission Line ROW
definition is unclear.
The SDT thoughtfully considered FERC staff’s concern regarding the Active Transmission Line Right-of-Way. However, in
light of the Commission direction in Order 693, in response to First Energy’s concern about unnecessary expense of
managing unused rights-of-way, to include such a provision, the SDT was left with only two practical choices, the current
proposed definition or a fill-in-the-blank site-specific TO-designated approach. Acknowledging the desire to eliminate fill-inthe-blank requirements, the SDT opted for the proposed definition. Therefore, the SDT respectfully suggests that no workable
change can be made to this definition and still implements Commission direction and thus has opted to retain the current draft
language.
9. R4: “Responsible control center” and “verified knowledge” – Some commenters remarked that there is no “Local Control
Center” entity in Functional Model and that could be an enforcement issue. Other commenters sought clarification for the
phrase “verified knowledge”.
The SDT clarified R4, M4 and Rationale text box:
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
“R4.
Each Transmission Owner shall notify the responsible control center without undue delay when qualified personnel
confirm the existence of a vegetation imminent threat. A vegetation imminent threat condition is one which is likely to cause a
Fault at any moment.”
“M4.
Each Transmission Owner that has experienced a confirmed vegetation imminent threat will have evidence that it
notified the responsible control center.”
“Rationale
To ensure rapid notification of the correct personnel when an occurrence of a critical situation is observed. Qualified personnel
may include line workers and utility arborists. The responsible control center is selected to ensure that the flow of operational
information, which includes broken cross-arms and tree issues, will continue to the Transmission Operator (or its delegate).”
10. R6 and R7 – Several commenters noted that R6 and R7 were assigned High VRFs although they previously were Medium.
SDT changed R6 and R7 from High to Medium. The justification is provided by NERC VRF Worksheet Tool and review of
NERC VRF Guideline. (See attached VRF_Tool_R6.pdf and VRF_Tool_R7.pdf documents for the VM SDT consensus
response utilizing the VRF Tool.)
11. Requirements R1 and R2 – some commenters stated:
i.
The MVCD requirements R1 and R2 need more detail to be enforceable and auditable. They do not see how FAC-003-2
addresses sag and sway with the elimination of Clearance 1.
ii.
Concern that the VRF for lines covered in R2 is a Medium.
Consideration:
i.
The SDT understands the commenter’s concern. The SDT worked on addressing the concern by drafting alternate
language to be responsive to issues of enforceability and auditability and offer the following as an alternative R1/R2
for industry comment:
“R1. Each Transmission Owner shall manage the floor of its Active Transmission Line ROW in accordance to one of
the following at all times:
A) A fixed maximum vegetation height of 15 feet from the ground at the mid-half of the span and 20 feet in the
outside quarters of the span, or,
B) A calculated maximum vegetation height that is the sum of the minimum conductor height at “max sag” plus
MVCD plus cycle growth, or,
C) A calculated minimum vegetation to conductor clearance that is the sum of “max sag” in the span plus MVCD
plus cycle growth, or,
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
D) A value determined by the Transmission Owner to provide a separation between the conductor and the
vegetation that is comparable to options A, B, or C.
E) Any alternative approach that ensures no encroachment occurs within MVCD, considering the sag and sway
of the conductor throughout its operating range under rated conditions.
F) A value to provide a separation between the conductor and the vegetation that is the sum of MVCD, and a
value that considers the sag and sway of the conductor throughout its operating range under rated conditions
plus 10 feet.”
NOTE: The SDT suggests similar language as found in the posted draft for measures M1/M2 may be appropriate
with this alternate R1/R2.
ii.
The SDT considered the comments that pertain to the assignment of a Medium VRF to R2 on the basis of IROL/Major
WECC Transfer Path designation. The SDT determined that the assignment of Medium is justified because the loss of
non-IROL or non-Major WECC Transfer Path lines pose a lower reliability risk than those lines that are elements of an
IROL or Major WECC Transfer Path.
Organization
Yes or No
American Electric Power
(AEP)
Question 13 Comment
American Electric Power suggests replacing the term "Minimum Vegetation Clearance Distance" with "Critical
Vegetation Clearance Distance." The use of "minimum" suggests that the minimum is acceptable. However, in
dealing with landowners or land managers, we may not be able to negotiate any more than the minimum. "Critical"
would help convey the sense that the distance borders on dangerous unacceptability.
Central Maine Power,
Iberdrola USA
No
Consumers Energy
No
East Kentucky Power
Cooperative, Inc.
No
IRC Standards Review
Committee
No
Manitoba Hydro
No
Pepco Holdings, Inc. -
No
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
Affiliates
PPL Electric Utilities
Corporation (NCR00884)
No
South Carolina Electric
and Gas
No
Southern California
Edison Company
No
Tennessee Valley
Authority
No
Tucson Electric Power
Co.
No
Tampa Electric Company
No
None
FRCC Manager of
Operations
Yes
- Applicability Section 4.3 - use the term "Exemptions" instead of "Other" as it is more descriptive.- As noted earlier Applicability Section 5 - use the term "Technical Basis" instead of "Background" and streamline by removing
paragraphs 2, 3 and 4.- R
American Transmission
Company
Yes
(a) R1 and R2 (pg.7) - What is meant by “to avoid a Sustained Outage”. Could be argued that a grow-in that does not
cause a Sustained Outage is acceptable. (Could this be a FERC issue?)(b) R5 (pg.9) - ATC believes the term
“temporarily” should be stricken from the requirement. This leaves too much to interpretation and does not add to the
requirement(c) R6 (pg.9) - The descriptive timeframe “at least once per calendar year” is used. What does this mean?
Every 365 days or a 12 month period within a calendar year? NERC needs to define this.(d) R4 (pg.15 in the
Guideline and Technical Basis) - The term “verified knowledge” is used which does not seem consistent with the
definition of “Verified Knowledge” in R4 Rationale on pg.8.(e) R4 (pg.16 in the Guideline and Technical Basis) - The
term “responsible control center” is used and further defined. ATC believes this is the Transmission Operator. This
should either be moved to the “Definitions of Terms” section or to R4 of the standard where the term is used.
Western Area Power
Administrtaion
Yes
1) It is suggested that the word "located" in the third bullet in Measure 1 and Measure 2 be replaced with the word
"originating". As worded, M1 or M2 could be interpreted to mean that vegetation originating outside of the right-of-way
which blows or sways into contact with conductors “located inside the ... right-of-way” would be evidence of a violation
of R1 or R2. Utilities generally are very limited in their ability to manage vegetative conditions outside of their right-of95
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
ways.2) Please reference the comments under Question 2 above regarding the incompleteness of requirements R3
and R7 in fully replacing the CCZ management concepts utilized in the Draft 1 version of the proposed FAC-003-2.3)
The requirement R4 Guidelines and Technical Basis narrative is inconsistent with requirement R4. Specifically, in the
Guidelines and Technical Basis section the second paragraph’s introductory sentence identifies a requirement for an
imminent threat procedure, and the second bullet in this paragraph identifies a need to identify vegetation related
conditions that warrant a response. Neither of these items are a requirement of R4 as currently written. R4 only
speaks to the notification of the responsible control center when it has verified knowledge of a vegetation imminent
threat condition.4) The requirement R7 Guidelines and Technical Basis section is written with an inappropriate bias
towards very extensive or time based vegetation maintenance programs. Comments received from previous draft
standard reviews have revealed that there are many other effective program approaches being utilized by the industry.
It is suggested that this section be revised to broaden its scope to incorporate these other program approaches.
Ga Transmission Corp
Yes
1) I would like further examples of inactive portions of corridors. For example would a ten foot buffer strip that is in
addition to a normal width to stay off a property line but is included in an easement plat but not cleared be considered
inactive corridor or not? 2) The MVCD definition may not be realistic in its wording. Many utility companies may not be
able to maintain these clearances at “design of Transmission Facility”. This needs further definition maybe “NESC
moderate wind”. Many utilities in coastal areas will design lines for high sustained winds due to hurricanes these
clearances may not be possible to maintain under these conditions however the line may be designed to with stand
these winds.
FirstEnergy
Yes
1. Requirements R1 and R2 - We do not agree with the "zero tolerance" for real-time observation of encroachments
that do not cause an outage. When discovered, most Transmission Owners (TO) take immediate action to alleviate
encroachments and it is not appropriate to be fined for taking immediate action when no outage has occurred.
Therefore, a violation should only occur when the TO has not immediately alleviated the situation within 24 hours. We
suggest the following change to the first bullet in Measures M1 and M2: "Real-time observation of encroachment into
the MVCD that is not corrected within 24 hours."2. Measurement M1 and M2 - For additional clarity, we suggest
adding the following wording from Guideline and Technical Basis into M1 and M2 - "Brief encroachment by falling
vegetation are not considered a violation."3. Requirement R4 - Since the intent of this requirement is the immediate
notification of an imminent threat, we suggest adding the word "immediately" between "shall" and "notify".4.
Requirement R5 - We suggest removing the term "temporarily" in the requirement. Some constraints faced by
Transmission Owners are permanent and appropriate alternate action is permanently implemented. 5. Requirement
R7 - Although we agree that the TO should be allowed to adjust the plan, the use of the term "flexible" is subjective.
Additionally, the phrase "to ensure no vegetation encroachments occur within the MVCD" is redundant with the other
requirements of the standard. Therefore, we suggest revising the wording of Requirement R7 to the following: "Each
Transmission Owner shall implement an annual vegetation work plan. Adjustments to the work plan to defer work
beyond the calendar year are acceptable and shall be documented."6. Coordination between Project 2007-07 and
2010-07 - Since the TO-GO interface team has identified the need for Generator Owner (GO) applicability in the FAC003 standard, we believe that these two drafting teams should coordinate the addition of the GO into this Version 2 of
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Organization
Yes or No
Question 13 Comment
FAC-003. It would not seem sensible to revise Version 1 of FAC-003 to include the GO while Version 2 is developed
and approved without applicability to the GO.7. Compliance Section - Under "Additional Compliance Information", we
suggest removing the parenthetical phrase "See Administrative Procedure" and replace with "None". Since the
Administrative Procedure is not part of the requirements, it is not sanctionable and should not be included in the
Compliance Section.
MRO's NERC Standards
Review Subcommittee
Yes
1. Need definition for the phrase “Major WECC Transfer Paths”.2. In question 2 of the comment form, it refers to the
“bulk power system.” This standard does not cover the bulk power system, it covers lines above 200kV and certain
ones below 200kV.
BGE (on behalf of
parent/affiliate
companies: CEG, CPSG,
CECG, CNE & CENG)
Yes
4.2.4 States that the Standard is not applicable to “...to Facilities .... located inside the fenced area of a switchyard,
station or substation”. This implies that anything within the fenced area of a switchyard, substation or power plant does
not fall within the jurisdiction of FAC-003-2. Some fenced in areas could be very large and susceptible to vegetation
encroachments issues.4.3.1 Suggest including in the Force Majeure government a phrase referencing government
interference, such as “Federal, State or other regulatory interference, including legal or other legislative actions, that
prevents performance to comply with this reliability standard.”M1 & M2 bullet: “Real-time observation of encroachment
into the MVCD” implies that real-time observation of vegetation encroachment ensures reliable operation the Bulk
Electric System. The reliability standard objective states;”To improve the reliability of the electric Transmission system
by preventing those vegetation related outages that could lead to Cascading.”However, real time observation of
current operating conditions provides no assurance that vegetation will not lead to outages. BGE recommends
removing the language. If an inspector finds vegetation encroaching into the MVCD during a visual inspection he / she
should immediately initiate an Immediate Threat Notification. Therefore, this measure has no value.Disagree with R6.
- Inspection Frequency. Very prescriptive. Please consider allowing TO’s to select an annual frequency that best fits
their requirements, such as calendar year, every growing season, every non-growing season, etc. BGE currently
defines their inspection frequency as annually during the non-growing season, October 1 to May 1. BGE believes
inspecting during the dormant season is a best practice due to the ability of the inspector to identify vegetation
defects, especially off the ROW, which could be hidden during the growing season due to foliage, canopy cover, etc.
Also, if a utility elects to leverage an advance technology, such as LiDAR, it provides the most effective results when
LiDAR is utilize during the growing season, therefore allowing the results of the advance technology to enhance the
fall to spring inspection cycle. All of the above comments are submitted on behalf of:
- Baltimore Gas & Electric
Company - Constellation Energy Group, Inc. - Constellation Power Source Generation, Inc. - Constellation
Energy Commodities Group, Inc. - Constellation New Energy, Inc. - Constellation Energy Nuclear Group, Inc.
Arizona Public Service
Company
Yes
APS objects to number 3 Objectives statement. This is the only reliability standard that has at its Objective to prevent
vegetation related outages that could lead to cascading. This is a reliability standard and its objective needs to be:
“To improve the electric Transmission system by preventing vegetation related outages.” Requirement 6: To ensure
reliability the TO’s are responsible for doing an annual inspection. You either do it or don’t and if you don’t finish it
you should be held accountable. There shouldn’t be a lower VSL because you didn’t finish all of it. This is poor
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
planning on the utilities part.Requirement R7: When developing the annual work plan the Transmission Owner should
allow time for procedural requirements to obtain permits to work on federal, state, provincial, public, tribal lands. In
some cases the lead time for obtaining permits may necessitate preparing work plans more than a year prior to work
start dates. Transmission Owners may also need to consider those special landowner requirements as documented in
easement instruments. There needs to be parameters for the TO to show they allowed time for procedural
requirements. An example, some land agencies will give you permission to perform work in as little time as two weeks
and others can take two years. Even within the same land agency the timing of approvals is a moving target. APS
recommends the TO must show documentation it submitted their Vegetation Management Plan to the land agency at
least 120 days prior to the required start date. If the land agency doesn’t respond within this time frame and the utility
can not perform the work they shouldn’t be held responsible.
JEA
Yes
Generally, I believe this document is a huge improvement. The requirements are much clearer and easier to
implement than some versions from the past. I do not understand why R7 is still in this standard however. It appears
to be a requirement whose purpose is only to dictate HOW an entity must document its implementation of its
vegetation management program. Thus, I believe this requirement should be removed.
Consolidated Edison
Company of New York,
Inc.
Yes
In R5, the SDT should better define the phrase 'where a transmission line is put at potential risk due to the constraint.'
This is rather vague and could lead to inconsistent practices between utilities. Con Edison defines all undesirable
species on the full width of the ROW as 'potential risks to the transmission line' regardless of height or location at the
time of vegetation management. Interim corrective action should only be required when the potential risk is
approaching the imminent threat classification.
Orange and Rockland
Utilities, Inc.
Yes
In R5, the SDT should better define the phrase 'where a transmission line is put at potential risk due to the constraint.'
This is rather vague and could lead to inconsistent practices between utilities. ORU defines all undesirable species on
the full width of the ROW as 'potential risks to the transmission line' regardless of height or location at the time of
vegetation management. Interim corrective action should only be required when the potential risk is approaching the
imminent threat classification.
Florida Municipal Power
Agency (FMPA) and
Some Members
Yes
In the Applicability section, the use of the term “Other” should be changed to another term, such as Force Majeure,
since its purpose is not to include scope into the standard, but exclude scope from the standard.R4 uses the term
“responsible control center”, which seems inappropriate. Consider using the term “responsible operating entity”. The
M4 is simply a restatement of R4 without an example of types of evidence, e.g., such as voice recording, operator
logs, etc.R5, consider using a different term than “constrained”, which has other transmission related connotations.
Possibly “limited” or “hindered”.FMPA disagrees with a 3 year retention schedule for all of the Requirements and
Measures. R4 and M4 would seem to be supported by operator logs, voice recordings and such and three year
retention for such evidence is inconsistent with other standards.
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Organization
Yes or No
Question 13 Comment
ITC Holding
Yes
In the previous draft the VRF’s R6 and R7 were listed as Medium; and in the latest revision they are listed as High
VRF’s, what is the reason for this change or is this just a mistake?”Temporarily” should be removed from the
requirement (R5 pg.9) this will be an interpretation issue and doesn’t add to the requirement.
Northeast Power
Coordinating Council
Yes
NPCC participating members recognize the hard work the drafting team has done and appreciate the efforts to
address the issues presented. An issue seems to be a recurring theme with the advent of the MVCD. Some believe
that the eventual adoption of this standard with MVCD will result in the reduction of current trimming cycles and
clearance distances. Opinions have been expressed that this may result in increased vegetation contacts and trips.
After reviewing some of the MVCD distances, for example 3.12 feet at sea level for 345kV, some expressed the
opinion that this is much less than what typical trim practices are today, and may actually “lower” the bar for trimming
practices, and effectively allow a TO to trim less and reduce the margin of clearance.Requirement R1 discusses
encroachment. M1 bullet 1 states one way to violate encroachment would be:”Real-time observation of encroachment
into the MVCD...”From a practical standpoint what is meant here? Who would determine this and how would it be
done? The intent is certainly to avoid a sustained outage. However, if a TO was in the process of trimming after an
active growing season, and noticed a slight encroachment while trimming, would it be considered a reportable
violation? How would the RE measure compliance with avoiding something, with the absence of a sustained outage
reported? A statement should be added to the “Definition of Terms Used in Standard” section to indicate how terms
defined in the NERC Glossary and used in the standard are identified (for example capitalizing the first letters of the
term or using italics or bold font). To avoid confusion when a term might be used at the beginning of a sentence,
bolding or italicizing the term should be considered. The Guideline and Technical Basis section should be a separate
document, and not part of the standard (mentioned previously in question 8). It should be included in the Technical
Reference Document.Applicability 4.2.4--A fenced area of a switchyard, station or substation can have vegetation that
could present a potential risk to facilities. What is the reason for this exclusion, and the exclusion in Applicability
Section 5--Background paragraph 3 “...this Standard does not apply...to line sections inside an electric station
boundary.”Referring to our previous responses to questions 1 and 2 for Requirements R1, R2, and R3, what rating is
used? It is possible to operate above a facility’s normal rating for a prescribed time (for example a transmission line
may be operated above its normal rating but below its LTE rating for up to 4 hours). Operating at emergency ratings
should be considered. During emergencies transmission lines might be loaded to their emergency ratings, thus
increasing the sag, thus increasing the likelihood of a vegetation caused trip if the required clearances don’t take into
account the increased loading. Especially in an emergency loading scenario, operating into an avoidable potential risk
is very undesirable. Referring to FAC-003 - Table 2 - Minimum Vegetation Clearance Distances (MVCD), for 345kV
(line to line), 3.12 foot (assuming to ground) clearance is required at sea level. IEEE Std 516-2003 IEEE Guide for
Maintenance Methods on Energized Power Lines dated July 29, 2003, Table 5 (p. 20), lists the MAID (minimum air
insulation distance) for 345kV phase to phase equipment at altitudes below 900 meters (2953 feet) to be 2.88 meters
(9.45 feet) phase to ground. It is understood that MAID is “The shortest distance in air between an energized
electrical apparatus and/or a line worker’s body at different potential...”, but the clearance differences at the various
voltage levels seem very significant. If a figure is referenced in a requirement (R3), it would be preferable to have
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Organization
Yes or No
Question 13 Comment
that figure positioned within that requirement. If that is not possible, it should be explicitly stated where the figure can
be found. Requirement R5--Legal actions and other events that prevent vegetation maintenance work be included in
the Introduction Section 4.3.1. What does “interim corrective action” mean specifically? The requirement as written
needs to be made clearer. Without the Rationale box it loses its meaning (refer to the question 3 response).Interim
Corrective Actions are explained on page 28 of the separate Technical Reference Document, with examples such as
modifying the inspection interval, or limiting the loading on the line (effectively changing its rating) to minimize sag.
“Interim corrective action” should be defined and added to the Glossary.Are voltages referred to in the Standard
(Applicability Section) line to line or line to ground for ac systems? (345kV line to line is 199kV line to ground, below
the 200kV threshold in the standard). Are the voltages also applicable to DC equipment?
Xcel Energy
Yes
On page 6, in paragraph 5 ("Background"), we suggest enhancing the 3rd paragraph by inserting the words "Active
Transmission Right-of-Way", as follows: "...addresses vegetation management in the Active Transmission Right-ofWay along applicable overhead lines..." This change emphasizes that this does not apply to areas outside of the
Active Transmission Right-of-Way. Comments to Requirments and Measures Section (pages 7 -9)The term Minimum
Vegetation Clearance Distance (MVCD) should be explicitly defined as a new "definition" rather than explained in a
"rationale" box. Additionally, formalizing the definition would give weight to how "Table 2" is supposed to be used. As
it is currently drafted, the requirements of the standard don't refer to Table 2 at all. (i.e., - our understanding is that the
rationale boxes are for clarification and the requirements should be able to convey what is necessary on their
own.)MVCD - while we understand this as an 'engineering term', the terminology is difficult to convey since land
owners tend to question the need to do anything more than the "minimum". We recommend revising the term to
"Critical Clearance Distance (CCD)". M1 & M2 should be revised to insert the concept of "verified knowledge" (that is
used in R4). This is because M1 & M2 do not clarify whose real-time obseration it is referencing. As such, we
recommend stating "Real time verified knowledge of encroachement into the MVCD..." instead of just the term
"observation" to make it clear that a trained, knowledgeable individual is making this determination. Also, it may make
sense to turn "verified knowledge" into a defined term since it will be used in M1, M2 and R4. If it is not made a
defined term, then the meaning in M1 & M2 must be clarified in those sections (maybe a cross refefrence to as
defined in R4 and on page 15 will work). However, we think it is best to make it a defined term.R5: Rationale box:
consider enhancing the second sentence by adding the word "significant", to read "...avoid significant risk..."R5:
Requirement & Measure: consider adding exception language when the constraint is known to be longer than
"temporary". e.g. - stand offs can occur on right of ways that cross federal and tribal lands and the entity cannot force
the federal government to do do something.R6: Xcel Energy still believes the requirement in R6 that mandates an
annual inspection is too onerous and is at odds with the results-based approach of these revisions. Xcel Energy
urges the retention of the provision in the existing standard that allows the Transmission Owner to set the frequency of
inspection. In some areas of the country, annual inspections may not be adequate. Yet in other areas, a longer
inspection frequency may be perfectly reasonable and practical. Our point is that inspection frequency should not be
treated as if it were “one size fits all”. If treated this way, we feel this could pose a risk to reliability and is not likely to
be cost-effective. The Transmission Owner should be allowed some flexibility. However, if the drafting team
disagrees and determines that an annual inspection is to be mandated, Xcel Energy believes that an exception to the
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Organization
Yes or No
Question 13 Comment
annual inspection is appropriate when a non-subjective advanced technology such as LIDAR is utilized to achieve
actual clearance distances. This places the Transmission Owner in a situation where it can rationally determine that
the objectively measured distances result in a situation where an inspection need not be performed within the next
year. It is suggested that R6 be revised to read as follows: Each Transmission Owner shall perform a Vegetation
Inspection of all applicable transmission lines at least once per calendar year, unless the Transmission Owner, based
on a non-subjective advanced technology, such as LIDAR, determines that a longer inspection period is
appropriate.R7: Revise the requirement to eliminate the superfulous language at the end of the sentence that says "...
to ensure no vegetation encoachments occur wihtin the MVCD", i.e., R7 would read as "Each Transmission Owner
shall execute a flexible annual vegetation work plan."
Independent Electricity
System Operator
Yes
Our comments to this point have focussed exclusively on the proof-of-concept for using the results-based criteria for
developing a reliability standard. We have one comment on the specifics of Requirement R7 and its Measure M7.
The rationale for M7 states that a flexible annual vegetation work plan allows for work to be deferred into the following
calendar year provided it does not have the potential to become an imminent threat. This will evidently require some
kind of assessment in each case. Will entities be expected to document those assessments as evidence in support of
its view that the associated vegetation did not have the potential to become an imminent threat, or would it be
sufficient to look at the outcomes of these decisions to defer items in the work plan - i.e. there were no imminent
threats and sustained outages? Finally, we applaud the drafting team for its efforts in developing this draft. The
industry has often commented about overly prescriptive requirements and I believe this draft has focused on the
“what” of the requirements and left the “how” up to the appropriate entities. In our view this draft, with its succinctly
stated requirements, represents an important first step in the right direction. Thank you.
Ameren
Yes
Page 9, M7 - what are the limits of flexibility in executing "a flexible annual vegetation work plan"?
Duke Energy
Yes
Please review the VRF Guideline because we believe that the VRF’s for R6 and R7 should possibly be changed to
“Medium” instead of “High”. They were “Medium” in the last draft of FAC-003-2.
Westchester County
Board of Legislators
Yes
Please see e-mail sent to [email protected]. Thank you.
Progress Energy
Carolinas
Yes
Progress Energy believes that the VRFs for R6 and R7 should be returned to “medium” since no singular “risk-based”
requirement in a defense in depth strategy should be depended upon to eliminate/prevent risk to grid reliability. In a
defense in depth strategy, no one specific “risk-based” or “competency” requirement should be “high” unless failure to
complete that singular requirement will result in an immediate “high” risk to grid reliability (if that is the case, then the
standard is not truly employing a defense in depth approach). Also, R6 and R7 (which have a zero tolerance) have no
differentiation between grid impacting facilities (IROL) and facilities primary impacting local customer reliability (i.e.,
radial lines to load, etc).
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Question 13 Comment
North Carolina EMC
Yes
R4: The requirement to notify the responsible control center of an imminent threat may potentially result in confusion
at the control center if the transmission lines in question are not part of the control center's actively monitored grid. As
an example, NCEMC has a few short radial 230kV lines that fall under the requirements of this standard, but these
lines are not shown on the BA's control center system because they are downstream from a protective device located
at a tap off networked transmission lines. A vegetation-related outage on these lines would not result in any of the
transmission elements continuously monitored by the control center being outaged, and the operator receiving a call
notifying the imminent threat may not have any familiarity with the line section being identified, since it is not on their
system. If prompt action to respond to any imminent threat is the intended goal, why not consider making it a
significant part of the mitigating factors of an actual outage.
City of Tallahassee
(TAL)
Yes
Recommend deleting the “to avoid a Sustained Outage” in R1 and R2. Has a violation occurred if a momentary
(successful reclose) outage occurs but the TO did not “observe(s) vegetation within the” MVCD? While it may not
have to be reported on the quarterly report, Table 1 for the Lower VSL seems to suggest a violation of the MVCD has
occurred, even if it was not “observed” as “required” in the Guideline and Technical Basis.In the Guideline and
Technical Basis, the final paragraph for R1 and R2, line 3 contains an extra word “...encroachment is not be a
violation...”In the Guideline and Technical Basis, the third paragraph for R6, line 2/3 contains an extra word “...230kV
transmission at least once line during the calendar year.”
Cleco
Yes
Requirement 4:Recommend the SDT consider modifying to make it clear the requirement applies to threats within the
right of way (ROW).Requirement 4.3.1:Recommend adding human activities to the list of causes. Logging activities
are listed but other human activities such as private property owner tree care operations are not.
Exelon
Yes
See R6. Exelon prefers “annual” to “calendar” but notes the requirement runs counter to the results based approach
and could be interpreted to be inconsistent with R7.The Rationale for R6 is ambiguous and without justification
suggests shorter but not longer cycles are acceptable. If local factors can shorten a cycle, they could also increase it.
The Rational is in conflict with the prescriptive nature of the requirement.
NERC Staff (12 staff
members)
Yes
Standard Development TimelineThe Development Steps Completed section of the standard is incomplete. This
section should include the dates of previous postings. Draft 1 of revised standard was posted for stakeholder
comment from 10/27/08 - 11/25/08. Draft 2 of revised standard was posted for stakeholder comment from 09/10/09 10/24/09.Definitions of Terms Used in StandardThe definition of Active Transmission Right-of-Way is ambiguous and
subject to interpretation. This definition need to be revised to add clarity. It is unclear what “active transmission
facilities” are. In the gray box, the SDT should explain what “active portions of corridors” are, and how that is different
than the “land that is occupied by active transmission facilities.” The terminology should be consistent. The example
should state whether the width is the portion that has been cleared or should be cleared and if it was not maintained
and should have been. The SDT should explain the reference to the National Electrical Safety Code in the gray box,
and how it differs from the IEEE clearances. In addition, the team should explain why the Table 2 clearances set forth
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in the standard itself are not referenced. The examples in the “inactive portion” suggest that there are active
transmission facilities (see references to conductors and circuits). The SDT should provide the rationale for excluded
them from vegetation management. While vegetation is permitted to exist at the corridor edge, the SDT should
address why there is no obligation to maintain it. The revised definition of Vegetation Inspection does not seem
necessary. It appears that the SDT is using the definition to set an expectation for enforcement by adding “which may
be combined with a general line inspection.” If both vegetation and general line inspections are to occur concurrently,
there should be minimum background requirements to perform such inspections. We recommend that the last portion
of the draft definition be moved to the Application Guideline section so the definition of Vegetation Inspection should
be “The systematic examination of vegetation conditions on an Active Transmission Line Right of Way.”The team
should consider making Minimum Vegetation Clearance Distance a defined term.Effective DatesThe effective date for
Ontario needs to be tied to the effective date in the U.S.With respect to the second exception, the team should provide
the rationale behind the exception for the effective date for “existing transmission line operated at 200kV or higher that
is newly acquired by an asset owner and was not previously subject to this standard”. All existing transmission lines
operated at 200 kV or higher are currently subject to vegetation management. Please explain why a new owner would
get an exception for this.Based on the wording in the Exceptions section, it appears that some lines in the US could be
brought into this standard prior to regulatory approval. (i.e. Lines operated below 200kV, designated by the Planning
Coordinator as an element of an IROL or as a Major WECC transfer path, become subject to this standard 12 months
after the date the Planning Coordinator or WECC initially designates the lines as being subject to this standard. An
existing transmission line operated at 200kV or higher that is newly acquired by an asset owner and was not
previously subject to this standard, becomes subject to this standard 12 months after the acquisition date of the
line(s))ObjectiveThe purpose of this standard should not be limited to outages that lead to Cascading, but prevention
of all vegetation related outagesApplicabilityThis standard should apply to Generation Owners.The term Facilities is
defined to exclude those in a fenced area of a switchyard, station or substation. The SDT should provide the basis for
the exclusion.Footnote 1 needs to be clarified. It is too cursory.The “Other” section should not be included in this
section. It is the expectation that the Compliance Enforcement Authority will not expect the Transmission Owner to
prevent tree contacts that the TO could not prevent. This might be better suited in the Application Guideline section.In
the “Other” section, the SDT should provide rationale for why the standard is not intended to address “human
errors”.The SDT might consider rewording the “Other” section as:”This Standard shall not apply in circumstances
where a requirement of this Standard was not complied with due to Acts of God, flood, drought, earthquake, major
storms, fire, hurricane, tornado, landslides, logging activities, animals severing trees, lightning, epidemic, strike, war,
riot, civil disturbance, sabotage, vandalism, terrorism, wind shear, or fresh gales that restricts or prevents performance
to comply with this Reliability Standard's requirements, so long as the non-compliance was not caused by the fault or
negligence of the Transmission Owner.”The team should provide justification for the applicability criteria they have
selected; specifically why a 200 kV cutoff was chosen.The team should provide justification for eliminating fall-ins from
outside the ROW.BackgroundAs a general comment, the background section seems repetitive.The fourth paragraph
of the background section notes that this standard is not intended to prevent customer outages due to tree contact
with lower voltage distribution systems. It is clear from the applicability section that this pertains to 200 kV and higher,
although the standard contemplates that some lower voltage facilities could be subject to the standard. The SDT
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should address whether this paragraph also address customer outages due to tree contacts with respect to 200 kV or
higher facilities.Requirements R1 and R2:R1If an auditor were to assess compliance with R1, they would need to have
the list of conductors that were associated with an IROL or a Transfer Path. This list should be identified in the list of
evidence that must be retained.R1 & R2 In the Rationale box, the term “a proven transmission design method” is
used. Please describe what this refers to, and whether these refer to the IEEE minimum clearances. The SDT should
state what the method was and what changes, if any, were made to it.The SDT should address why the requirements
only reference line conductors and not transmission facilities or transmission lines (the VSLs refer to transmission
lines).The word “encroaching” should be replaced with another word/phrase that clearly defines the concept for
compliance purposes. The word, “encroach” could be interpreted differently by different people (how close can
vegetation grow before it enters the MVCD and is it a violation of R1/R2 - is it 2”, 2’, 10”, 10’?), whereas the word
“enter” is explicit.Guidance is offered in the Guideline section of the standard that implies that all TOs should retain
this evidence, yet the evidence is not identified anywhere in the Measures or evidence retention sections of the
standard.We suggest adding the phrase, “of its” to clarify that the TO is only responsible for facilities it owns. “In
addition, the Transmission Owner should maintain detailed records of the findings of its planned inspections. This
documentation constitutes evidence that the Transmission Owner had no encroachments into the MVCD Table
distances.”Immediately after the phrase MVCD, we suggest including the text “as specified in FAC-003-2
Transmission Vegetation Management Table 2 - Minimum Vegetation Clearance Distances (MVCD). Table 2 is not
referenced in any of the requirements. If you require entities to use the MVCD as stated in Table 2, then this should
be referenced in at least R1 and R2.M1 & M2Overall, it appears that these measures are asking for evidence of noncompliance. The initial item under M1 & M2 (shown below) should be rephrased with the addition of the words “verbal
or written report of a,” otherwise the measure doesn’t seem as though it could be used objectively. In addition, the
words Real-time should be removed, as they ad confusion to the issue.”Verbal or written report of a observation of
encroachment into the MVCD, or”The phrase “Multiple Sustained Outages on an individual line, if caused by the same
vegetation, will be reported as one outage regardless of the actual number of outages within a 24-hour period” should
be changed to a footnote that reads “Consider Multiple Sustained Outages on an individual line, if caused by the same
vegetation, as one outage regardless of the actual number of outages due to the same piece of vegetation”Momentary
outages due to vegetation are also a violation of R1. Momentary outages from tree contacts may not result in a
sustained outage but are evidence of a tree within the MVCD. The requirement should not be limited to only
sustained outages. Consider this scenario: An entity self-reports a violation of the standard. Does that mean that if
there is no actual "real-time observation" or a "Sustained Outage" there is no violation? Who must do the observing?
Please explain.Requirement R3 Consider this scenario: A Sustained Outage occurs on a location that was not
considered and therefore was not part of the TO’s TVMP. Would this result in a violation simply because the location
was not considered when the entity developed a TVMP?Requirement R4 Each requirement should identify “who shall
do what under what conditions, for what reliability outcome.” R4 has no identified reliability outcome. What is the
reason for making a prompt notification? Is it to give the real-time system operator information on which to develop
and implement an action plan if there is an outage on the line with the imminent threat? Then that should be stated in
the requirement. R4 contains explanatory information. The sentence “A vegetation imminent threat condition is one
which is likely to cause a Sustained Outage at any moment” should be moved to the blue box.Please explain what
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“verified knowledge” means. The Rationale section does not really address this. While this is in the Guidelines and
Technical Basis section, it defines it as “implies reliable confirmation.” This should be clarified and put in the
measures section.”Imminent threat” should be defined so that it does not evolve into an enforcement issue.”Notify the
responsible control center” should be clarified so that it does not evolve into an enforcement issue.Application
Guideline for R4 should contain provisions in the imminent threat procedure for notification of the land owner.M4
should provide examples of acceptable evidence.Requirement R5 This requirement does not include a reliability
outcome. The requirement should be rewritten to include a reliability outcome.Requirement R6 The Rationale for R6
is that one year “seems to be reasonable.” The SDT should address how this relates to the practice in place now, and
whether it is consistent with current practice or is more or less than current practice. If inconsistent, the SDT should
provide an explanation.The Rationale states the TOs should consider other factors that could warrant more frequent
inspections. If so, the SDT should explain whether we are requiring them to do so if such factors exist.This
requirement does not include a reliability outcome. The requirement should be rewritten to include a reliability
outcome.Requirement R7 R7 is ambiguous; it is not clear how this could be enforced objectively. The rationale for the
“flexible” plan indicates that the owner can delay work as long as it will not pose an “imminent threat.” The SDT
should explain what the Compliance Enforcement Authority would look at to determine that the work that was delayed
was not causing an “imminent threat.” The SDT should address whether it would ever be acceptable to delay work on
a critical line (covered under R1).In Requirement R7, please explain what “execute a work plan” means. Did the SDT
mean implement a work plan? As drafted, it could be read to just have one in place. The SDT should explain what
“flexible” means. Does it mean there will never be a FAC-003 violation if you fail to implement the plan? The
Rationale says the work can be deferred if it does not have the potential to become an imminent threat. Please
explain. Corresponding clarification changes should be made to the VSLs for this requirement.Either M7 or the
evidence retention for M7 needs to include the annual work plan. Without that the Compliance Enforcement Authority
can’t determine if the plan was executed. The VSLs for R7 imply that the entire annual plan will be accomplished. . .
not a “flexible” amount of the plan - the VSLs don’t line up with the use of the word “flexible.”According to the VSL
Guidelines the VSLs should be stated in language that identifies the degree of noncompliance in language that
identifies the amount that was noncompliant, rather than the amount that was compliant. VSLs for R6 and R7 are
stated in terms of the % of the required performance that was compliant and should be rephrased. GuidelinesThe
following guidance is offered in the Guideline section of the standard:Documentation or other evidence of the work
performed typically consists of signed-off work orders, signed contracts, printouts from work management systems,
spreadsheets of planned versus completed work, timesheets, work inspection reports, or paid invoices. Other
evidence may include photographs, work inspection reports and walk-through reports.Documentation is required when
the annual work plan is adjusted or not completely implemented as originally planned. The reasons for the deferrals or
changes and the expected completion date of postponed work should be documented.This implies that all TOs should
retain this evidence, yet the evidence is not identified in nearly this level of detain in the Measures section of the
standard. In addition, no part of the requirement or measure is clear in indicating that documentation is required to
support the need for a work plan adjustment. Evidence Retention The evidence retention periods specified don’t
reflect the guidance in the SDT Guidelines. Should the evidence retention be the later of three years or three years
from the last audit? The second paragraph should be stricken because it seems to contradict the first paragraph
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retention period.VSLsThe SDT should verify that the VSLs for Requirement 3 are properly calibrated.Administrative
ProcedureThe Administrative Procedure does not require prompt reporting of sustained outages; rather it requires
only a quarterly report. This appears to be less stringent than the current requirements as employed today.The SDT
should explain what “blowing together” means, and how this is different from a tree that grows into a
line.FootnotesFootnote 1 should be deleted or modified. It is only relevant in explaining the proposed modifications to
the standard. In footnote 4 the word, “substantially” adds ambiguity.Guideline and Technical BasisIn the Guidelines
and Technical Basis section, it states “Requirements 1 and 2 state if the TO observes vegetation within the distances
prescribed in FAC-003 - Table 2 it is in violation of this Standard.” This is actually in the Measures 1 and 2 and not the
requirements.General commentsThere seems to be a lot of information not captured in the Requirements but rather
are in various other sections. The SDT should clearly delineate whether these other sections are considered part of
the Standard or just informational.With the next posting of the standard, the drafting team should include the following
four points for stakeholder review:1. Justification for selection of the applicable lines. 2. Table listing each FERC
directive and stakeholder issue (from the Issues Database) associated with the standard and identification of how the
team addressed each of these3. Table listing each VRF and identification of how the proposed VRF meets both
NERC criteria for setting VRFs and FERC’s five Guidelines for approving VRFs4. Document identifying how the
proposed VSLs meet both NERC criteria for setting VSLs and FERC’s four Guidelines for approving VSLs.There is a
significant concern with the use of the Gallet equations in this standard. This standard eliminates Clearances 1 and 2
from the previous version and replaces it with a single Minimum Vegetation Clearance Distance (MVCD) based on the
Gallet equations. This approach reflects the most basic lowest common denominator and significantly lowers the bar
versus the performance expected from the existing standard. Further, it would not appear that responsible entities
would use the Gallet equations as the basis for the development of the vegetation management program.
Additionally, whereas the multiple clearance zones provide an indicator of proactive vegetation management, the
current proposal does not provide an equivalent demonstration of proactive performance. This approach appears
inconsistent with Order 693 and the presentation of NERC standards to provide a defense in depth strategy, which is
a fundamental outcome of the results-based standards process. Order 693 states in P24 that the “reliability mandate
of Section 215 of the Federal Power Act....contemplates the prevention of incidents, acts, and events that would
interfere with the reliable operation of the Bulk Power System.” The SDT should consider adding more clarification to
the draft standard and white paper describing the building blocks for determining how much vegetation management
(trimming) needs to be performed based upon growth rate of vegetation and the time between trimmings to reflect a
proactive approach.The SDT should consider the impact of moving the reporting requirement in the existing standard
to the compliance section of the new standard. The team should consider the reporting of this activity on an exception
basis within a pre-defined timeframe following the event. This approach would provide more timely awareness to the
Regional Entity and NERC of an event than the quarterly reporting expectation, and provide opportunities for
identification and implementation of mitigating strategies in a more timely manner. While this approach removes an
administrative type requirement from the standard that is believed to provide a deterrent to responsible entities, the
increased timeliness of reporting in an exception basis would provide greater benefit to the effort to maintain
reliability.Transmission Line is a defined term. The SDT should consider using this term in place of “transmission
line.”The report identified in the administrative section of draft 3 of FAC-003 is really a “Periodic Data Submittal” used
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to assess compliance and does not belong in an administrative section of the standard - it belongs in the compliance
section of the standard. “Periodic Data Submittals” is one of eight different compliance monitoring and enforcement
processes that may be used to monitor and assess compliance. The eight processes are identified in the Uniform
Compliance Monitoring and Enforcement Program of the North American Electric Reliability Corporation and should
not be mixed in with other processes or procedures. Each standard must list the appropriate processes in the
compliance section of the standard so that there is a clear understanding of the purpose of the data submittal.As
drafted, FAC-003-2 applies only to Transmission Owners. It also should apply to Generator Owners. The SDT should
explain whether the issues brought forward in the GO/TO Report been considered and are addressed as part of this
revision.Please update the mapping document so that it compares the last version of the approved standard to the
latest proposed version of the standard so that it is easy to compare the proposed standard to the standard that is in
force now.
Utility Risk Management
Corporation
Yes
Suggested Improvements to M1. and M2.The purpose of Requirements R1 and R2 is to require the prevention of
vegetation encroachments within the MVCD. As made clear in the background and remaining FAC 003-2
requirements, the overarching intent of FAC 003-2 is to prevent sustained outages caused by vegetation that could
lead to cascading. However, both M1 and M2 include real-time observations of encroachment into the MVCD as an
automatic violation of R1 or R2, respectively (even though the violations may not result in penalty or fine). This is
inconsistent with the “defense in depth” goal sought by the committee, as a real time observation using new
technologies may in fact demonstrate that the Transmission Owner is in fact aggressively managing vegetation to
meet the MVDC requirements and is discovering new encroachments and remediating them quickly and effectively
and thereby is not in violation of the standard.Similar to imminent threats, remediation procedures should be permitted
for encroachments as well and serve to make clear the observation is not automatically a violation. Classifying a realtime observation of an encroachment automatically as a violation of R1 or R2 penalizes a Transmission Owner for
identifying vegetation threats, which are less severe than imminent threats. Under Requirement R4, the transmission
owner is permitted to take appropriate actions to alleviate an imminent threat through short term corrective actions
upon observation of any vegetation that is near to or is encroaching into the MVCD. (See FAC-003-2 Guideline and
Technical Basis, Requirement R4). Considering the allowance for remedial action under Requirement R4 when facing
a condition that is “likely to cause a Sustained Outage at any moment,” it seems excessive to qualify a real-time
observation of an encroachment as a violation of R1 or R2. We suggest a better approach is to modify M1 and M2 to
allow for remedial action. Or, in the alternative, the standard should clarify that observations of encroachments using
software-enabled technology, such as LIDAR coupled with work order management systems, do not constitute a “real
time observation of an encroachment.” First, by modifying M1 and M2 to allow for remedial action as suggested below
will deal with the concern we raise:M1. Evidence of violation of Requirement R1 is limited to: o Real-time observation
of encroachment into the MVCD which is not mediated in accordance with R4. o ... M2. Evidence of violation of
Requirement R1 is limited to: o Real-time observation of encroachment into the MVCD which is not mediated in
accordance with R4. o ... In the Alternative, “Real-Time Observation” Should be Clarified. As noted above, a realtime observation of an encroachment is evidence of a violation of Requirements R1 and R2. Observations in real time
mean “an actual field observation or measurement of the conductor-to-vegetation distance and not a calculated
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determination of relevant positions.” (See FAC-003-2 Guidelines and Technical Basis, Requirements R1 and R2)
Given the current definition, it is not clear observations using software-enabled LiDAR would trigger violations and
thereby would discourage the Standard’s emphasis on preventing sustained outages or Cascading due to grow-ins.
This may result in penalties for registered entities that are engaged in good faith activities to prevent sustained
outages. The meaning of “real-time observation” should be clarified as to remove any adverse incentives for
vegetation inspection and management. To implement this suggestion as an alternative to allowing remediation to
prevent an observation from being an automatic violation, the definition could be reworded to state:”Real-time
observation” means an actual field observation or measurement of the conductor-to-vegetation distance which is not
performed under the regular Vegetation Inspection of Requirement R6 or annual vegetation work plans in accordance
with Requirement R7. Such observations do not include calculated determinations of relative vegetation positions.
Conclusion:Adopting one or both of these proposed changes would help R1 and R2 measures more fully meet the
goal of preventing overgrown vegetation and systemic failures triggered by flash over, as stated in the background
section on page 6 of FAC-003-2. The current M1 and M2 use of real-time observations conflicts with the expectation
that utilities engage in “defense in depth” measures. As the guidelines conclude regarding Requirements R1 and R2,
the Transmission Owner is expected to have a cohesive vegetation management program for managing vegetation in
such a manner as to maintain separation between conductors and vegetation. This is to function in conjunction with
the imminent threat procedure to facilitate interim corrective action. “However, brief encroachments by falling
vegetation are not considered to be a violation.” Making the changes suggested above - coupled with the existing
requirement that the utility mitigate an observation in accordance with the utility TVMP through a response schedule thereby advance the goals of the standard and take away an impediment to aggressive defense in depth.
SERC OC Standards
Review Group
Yes
The requirements (R6 and R7) for inspections and the performance of work plans are part of a defense-in-depth
approach and as such the TO is not depending on singular requirements to prevent sustained outages, therefore, the
VRF for R6 and R7 should remain medium not high. We applaud the attempt to improve the readability and ultimate
comprehension of reliability standards by changing to this new template. We have included some comments also
made by the SERC Vegetation Management Subcommittee (VMS).”The comments expressed herein represent a
consensus of the views of the above named members of the SERC OC Standards Review group only and should not
be construed as the position of SERC Reliability Corporation, its board or its officers.”
SERC Vegetation
Management Subcommittee
Yes
The requirements (R6 and R7) for inspections and the performance of work plans are part of a defense-in-depth
approach and as such the TO is not depending on singular requirements to prevent sustained outages, therefore, the
VRF for R6 and R7 should remain medium not high.
GCPD
Yes
The standard should include only R1, R2 and the Clearance Table. Everything else should be in guidelines as to how
you might comply with the standard. If R3 thru R7 remain in the standard then it is virtually the same as it exists today,
just put in a different order.
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CenterPoint Energy
Yes or No
Question 13 Comment
Yes
The term "Active Transmission Line Right-of-way" (ATLROW) is not defined in sufficient detail in the Definition of
Terms Used in the Standard section to know how to apply it to the Requirements and Measures. The Technical
Reference merely depicts the relative position of energized conductors, but it does not show a graphical determination
of the limits of the ATLROW. The ATLROW is missing a definable and determinable width in its current definition
within the Standard which makes it an arbitrary term and does not allow for a clear and measurable expected outcome
of each requirement. In several sections, the Standard relies on the specific determination of the physical width of the
ATLROW to determine applicability of the requirements. The Vegetation Inspection definition refers to “on” an
ATLROW. The Background section refers to “outside” the ATLROW. Table 1 refers to “within” and “on” the
ATLROW. M1 and M2 refer to “inside” the ATLROW. R3 and M3 refer to “on” the ATLROW. The Administrative
Procedure refers to “inside and/or outside” and “within” the ATLROW. The Guideline and Technical Basis section
refers to “on or near” the ATLROW and the “limited” ATLROW “width”. It also says that, “The Transmission Owner
should, therefore, endeavor to maintain its ATLROW to the full extent of its legal rights at all times in all cases.” Since
the Standard does not currently define how a Transmission Owner is to determine the specific boundaries of the
ATLROW, it would appear that the Transmission Owner is to make that determination on a case by case basis at its
discretion. Should that not be the intent, we recommend the definition for the ATLROW to be, “A strip or corridor of
land or aerial space that is occupied by energized transmission conductors with its operational clearance limits defined
by the Transmission Owner’s specific legal rights but in no case less confining than the MVCD applied to the
movement of the conductors within their Rating and Rated Electrical Operating Conditions.” This definition contains
sufficient detail to determine the physical limits of the ATLROW, and it allows for vegetation management to apply
within the full extent of the legal rights of the Transmission Owner while requiring a minimum area for vegetation
management in undefined ROW’s to ensure Sustained Outages are minimized.M1 contains a reference to “real-time
observation of encroachment into the MVCD” but does not explain who is to make the observation and where it is to
be documented. If this is to be done by the Transmission Owner, then perhaps it should be a Measurement under R6
and recorded under M6.The language in R6 refers to inspecting “transmission lines” and Table 1 for R6 refers to
inspecting “ROW”. Both areas should use consistent terminology.M1 and M2 have the potential for double jeopardy
when a Sustained Outage occurs because the Violation Severity Level has an entry for an MVCD encroachment
(which causes the outage) and another sister entry for the type of Sustained Outage. Some additional clarity in the
application of M1 and M2 is necessary.R5 should include the exception stated in the Rationale text box to add clarity
to the Requirement. R5 should read, “Each Transmission Owner shall take interim corrective action when it is
temporarily constrained from performing planned vegetation work, where a transmission line is put at potential risk due
to a constraint, except where the risk is avoided by implementing an alternate work methodology.” In the Guideline
and Technical Basis section for R1 and R2 (page 15), there is a reference to records of “planned inspections” and
“evidence” for no encroachment into the MVCD. This reference should be moved to R6 where the inspections are
required. If R6 is intended to provide evidence for M1, then that should be stated in R6.In the Guideline and Technical
Basis section for R6, the reference to the VSL calculation units and the example units should be consistent-the
example should use “line miles”, not just “miles”.Table 2 contains several “*” in the voltage column that are not
defined.In the Technical Reference on page 21, the following sentence should be deleted, “If constraints cannot be
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overcome and if design clearances are sufficient, an exception to the Transmission Owner’s 10-foot guideline might
be made.” The Technical Reference should not provide examples of granting exceptions as they may be
misinterpreted as an endorsement by NERC to increase the planting of trees near and under transmission lines
without taking into account several other factors such as ROW access, changing design conditions, future line
additions and rebuilds. The inclusion of modifications to the wire zone on page 24 regarding the wire-border zone
model should be re-examined to be sure they are specific to an environmental conservancy requirement while
allowing for construction and inspection access as needed.In the Technical Reference on page 22 under Planning and
Implementation, delete the sentence, “While designed primarily with transmission systems in mind, t is also applicable
to distribution projects.” The Standard should not imply its applicability to distribution systems since it is intended only
as a transmission standard.In the Technical Reference, the last sentence on page 26 starting with “Appropriate
actions...” should be moved to R5 where it applies. In general, the proposed FAC-003-2 has gone FAR beyond what
was contemplated by the Commission in FERC Order 693 and equates to a total re-writing of the Standard for no
apparent reason. The Commission's determination dealt with the following areas: (1) applicability; (2) inspection
cycles; and (3) minimum clearances on National Forest Service lands. For instance in Paragraph 729, the
Commission states, “As proposed in the NOPR, the Commission approves Reliability Standard FAC-003-1 with no
proposed modification on the issue of clearances. The Commission reaffirms its interpretation that FAC-003-1 requires
sufficient clearances to prevent outages due to vegetation management practices under all applicable conditions....”
Rewriting the minimum clearances introduced a new set of confusing definitions, and further burdens the
Transmission Owners with new documentation requirements with little if any benefit when compared to the Clearance
2 concept in the existing Standard.A preferred approach would have been to incorporate the following few items into
the existing Standard: (1) the RC versus the RRO; (2) the designation of a specific inspection frequency; (3) the Gallet
equation; and (4) the applicability to National Forest Service lands.
Ad Hoc Group subteam
formed to review draft
standard
Yes
The wording in R7 is troublesome. We believe that the process for developing the annual work plan is imbedded in
R3. As discussed in question 2, demonstrating capability to actually perform those actions necessary to ensure no
vegetation encroachments occur within the MVCD is the primary concern. Deferring such work into the next calendar
year appears contrary to this concern and neutralizes the defense-in-depth concept by diminishing the imminent threat
requirement of R4 to a primary means of defense. While we don’t want to incent vague annual work-plans, we also
don’t want to remove the imperative that the work must be done.
Nebraska Public Power
District
Yes
Under section 4.3.1 add in ice storms as one of the force majeure events. This type of event may impact many TOs
and should be included.
Oncor Electric Delivery
Yes
Use of the Gallet equation to determine the minimum gap between vegetation and conductor to prevent sparkover
seems to be appropriate. No utility should be managing to this distance but developing a distance beyond this would
be arbitrary. This is a reliability standard not a worker safety or vegetation management practices standard. As
Federal agencies and other entities are interpreting the Standard to limit normal vegetation management efforts, the
FERC should develop and adopt an overarching memo allowing utilities to maintain vegetation under any agency
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jurisdiction as a utility manages vegetation along the entire right-of-way corridor.
Western Area Power
Administration - Upper
Great Plains Region
Yes
WAPA - UGPR would like to see "ice storms" specifically mentioned in Section 4.3.1. Having additional clarification as
to what is considered a "major storm" would also be helpful.
Bonneville Power
Administration
Yes
We believe the minimum vegetation distances are very granular and nearly un-measurable in real life. When a person
considers the table to be a list of minimums it seems that the regulated entities, or land owners would want the
distances to be as close to the wire as possible. We would not want a non-technical manager to believe that any small
distance outside of the noted distances is ok.
Omaha Public Power
District
Yes
We have concern over establishing proof an outage is exempt due to fresh gale. A fresh gale, or even a localized
thunderstorm, can easily produce wind gusts that exceed the lines rated capacity for blow out. If an outage occurs
under these conditions, the standard provides an exemption under Section 4.3.1, but there is often no way to
empirically prove conditions exceeded the lines normal operating conditions. How should a utility handle these
situations?
Southen Company
Yes
We have concern over establishing proof an outage is exempt due to fresh gale. A fresh gale, or even a localized
thunderstorm, can easily produce wind gusts that exceed the lines rated capacity for blow out. If an outage occurs
under these conditions, the standard provides an exemption under Section 4.3.1, but there is often no way to
empirically prove conditions exceeded the lines normal operating conditions. How should a utility handle these
situations? Please note there is a typographical error in the third paragraph on page 15, “...encroachment violation is
not be a violation...”We would like to thank the Standard Drafting Team for their hard work. The time and effort they
have put into developing this standard is obvious.
Dominion
Yes
While not related solely to this standard, we suggest that no future standard be effective until approval has been
granted by the applicable regulatory authority. Having an effective date that differs from the mandatory date is causing
confusion/chaos on the part of the applicable registered entity(ies). With the current process, it is possible to have a
standard that is mandatory conflict with a superseding newer version (or a new standard that contains requirements
meant to supersede those in the mandatory standard). Applicable entity(ies) may not be able to comply with both
when this is true, and may not be able to take steps necessary to transition from mandatory requirement to
superseding requirement without becoming non-compliant.
Westchester County
Board of Legislators
1.
Bulk Electricity System NOPR – FERC recently issued a notice of proposed rulemaking to revise the definition of
“bulk electric system” (BES) to include all transmission facilities with a rating of 100 kV or above. 130 FERC ¶ 61,204
(Mar. 18, 2010). If approved, such revision might significantly increase the amount of transmission facilities subject to
standard FAC-003. In areas with dense residential and commercial development, this revision will exacerbate
111
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
existing conflicts between homeowners, municipalities, affected transmission owners (TOs), and regulating agencies.
As described in comments below, compliance with the existing or perceived requirements in FAC-003 has produced
numerous conflict in areas of dense development and narrow rights-of-way between homeowners, TOs, and
regulating agencies because of economic, environmental, and aesthetic impacts. If FERC adopts the proposed BES
definition, then the FAC-003 standard (current 001 and draft 002) should be extensively reviewed by the drafting
team to evaluate the amount of affected facilities and the need for standard revision to avoid as far as possible further
conflicts.
2.
“Background” Section 5 – The draft adds a new section titled “Background” (Section 5). The existing standard FAC003-1 does not include a similar section. This narrative section appears to provide interpretation on the rationale for
a vegetation management reliability standard and to clarify the standard applicability. This discussion may be more
appropriate in the accompanying technical reference, which describes and clarifies standard FAC-003. While
identifying overgrown vegetation as cause of major outages and operational problems, this section fails to state that
many other causes can lead to Cascading events. Indeed, of the many NERC reliability standards, only one, FAC003, concerns vegetation management. While the August 2003 blackout was initiated by a tree contact, there were
numerous other factors that caused this power outage to spread to over a dozen states. Section 5 should therefore
be revised to clarify that FAC-003 is only one of many factors that can lead to a large-scale grid failure.
3.
Standard Applicability Across Land Uses – Standard FAC-003-1 and the proposed draft do not vary in applicability,
even though the types of land uses within and adjacent to transmission facilities vary widely. Among certain land
uses, such as dense residential development, this can lead to substantial conflict between the TO and adjacent
landowners, especially concerning environmental, aesthetic, and economic impacts. The Westchester County Board
of Legislators identified such problems in its recent resolution, available at
http://meetings.westchesterlegislators.com/Citizens/FileOpen.aspx?Type=4&ID=2828&AgencyName=WestchesterCo
unty .
Notwithstanding the reliability imperative expressed by Congress in enacting Section 1211 of the 2005 Energy Policy
Act, the implementation of reliability standard FAC-003 has produced significant challenges for all parties in suburban
areas. In particular, surburban area homeowners, often on small parcels, that abut or are near to transmission rightsof-way have experienced dramatic impacts upon their properties and property values when TOs exercise their “full
extent of legal rights at all times and in all cases”, as stated on page 18 of the draft. Therefore, the development of
standard FAC-003 must consider this backdrop and select requirements and accompanying text that provide some
balancing of electric reliabilty with environmental and economic impacts. As presently written, the draft does not
acknowledge such balance.
4.
Varying Conditions – Requirement R1.2.1 of Standard FAC-003-1 identifies numerous local conditions that should be
considered in determining appropriate clearance distances. This balanced evaluation of factors should be retained in
FAC-003-2.
5.
Full Legal Rights – The draft encourages TOs to exercise full legal rights at all times and in all cases. This language
112
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
is not included in present standard FAC-003-1. As noted above, electric reliabilty and TO compliance with FAC-003
must not preclude other important societal factors. The language encouraging full exercise of legal rights should be
removed from the draft.
KCPL
Yes
Requirement 4:
Recommend the SDT consider modifying R4 to make it clear the requirement applies to that which is within the Right
Of Way (ROW) for the transmission facility. Obviously, the Transmission Owner has no authority or control beyond
the ROW. This is also an audit concern regarding “triggering” this requirement on a subjective evaluation of
“imminent threat”. How does a Registered Entity, Regional Entity or Auditor determine what constitutes an “imminent
threat”? This will be a matter of opinion and makes this a difficult requirement regarding compliance when a
difference of opinion arises.
In addition, as proposed, this requirement does not address the need to take immediate corrective actions to mitigate
an imminent threat. The previous FAC-003 Standard included taking action to remove the “imminent threat” which is
not included in this proposed version 2. What was the intention of the SDT in this regard? Recommend the SDT
consider language to include taking action to remove the imminent threat.
In the “Guideline and Technical Basis” section:
1. Under R6: believe the word “per” is missing in the first sentence of the third paragraph between “once (per) line”.
2. Under R7: concerned regarding the use of words such as “never”, “at all times”, and “in all cases” in the bulleted
items with paragraph 6 in this section as a guiding document. This is the kind of material that is creeping into
compliance audits and recommend softening this language.
Violation Severity Levels
1. Do not agree with the zero tolerance for encroachments that do not result in a service interruption for R1 and R2.
2. Not notifying the Control Center should be a HIGH and not removing the imminent threat should be a SEVERE.
113
Consideration of Comments on 4th Draft of FAC-003-2 Transmission Vegetation
Management —Project 2007-07 Vegetation Management
The Vegetation Management Standard Drafting Team thanks all commenters who submitted
comments on the 4th draft of reliability standard FAC-003-2 — Transmission Vegetation
Management. This standard and its associated implementation plan and technical reference
paper were posted for a 30-day public comment period from June 17, 2010 through July 17,
2010. The stakeholders were asked to provide feedback on the standard through a special
Electronic Comment Form. There were 45 sets of comments, including comments from more
than 100 different people from over 50 companies representing 7 of the 10 Industry Segments
as shown in the table on the following pages.
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
The standard and its associated implementation plan and technical reference paper were
balloted from July 9 – 19, 2010. The voting had a quorum of 86.18 percent and an affirmative
vote of 65.93 percent. Because at least one negative ballot included a comment and the
affirmative votes did not meet the two thirds threshold for approval, the results were not final.
On November 4, 2010, NERC staff provided a Quality Review of FAC-003-2 to the Standards
Committee (SC). The SC met on November 11, 2010 to determine if the draft standard should
proceed to posting. During the meeting, the SC requested the Vegetation Management
Standard Development Team (VMSDT) to work with NERC staff in addressing the items
identified in the Quality Review. The VMSDT conducted several conference calls and acted in
good faith to produce Draft 5 of FAC-003-2. The VMSDT considered the feedback provided in
the Quality Review by NERC staff and reached consensus in the following areas:
1. Elaborated upon the Purpose Statement to encompass more of the standard’s content.
2. Added a Rationale text box to the section 4 - Applicability to explain the exclusion of
substation facilities. Clarified 4.2.4 by adding specific boundary details.
3. Updated Requirement R1 and R2 to emphasize the “planning” time horizon as the
applicable temporal context.
4. Elaborated upon the explanation in the Rationale text boxes for R1 and R2 to highlight
the range of non-compliant performance.
5. Re-organized the content of Requirement R3 for improved readability.
6. Augmented Requirement R5 to include a “reliability objective”.
7. Modified Requirement R6 and the associated VSLs for improved enforceability and for
consistency in the units of measure between the Requirement and the associated VSLs.
8. Modified Requirement R7 and the associated VSLs for improved enforceability and for
consistency in the units of measure between the Requirement and the associated VSLs.
9. Updated the Evidence Retention section in accordance with current guidelines.
Modifications incorporated into Draft 5 of FAC-003-2 in response to stakeholder comments
include:
A. Removed reference to Active Transmission Line Right of Way (ROW).
B. Redefined the Glossary term for ROW to address Paragraph 734 of FERC Order 693
addressing the width of ROW to be maintained.
C. Redefined the Glossary term for Vegetation Inspection to include identifying hazards to
the line inside the ROW.
D. Included the term referred to as “applicable lines” under Section 4.2 Facilities.
E. Removed Section4.4 and footnote 2 addressing “force majeure” and addressed the
issue in new footnotes 2, 3 and 4.
F. In R1./R2 – M1/M2
• Added reference “into the MVCD” (Minimum Vegetation Clearing Distance – MVCD)
into the text.
• Eliminated “types of encroachment” and added “The four types of failure to manage
vegetation, in order of increasing severity.”
• In M1/M2, added a paragraph defining “later confirmation of a Fault by the TO as a
real-time observation.”
• Added to the Rationale box types of failures to manage vegetation.
G. In R4, changed “qualified personnel” to TO.
H. In R5, added the term “is constrained from performing vegetation work” and referenced
MVCD. Also removed reference to the 2003 northeast blackout from Rationale box
I. In R6, added the phrase “ but no more than 18 months between inspections.” Also
added Footnote 3.
J. In R7, replaced major storms bullet with “circumstances that are beyond the control of a
Transmission Owner.” Also added Footnote 4 to this requirement.
K. In Additional Compliance Information
• Category 2 was split into two parts recognizing Interconnection Reliability Operating
Limits (IROL’s) and Major Western Electric Coordinating Council (WECC) Transfer
Paths.
• Added Category 3 for Fall-ins from outside the ROW.
• Category 4 was split into two parts recognizing IROL’s and Major WECC Transfer
Paths
L. Removed alternate versions of Violation Severity Levels (VSL’s) for Requirements R1
and R2.
M. Deleted Table 3 from the Guidelines and Technical Basis section.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is
to give every comment serious consideration in this process! If you feel there has been an error
or omission, you can contact the Vice President and Director of Standards, Herb Schrayshuen,
at 609-452-8060 or at [email protected]. In addition, there is a NERC Reliability
Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Index to Questions, Comments, and Responses
1.
2.
3.
4.
5.
6.
7.
8.
The SDT replaced the defined term “Active Transmission Line Right of Way”
with footnote number 2 that provides a description of “active transmission
line ROW” and added Table 3, “Minimum Distance from the Centerline of the
Circuit to the edge of the active transmission line ROW” to support that
description. Do you agree? Please explain. ..................................................... 10
In response to comments received regarding the terms “reasonable” and
“human errors/human activity”, the SDT modified the Other Section and
Background Section. Do you agree? Please explain. ....................................... 28
In response to comments received regarding the language in M1 and M2, the
SDT modified the first bulleted item and added a sentence to the end of the
paragraph in M1 and M2. Do you agree? Please explain. ................................ 35
In response to comments received that requirement R3 is deficient in detail,
the SDT modified the requirement. Do you agree? Please explain. ................. 46
In response to comments received that requirement R7 is unclear with respect
to flexible work plans, the SDT modified the requirement. Do you agree?
Please explain. ............................................................................................... 57
In response to comments received that requirement R1/R2 may not
adequately protect the transmission conductors under all conditions of sag
and sway, the SDT drafted alternate language for the industry to provide
feedback. The SDT did not opt to incorporate this language into “Draft 4” until
further comment was solicited from industry. Which do you prefer? Please
comment on your choice in the comment box below: ..................................... 68
The drafting team and NERC staff disagree on an appropriate set of VSLs for
Requirements R1 and R2 and the Standards Committee has directed that both
sets of VSLs be posted for stakeholder comments. Which set of proposed VSLs
best supports NERC’s VSL Criteria? ................................................................ 82
Is there anything that you have not addressed above regarding the draft FAC003-2 Transmission Vegetation Management standard or the Technical
Reference Document? If yes, please provide what you believe should be
changed, added or deleted and the rationale for your proposal. ..................... 94
3
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Commenter
1.
Group
Guy Zito
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
Northeast Power Coordinating Council
Additional Member
10
X
Additional Organization
Region
Segment Selection
1. Alan Adamson
New York State Reliability Council, LLC
NPCC
10
2. Gregory Campoli
New York Independent System Operator
NPCC
2
3. Kurtis Chong
Independent Electricity System Operator
NPCC
2
4. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
5. Michael Schiavone
National Grid
NPCC
1
6. Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
7. Dean Ellis
Dynegy
NPCC
5
8. Ben Eng
New York Power Authority
NPCC
4
9. Brian Evans-Mongeon
Utility Services
NPCC
8
10. Peter Yost
Consolidated Edison Co. of New York, Inc.
NPCC
3
11. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC
5
12. Kathleen Goodman
ISO - New England
NPCC
2
13. Chantel Haswell
FPL Group, Inc.
NPCC
5
14. David Kiguel
Hydro One Networks Inc.
NPCC
1
15. Michael R. Lombardi
Northeast Utilities
NPCC
1
4
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
16. Randy MacDonald
New Brunswick System Operator
NPCC
2
17. Bruce Metruck
New York Power Authority
NPCC
6
18. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
10
19. Robert Pellegrini
The United Illuminating Company
NPCC
1
2.
Group
Denise Koehn
Bonneville Power Administration
Additional Member
X
Additional Organization
X
X
Region
WECC
1
2. Steve Narolski
BPA, Tx Vegetation/Access Road Mgmt
WECC
1
3. Vince Ierulli
BPA, Transmission Line Design
WECC
1
4. Frank Weintraub
BPA, Transmission Line Design
WECC
1
5. Daniel Tuominen
BPA, Transmission Line Design
WECC
1
6. Joel Billings
BPA, Transmission Line Design
WECC
1
7. Michael Staats
BPA, Transmission Engineering
WECC
1
8. Don Swanson
BPA, Transmission Line Maintenance Technical Svcs
WECC
1
Sasa Maljukan
Additional Member
Hydro One
Additional Organization
Region
Segment Selection
Hydro One Networks Inc.
NPCC
1
2. Patrick HOWE
Hydro One Networks Inc.
NPCC
1
3. Leslie KOCH
Hydro One Networks Inc.
NPCC
1
4. Jonathan MARRIOTT
Hydro One Networks Inc.
NPCC
1
Group
Richard Kafka
Additional Member
Pepco Holdings, Inc - Affiliates
X
Additional Organization
X
X
X
Region
Segment Selection
1. Pat Byrne
Potomac Electric Power Company
RFC
1
2. Dave Paduda
Potomac Electric Power Company
RFC
1
3. Steve Benn
Delmarva Power & Light
RFC
1
4. Olivia Watts
Atlantic City Electric
RFC
1
5.
Group
Joseph DePoorter
10
X
1. David kiguel
4.
9
Segment Selection
BPA, Tx Vegetation/Access Road Mgmt
Group
8
X
1. Chuck Sheppard
3.
7
MRO’s NERC Standards Review Subcommittee
(nsrs)
X
5
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Commenter
Organization
Additional Member
Industry Segment
1
Additional Organization
2
3
4
5
6
Region
7
OPPD
MRO
1, 3, 5, 6
2. Chuck Lawrence
ATC
MRO
1
3. Tom Webb
WPSC
MRO
3, 4, 5, 6
4. Jason Marshall
MISO
MRO
2
5. Jodi Jenson
WAPA
MRO
1, 6
6. Ken Goldsmith
ALTW
MRO
4
7. Dave Rudolph
BEPC
MRO
1, 3, 5, 6
8. Eric Ruskamp
LES
MRO
1, 3, 5, 6
9. Joseph Knight
GRE
MRO
1, 5, 6
10. Joe DePoorter
MGE
MRO
3, 4, 5, 6
11. Scott Nickels
RPU
MRO
4
12. Terry Harbour
MEC
MRO
1, 3, 5, 6
13. Carol Gerou
MRO
MRO
10
Group
Sam Ciccone
FirstEnergy
Additional Member
X
Additional Organization
X
X
X
Region
Segment Selection
1. Rebecca Spach
FE
RFC
1
2. Katrina Schnobrich
FE
RFC
1
3. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
4. Dave Folk
FE
RFC
1, 3, 4, 5, 6
7.
Group
Michael Gammon
Kansas City Power & Light
Additional Member
X
Additional Organization
X
X
X
Region
Segment Selection
1. Jennifer Flandermeyer
KCPL
SPP
1, 3, 5, 6
2. Duane Ansteate
KCPL
SPP
1, 3, 5, 6
3. Dean Beasley
KCPL
SPP
1, 3, 5, 6
8.
Group
Mallory Huggins
NERC Staff
Additional Member
1. Robert Novembri
9
Segment Selection
1. Mahmood Safi
6.
8
Additional Organization
NERC
Region
NA - Not Applicable
Segment Selection
NA
6
10
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
2. Gerry Adamski
NERC
NA - Not Applicable
NA
3. Joel deJesus
NERC
NA - Not Applicable
NA
4. Valerie Agnew
NERC
NA - Not Applicable
NA
5. Mike DeLaura
NERC
NA - Not Applicable
NA
6. Maureen Long
NERC
NA - Not Applicable
NA
7. David Taylor
NERC
NA - Not Applicable
NA
8. Herb Schrayshuen
NERC
NA - Not Applicable
NA
9.
Group
Louis Slade
Additional Member
Dominion
X
Additional Organization
X
X
7
8
9
10
X
Region
Segment Selection
1. Aaron Jonas
SERC
1
2. John Loftis
SERC
3
3. Mike Garton
5
10.
Individual
Brandy A. Dunn
Western Area Power Administration
X
11.
Individual
Jana Van Ness
Arizona Public Service Company
X
12.
Individual
Steve Rueckert
Western Electricity Coordinating Council
13.
Individual
Luke Diruzza
Tampa Electric Company
X
14.
Individual
Silvia Parada Mitchell
FPL FPL Corporate Compliance
X
15.
Individual
JT Wood
Southern Company Transmission
X
16.
Individual
Linwood Blacksmith
Tri-State Generation & Transmission
X
17.
Individual
David Burke
Orange and Rockland Utilities, Inc.
X
18.
Individual
Weston Davis
Central Maine Power Company, Iberdrola USA
X
19.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
20.
Individual
Jonathan Appelbaum
The United Illuminating Company
X
21.
Individual
Patrick Simons
Idaho Power Company
X
22.
Individual
Sam Stonerock
Southern California Edison Company
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
7
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
X
23.
Individual
Marty Berland
Progress Energy
X
X
X
24.
Individual
John Bee
Exelon
X
X
X
25.
Individual
Hugh Conley
Allegheny Power
X
26.
Individual
Edward Davis
Entergy Services
X
X
X
X
27.
Individual
Jon Kapitz
Xcel Energy
X
X
X
X
28.
Individual
Gordon Rawlings
BC Hydro
X
X
X
29.
Individual
Bill Rees
BGE Forestry Management
X
30.
Individual
Michael R. Lombardi
Northeast Utilities
X
X
X
31.
Individual
Bryan Taylor
Idaho Power
X
32.
Individual
Anne Beard
PNM
X
X
33.
Individual
James Sharpe
South Carolina and Gas
X
X
X
X
34.
Individual
Greg Rowland
Duke Energy
X
X
X
X
35.
Individual
Andrew Z.Pusztai
American Transmission Company
X
36.
Individual
Terry Harbour
MidAmerican Energy
X
37.
Individual
Claudiu Cadar
GDS Associates
X
38.
Individual
Joe Knight
Great River Energy
X
X
X
X
39.
Individual
Kirit Shah
Ameren
X
X
X
X
40.
Individual
Earl V. Burnside
PPL Electric Utilities
X
X
41.
Individual
Jianmei Chai
Consumers Energy Company
42.
Individual
Michael Pakeltis
CenterPoint Energy
X
43.
Individual
E Hahn
MWDSC (METROPOLITAN WATER DISTRICT
OF SOUTHERN CALIFORNIA)
X
44.
Individual
George Czerniewski
Consolidated Edison Company of New York Inc
X
X
X
X
7
8
9
X
8
10
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Commenter
45.
Individual
James W. Smith
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
ITC Transmission
9
10
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
1. The SDT replaced the defined term “Active Transmission Line Right of Way” with footnote number 2
that provides a description of “active transmission line ROW” and added Table 3, “Minimum Distance
from the Centerline of the Circuit to the edge of the active transmission line ROW” to support that
description. Do you agree? Please explain.
Summary Consideration:
Of 45 respondents, there is 1 abstention, 19 are in agreement, and 25 are in disagreement.
The major comment issues raised are:
1.
The values used in Table 3 needs to be justified.
2.
The definition of an active transmission line ROW ought to be a Glossary term.
3.
The Table does not account for different structure designs and the term “centerline” is not applicable in all
cases.
The VM SDT considerations for the major comment issues are:
1.
The VM SDT added explanatory text in the Guideline and Technical Basis section.
2.
Based on comments from 4th posting the SDT is revising the definition of ROW in the NERC Glossary.
3.
Table 3 has been removed.
Some minor comment issues are:
1.
Add distances for DC lines into Table 3.
2.
The term and Table 3 needs further clarification.
The VM SDT considerations for the minor comment issues are:
1.
Table 3 has been removed.
2.
Table 3 has been removed.
10
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
1
MWDSC
(METROPOLITAN
WATER DISTRICT
OF SOUTHERN
CALIFORNIA)
2
Hydro One
Yes or No
Question 1 Comment
No
A DC table for Table 3 similar to the MVCD table should be added.There
should be a statement in Table 3 that is consistent with footnote number 2
stating that the minimum width of the Active Transmission Line ROW is either
the full width of the easement or, if the easement is wider than the distances
in Table 3, the minimum distances must not be less than the distances
shown in the Table. The use of a minimum distance from the centerline of the
circuit or structure is an incorrect measure to use for a set clearance distance
of the active transmission right-of-way. The description does not take into
account vertical versus horizontal design configuration. Consideration
should be given for the type of construction as different construction types
(H-Frame, Lat-tice towers, Monopole delta or vertical construction) will
require different widths of a cleared right-of-way to provide the necessary
openings for these circuits. A minimum distance for 345-kV is now set at 150
feet based on the minimum distances from centerline. This may be correct
for certain H-Frame and Lattice Tower configurations but it is excessive for
monopole situations. A single pole configuration with vertically aligned
conductors does not need this full 150 foot width. It is strongly
recommended that a minimum distance from conductor be used in place of a
set distance from centerline. As long as there is at least 30 - 40 feet of
clearance in the right-of-way from the outermost conductors (adjusted to
account for maximum sway at mid-span for longer spans), then this is the
distance that should be used to develop the right-of-way widths.For example,
a monopole structure with vertically aligned conductors would result in a
cleared active right-of-way width of only 80 feet (40 feet from conductor to
edge of cleared active right-of-way) using the minimum distances from the
conductors. There is no need to extend this distance another 35 feet (on
each side) in order to obtain the full 150 foot width. This requirement is
excessive and must be adjusted to account for line construction variations.
11
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
Instead of using the term "Centerline" as referenced on Table 3, the use of
"outer phase" or "phase closest to tree line" would be more appropriate.
There is published literature using the term “cleared width” to indicate the
distance from the outer phase to the tree line. This distance should be used
in the Active ROW definition. The word easement is also used in the
definition. Is there a reason the Active ROW only includes easements, not
fee ownership, license or some other right to occupy and manage the ROW?
Would Active ROW include “danger tree rights” on land? These questions
need to be addressed in the standard (in text) and technical reference
document (in graphics).
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has revised
the definition of Right of Way to embody the concept of an Active Transmission Right of Way. Subsequently the
definition of Active Transmission Line Right of Way and Table 3 have been removed.
3
Allegheny Power
No
Allegheny Power strongly disagrees with the numbers or widths stated within
Table 3. These numbers seem arbitrary and have no accompanying
reasonable explanation as to their origin, basis, or other criteria noting the
rationale for inclusion in this standard. This inclusion effectively prohibits a
TO from establishing corridor widths less than the widths (which may be
easily possible by utilizing various tower or structures heights or
configurations) stated in Table 3 without placing the TO in extreme jeopardy
of non-compliance issues from a falling off-corridor tree, during minor storm
conditions as an example. Furthermore, this Table insinuates the TO has no
ability to successfully manage vegetation WITH NO RESULTING OUTAGES
or encroachments within the MVCD from off-corridor trees where corridors
are less that the widths stated in Table 3.Allegheny Power suggests that the
definition of the “Active Transmission line Right Of Way” be “the transmission
line ROW corridor that is actively maintained as part of the entity's vegetation
management plan.".
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has revised
the definition of Right of Way to embody the concept of an Active Transmission Right of Way. Subsequently the
definition of Active Transmission Line Right of Way and Table 3 have been removed.
4
FPL Corporate
Compliance
No
Although there is support for making Active Transmission Line Right of Way
a clearly defined term, and the foundation for compliance with FAC-003-2,
the distances in the table are arbitrary and are not supported by any scientific
12
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
or engineering analysis. It is possible that such a table could be interpreted to
define the minimum width of future lines. Different construction configurations
require different ROW widths.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
5
PPL Electric Utilities
No
Centerline (CL) distances shown in Table 3 are shown as Minimal distances
from CL. If utility is not able to define its ultimate ROW, due to CL agreement
or other circumstances, these minimal distances may not be applicable and
as such could result in non-compliance as written.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
6
Southern Company
Transmission
No
Depending on the intent this may create a problem. We are concerned the
addition of Table 3 could be interpreted to mean something completely
different than what we believe to be its intention. Please consider alternate
wording to Footnote 2: A strip or corridor of land that is occupied by active
transmission facilities. This corridor does not include the parts of the Right-ofWay that are unused or intended for other facilities. However, the active
transmission line ROW cleared width it is not to be less than the width of the
easement itself unless the easement exceeds distances as shown in Table 3
for various voltage classes.If the SDT determines keeping Table 3 is the
appropriate course of action, we recommend clarifying its intent better; either
in a footnote or in the title. Adding a footnote stating the Table is not
applicable if the distance from the center line of the conductor to the right-ofway edge is less than the appropriate distance indicated in the table.Another
option might be to add a statement to the title such as, “If the distance from
the centerline of the circuit to the edge of the easement is less than the
values in Table 3, that distance is considered active ROW”.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
13
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
7
Ameren
No
Does this mean wider ROW easements will need to be acquired to be
compliant or will this apply to ROW’s for new circuits going forward?
Response: Based on your comment and others, the SDT has revised the definition of Right of Way to
embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active
Transmission Line Right of Way and Table 3 have been removed.
8
Progress Energy
No
In Applicability Section 4.4, “active transmission line ROW” is not capitalized
indicating it is not a defined term, but Footnote 2 is effectively a definition for
active transmission line ROW. However, in the first paragraph of Section 5
Background, Active Transmission Line Right-of-Way is capitalized indicating
it’s a defined term. It would seem cleaner to make “Active Transmission Line
Right of Way” a formal NERC definition. Alternatively and at a minimum,
Footnote 2 should be revised to say “An active transmission line ROW is a
strip or corridor...” and also in Section 5 Background, “Active Transmission
Line Right of Way” should be changed to no longer be capitalized.
Response: Based on your comment and others, the SDT has revised the definition of Right of Way to
embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active
Transmission Line Right of Way and Table 3 have been removed.
9
PNM
No
ROW easements vary according to land ownership therefore, potentially
subjecting the utility to be liable for land outside of easement/ROW.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
10
Central Maine Power
Company, Iberdrola
USA
No
Table 3 distances may not be appropriate, for example table 3 should reflect
a clearance zone based on construction type, topography, species, or growth
rates. Table 3 could give the impression that the listed distances are the
maximum, therefore suggest table 3 be removed or revised.The Active
Transmisson Line Right-of-Way defination uses the word easement, which
most likely would include danger trees in situations where danger removals
14
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
are included in the the easement language. This would expand the scope of
FAC 003 2 beyond the cleared right-of-way width.
Response: The SDT agrees that Table 3 does not reflect the structural differences which directly determines
the right of way width. Based on your comment and others, the SDT has revised the definition of Right of
Way to embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active
Transmission Line Right of Way and Table 3 have been removed.
11
Consumers Energy
Company
No
Table 3 does not adequately address ROW width requirements based on the
type of construction used for structures, especially for the two lower voltage
classes, 69-138kV and 139-230 kV. Lines constructed on H-Frame
structures have a much wider footprint across the ROW than do single pole
construction and most steel tower construction types. The minimum ROW
width listed in Table 3 for a 138 kV line constructed on a wooden H-Frame
may put the outside conductor within MVCD under windy conditions due to
wind displacement of conductors and trees.Consumers Energy recommends
that Table 3 be modified to describe the minimum distance in the table is the
vertical plane of the outside conductor to the edge of the active transmission
ROW and therefore independent of the width of the structure construction
type.
Response: The SDT agrees that Table 3 does not reflect the structural differences which directly determines
the right of way width. Based on your comment and others, the SDT has revised the definition of Right of
Way to embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active
Transmission Line Right of Way and Table 3 have been removed.
12
The United
Illuminating Company
No
The definition has been altered. The last sentence "However, it is not to be
less than the width of the easement itself unless the easement exceeds
distances as shown in Table 3 for various voltage classes..." was added.
The concept of the easement is confusing and not included in the
Supplemental Reference. Table 3 of the standard is titled "Minimum
Distance from the Centerline of the Circuit to the edge of the active
transmission line ROW", no mention of easements. It is suggested that the
definition state "strip or corridor of land that is occupied by active
transmission facilities. This corridor does not include the parts of the Right-ofWay that are unused or intended for other facilities. At a minimum the width
is to be the distances as shown in Table 3 for various voltage classes."The
15
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
proper location for the definition is in the Glossary.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
13
Dominion
No
The distances proposed in Table 3 - Minimum Distance from the Centerline
of the Circuit to the edge of the active transmission line ROW may not be
consistent with the centerline distances cleared and maintained by the TO.
For example, a TO maintaining 75’ from centerline for a 500kV circuit would
be required to clear and maintain an additional 12.5’ to meet the proposed
standard’s requirement. We suggest either allowing individual TOs to
maintain active ROW widths consistent with their normal
clearing/maintenance practices, going back to Draft 3’s definition of Active
Transmission Line Right-of-Way, or changing the footnote in Draft 4 to
read:A strip or corridor of land that is occupied by active transmission
facilities. This corridor does not include the parts of the Right-of-Way that are
unused or intended for other facilities. However, the portion of the ROW that
has been cleared must at least meet design clearance requirements such as
National Electric Safety Code or other design criteria, for the reliable
operation of active facilities.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
14
BC Hydro
No
The footnote definition is ok but Table 3 is poorly developed. The voltage
classes should be better segregated (e.g. nominal voltage 69kV, 138kV,
230kV, 287kV, 345kV, 500kV, 765kV) along with distances in feet and
metres as Canadian utilities are metric. Also the table should include
recommended right of way widths for single circuits. The assumption made
in the footnote is that the legal easement is larger than in Table 3. However,
as currently defined, some of the distances in Table 3 exceed statutory rights
of way at our utility and exceed engineering standards as defined by the
Canadian Standards Association - Overhead Systems (CAN/CSA C22.3 No.
1-6). Also, clearances will very much depend on line design (e.g. structure
architecture such as flat, Post T, H-frame, steel lattice, and other variables
16
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
such as ruling span length, conductor type used, etc.) To some degree this
will vary quite a bit between utilities. As such Table 3 as currently presented
is not workable.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
15
Exelon
No
The term “Centerline of the Circuit” in Table 3 is not defined. Until it is
defined, there is no way to know if the standard is technically reasonable or
whether existing circuits would be in violation of the standard and unable to
operate. In addition, it is unclear what types of construction and span lengths
were used to develop the distances for active right-of-way widths in Table 3.
Furthermore, it is not clear whether Table 3 contains requirements against
which compliance will be measured or best practice guidelines. Footnote 2,
in the background section, compounds this ambiguity. In short, the lack of a
definition for “Centerline” combined with Footnote 2 and Table 3 make this
draft unclear and unenforceable. Exelon does not necessarily have
easement widths for all transmission lines that equal those defined in Table 3
of this draft; This may require the acquisition of additional easements, if even
possible.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
16
Northeast Utilities
No
The use of a minimum distance from the centerline of the circuit or structure
is an incorrect measure to use for a set clearance distance of the active
transmission right-of-way. Consideration should be given for the type of
construction as different construction types (H-Frame, Lattice towers,
Monopole delta or vertical construction) will require different widths of a
cleared right-of-way to provide the necessary openings for these circuits. A
minimum distance for 345-kV is now set at 150 feet based on the minimum
distances from centerline. This may be correct for certain H-Frame and
Lattice Tower configurations but it is excessive for monopole situations. A
single pole configuration with vertically aligned conductors does not need this
full 150 foot width. It is strongly recommended that a minimum distance from
17
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
conductor be used in place of a set distance from centerline. As long as
there is at least 30 - 40 feet of clearance in the right-of-way from the
outermost conductors (adjusted to account for maximum sway at mid-span
for longer spans), then this is the distance that should be used to develop the
right-of-way widths.For example, a monopole structure with vertically aligned
conductors would result in a cleared active right-of-way width of only 80 feet
(40 feet from conductor to edge of cleared active right-of-way) using the
minimum distances from the conductors. There is no need to extend this
distance another 35 feet (on each side) in order to obtain the full 150 foot
width. This requirement is excessive and must be adjusted to account for
line construction variations.Instead of using the term "Centerline" as
referenced on Table 3, the use of "outer phase" or "phase closest to tree line"
would be more appropriate.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
17
Idaho Power
Company
No
The way I interpret this, the new definition of active transmission line right of
way takes away our ability to clear potential fall ins if they are outside of the
active transmission line ROW>
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
18
CenterPoint Energy
No
There is no rationale provided for the “minimum distances” stated in Table 3,
and they far exceed the ROW widths that CenterPoint Energy owns (typical
total 100’ ROW width for 2-ckt 345kV line) for its current 345kV system, and
as such, are open for misapplication and misinterpretation as an intended
minimum standard for making a fall-in determination for R1 and R2 outside
the legal limits of the utility. Table 3 should be deleted. If kept, there should
be sufficient rationale included within the Guidelines and Technical Basis to
explain how it was derived and how it is to be used within the Standard.
CenterPoint Energy agrees with the removal of “active transmission line
ROW” as a defined term; however, the footnote should be deleted as well
since it attempts to create a definition which is not accurate, necessary or
18
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
useful. Throughout the Standard, the phrase “active transmission line ROW”
should be replaced with “transmission line ROW” to eliminate the qualifying
term “active”. In making a fall-in determination for R1 and R2, the limit
should be “within the full extent of the Transmission Owner’s transmission
ROW as defined by easement, fee simple, or other legal rights” as discussed
in the Guidelines and Technical Basis regarding the vegetation management
maintenance approach. This places the determination of the width of the
ROW for determination of fall-in violations clearly on the Transmission Owner
and the within the limits of its legal rights to control the vegetation that has
fallen into the line under R1 and R2.
Response: The SDT thanks you for your comments. The SDT disagrees with the point that the TO should be
required to clear the entire extent of legal rights. FERC Order 693 agreed that expansion easements needed
to be adressed. Based on your comment and others, the SDT has revised the definition of Right of Way to
embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active
Transmission Line Right of Way and Table 3 have been removed.
19
Northeast Power
Coordinating Council
No
There should be a statement in Table 3 that is consistent with footnote
number 2 stating that the minimum width of the Active Transmission Line
ROW is either the full width of the easement or, if the easement is wider than
the distances in Table 3, the minimum distances must not be less than the
distances shown in the Table.The use of a minimum distance from the
centerline of the circuit or structure is an incorrect measure to use for a set
clearance distance of the active transmission right-of-way. The description
does not take into account vertical versus horizontal design configuration.
Consideration should be given for the type of construction as different
construction types (H-Frame, Lattice towers, Monopole delta or vertical
construction) will require different widths of a cleared right-of-way to provide
the necessary openings for these circuits. A minimum distance for 345-kV is
now set at 150 feet based on the minimum distances from centerline. This
may be correct for certain H-Frame and Lattice Tower configurations but it is
excessive for monopole situations. A single pole configuration with vertically
aligned conductors does not need this full 150 foot width. It is strongly
recommended that a minimum distance from conductor be used in place of a
set distance from centerline. As long as there is at least 30 - 40 feet of
clearance in the right-of-way from the outermost conductors (adjusted to
account for maximum sway at mid-span for longer spans), then this is the
19
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
distance that should be used to develop the right-of-way widths.For example,
a monopole structure with vertically aligned conductors would result in a
cleared active right-of-way width of only 80 feet (40 feet from conductor to
edge of cleared active right-of-way) using the minimum distances from the
conductors. There is no need to extend this distance another 35 feet (on
each side) in order to obtain the full 150 foot width. This requirement is
excessive and must be adjusted to account for line construction
variations.Instead of using the term "Centerline" as referenced on Table 3,
the use of "outer phase" or "phase closest to tree line" would be more
appropriate. There is published literature using the term “cleared width” to
indicate the distance from the outer phase to the tree line. This distance
should be used in the Active ROW definition. The word easement is also
used in the definition. Is there a reason the Active ROW only includes
easements, not fee ownership, license or some other right to occupy and
manage the ROW? Would Active ROW include “danger tree rights” on land?
These questions need to be addressed in the standard (in text) and technical
reference document (in graphics).
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
20
Arizona Public
Service Company
No
These clearances could exceed the permitted ROW’s on federal lands and
the utility has no legal right to clear beyond those rights. In some cases the
permitted ROW can exceed those distance and federal agencies could not
allow you to clear beyond those clearances in this version.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
21
Entergy Services
No
This is very unclear, and creates much uncertainty as to how certain
potential outage situations should be reported. Clarification language should
be added within the Standard to help define and guide the TO's actions when
an outage occurs from a location at a point that is less than the documented
ROW boundaries (Easements) but greater than the ROW distances
represented in Table 3. It is unclear which distance should guide our
20
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
reporting actions........ROW Document Width, Table 3 ROW Widths, or the
lesser of the two.......See scenarios / examples below for consideration to aid
with clarification points:Example 1: If our documented ROW width for a
500kV line is 100' from centerline (200' total ROW width) and we have a fall
in from 90' from centerline, do we report this as a Category 2 Outage due to
the fact that it fell from within our ROW limits, or is it non-reportable due to
the fact that it is located at a greater distance than 87.5' from the centerline of
the ROW as listed in Table 3 in the Standard?Example 2: How does
maintenance and outage reporting correlate with the example defined as
follows.......You have a 230 kV line situated on one side of a 150' wide ROW
that was initially cleared to a width that would accommodate 2 separate
parallel transmission lines and structures. The second set of lines/structures
have not yet been constructed, and the current Transmission line is situated
on one side of the 150' ROW, and is being maintained to the edge of the
actual ROW on the side of the ROW that it was constructed on (maintained
to a distance of 50' from centerline that puts it at the legal edge of the ROW),
but it has been typically maintained to a distance of approximately 60' from
centerline to the inside portion/other side of the ROW (the side of the ROW
that has never been cleared), but a tree falls into the line from approx 58'
from centerline (2' within the 60' distance typically being maintained on that
line).......would this be considered a Category 2 outage since it was approx 2'
within the average width being maintained on that side of the ROW or would
it not be reported due to the fact that it was located at a distance greater than
50' as indicated in Table 3??
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
22
Kansas City Power &
Light
No
This needs to be a defined term since the Standard uses that as a basis for
use with Table 3. Using this term as a footnote does not allow the industry to
weigh in on its definition. Footnotes should not be used as a means of
definition or clarification. Footnotes are for references to other sources of
statements or documents that support a particular thought.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
21
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
23
Xcel Energy
No
We believe Active Transmission ROW should be a defined term, not buried
in a “footnote” of the “Other” section of a Standard. It still begs the question what is an “active transmission facility”? Regarding the substance, overall
we believe that the Active Transmission ROW should not include the new
reference to Table 3. This newly added sentence in footnote 2, referencing
Table 3, is confusing to interpret. If retained, please rephrase to make it
clearer that a Transmission Owner never has to increase the size of its
easement/land right to satisfy this table. As drafted, our team had various
interpretations and it is unclear whether the intent is that a Transmission
Owner has to increase its easement or acquire land to meet this requirement,
or conversely if the easement is well beyond the values in Table 3, the
Transmission Owner has to maintain that the entire easement or only the
values in Table 3.”Active Transmission Right of Way” is still used in the first
paragraph of the Background section.In total, we suggest that the definition
of Activate Transmission ROW return to the version used in the prior draft
and be placed in the definition section.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
24
ITC Transmission
No
We disagree with footnote comment as this adds confusion to the standard.
Is a footnote considered part of the standard or not? The reference to table
#3 is something new and has never been discussed or commented on prior
to this revision and appears to be a bright line concept which we are in total
disagree with.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
25
FirstEnergy
No
We do not support replacement of the term Active Transmission Line Right of
Way with Footnote #2. Since the term "active transmission line ROW" is used
in the requirements, compliance section, and VSLs, and since the drafting
team has a very definite view of what this term means, the term should be a
22
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
definition included in the NERC Glossary. Also, since ROW is defined in the
NERC Glossary, it further supports the reasons this term should also be
defined. Therefore, we suggest the team revert back to the Draft 3 proposed
NERC Glossary term.Lastly, we do not support the addition of Table 3. We
believe this adds unnecessary prescriptiveness to the requirements. It is also
not clear if this Table was intended to be mandatory because the only
reference in the table is in Footnote #2. If the SDT feels this table is a useful
tool that should be included in the standard, then we suggest adding it to the
Guidelines section as optional information. Also, reference to this Table 3 in
the Active Transmission Line ROW definition should be removed.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
26
Tampa Electric
Company
No
We have concern with the “Minimum Distances” as listed in Table 3. What
analytical methodology, criteria and rationale was utilized to determine each
recommended distance? In addition, we have concerns regarding the change
to a pre-determined distance. This seems to be a major shift from the
vegetation to conductor methodology employed previously and throughout
this standard? NERC/FERC must recognize that while protecting and
securing grid reliability, each utility must also balance the environmental,
political, customer and economic issues and impacts which will occur with
the implementation of the Table 3 clearances. We question whether this is
the most responsible action to take given the current state of the economy as
well as the environmental and political sensitivity impacts which will result.
Tampa Electric questions whether Table 3 will improve System reliability.
Since the inception of standard FAC-003-1 Tampa Electric has not had a
Category 1 or Category 2 outage on our 230kV Transmission System. We
don’t believe that the changes proposed to table 3 will improve overall
service reliability. It is Tampa Electric’s opinion that each utility should define
the width of its own Active Transmission line ROW. However, if such a table
is to be utilized, Tampa Electric recommends the following changes or
adjustments to Table 3.1. Expand the table to account for the various types
of Transmission construction; i.e. vertical versus horizontal conductor
configurations.2. Use a distance from the outermost conductor, not the
centerline. This will account for
construction type and better achieve a
23
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
consistent clearance from conductors.3. We recommend reducing the
distances in Table 3 by 12.5 feet for each voltage category. 4. Specify
whether the voltage is based upon the design or operating voltage.5.
Reformat the voltage ranges to 100kV - 200kV, 200kV - 300kV, 300kV 400kV, etc. as an example; this would create a more appropriate range of
voltages and clearance distances. The reformatted voltage ranges eliminate
confusion. For example, under the current proposal it is unclear in which
category a nominal 230kV line should be since sometimes such a line can
operate at up to 232kV during low-load conditions.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
27
American
Transmission
Company
Yes
28
BGE Forestry
Management
Yes
29
Great River Energy
Yes
30
MidAmerican Energy
Yes
31
NERC Staff
Yes
32
Pepco Holdings, Inc Affiliates
Yes
33
South Carolina and
Gas
Yes
34
Western Electricity
Coordinating Council
Yes
24
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
35
GDS Associates
Yes or No
Question 1 Comment
Yes
- ROW abbreviation comes prior to the full term (marked footnote prior to the
full term as stated in 5. Background). Please make correction accordingly.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
36
Duke Energy
Yes
However, due to different design attributes of transmission lines, it may be
better to change the distance in Table 3 from a centerline distance to a
“Minimum Full Active Transmission Line ROW Width Distance”.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
37
Idaho Power
Yes
I support the description for the active right of way. However, I believe there
needs to be a provision that addresses identifying potential hazards outside
the active right of ways that may pose a risk to the transmission lines.
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
38
Manitoba Hydro
Yes
Please add metric equivalents in the standard.While it makes some aspects
easier around pointing to what we need to keep "clear" to meet NERC rules it does limit some of our flexibility to design lines and ROWs to your own
standards. Also, the minimum only applies when you have easement larger
than the minimums in table 3, and I would assume that does not relieve you
of the responsibility to maintain ROWs appropriately if the design of your
lines requires a wider ROW.
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
25
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
39
Southern California
Edison Company
Yes or No
Question 1 Comment
Yes
SCE appreciates the SDT’s efforts to replace the defined term with a set of
minimum distances. However, the proposed new Table 3 appears to assume
a horizontal configuration of transmission lines. Thus, it would appear that
those lines configured vertically (for example, two circuits on opposite sides
of a tower), the “active right of way” required would be at least twice as large
as that for horizontal lines. SCE respectfully recommends a footnote be
added to Table 3 that allows the TO to recalculate the active right of way for
lines in a vertical configuration, based on a horizontal line configuration.
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
40
Western Area Power
Administration
Yes
Suggest using a total right-of-way width in Table 3 rather than a distance
measured from centerline.
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
41
Tri-State Generation
& Transmission
Yes
Table 3 should be referenced as a guideline only.
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
42
MRO’s NERC
Standards Review
Subcommittee (nsrs)
Yes
The NSRS agrees in whole to the question but has the SDT taken into
consideration the difference in ROW may be different in Urban and Rural
settings?
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
26
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
43
Consolidated Edison
Company of New
York Inc
Yes or No
Yes
Question 1 Comment
The same verbiage in footnote number 2 should appear below Table 3 to
avoid any confusion.
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
44
Orange and Rockland
Utilities, Inc.
Yes
There should be a statement in Table 3 that is consistent with footnote
number 2 stating that the minimum width of the Active Transmission Line
ROW is either the full width of the easement or, if the easement is wider than
the distances in Table 3, the minimum distances must not be less than the
distances shown in the Table.
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
45
Bonneville Power
Administration
Yes
This distance is reasonable in the table, but due to widely varying designs of
structures it does not give a relationship of the outside wire to edge of ROW.
It should be noted as outside wire, phase or conductor to edge of ROW.In
addition, the effective date should allow transmission owners time to achieve
this distance, perhaps one cycle.
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
27
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
2. In response to comments received regarding the terms “reasonable” and “human errors/human
activity”, the SDT modified the Other Section and Background Section. Do you agree? Please explain.
Summary Consideration:
Of 45 respondents, there are 3 abstentions, 38 are in agreement, and 4 are in disagreement.
The major comment issues raised are:
1.
Of the 4 in disagreement, only NERC believes “force majeure” statement is not necessary.
2.
Three respondents believe the “force majeure” statement should be expanded to include Federal, State,
Regulatory and legal interference.
The VM SDT considerations for the major comment issues are:
1. a) The SDT believes this language is appropriate for this standard due to the many factors related to
vegetation that are truly outside the TO’s control. Unlike the vast majority of other NERC standards,
implementation of FAC-003 is not under the absolute control of the utilities. These influences range from
landowner and agency obstacles to weather events, and as such the SDT believes the force majeure
provisions should be applicable. The recognition of this provision is also supported by 90% of the industry.
An attempt at similar language is contained in version 1 but it is ambiguous and lacks clarity. This language
adds clarity and reduces the opportunity for mis-application. Further, TO’s who elect to invoke “force
majeure” must have supporting evidence of such action. The lack of a force majeure section means a
Transmission Owner would have a violation of a Requirement, even if the penalty might have been
mitigated by the circumstances.
b) However, the SDT moved the force majeure from applicability to a footnote (Footnote 2) based on comments
concerning the structure of NERC standards. The footnotes are referenced in R1, R2, and R7. In R6, an
exclusion clause was added in Footnote 3.
3.
The SDT recommends no expansion. The “force majeure” provision is intended to recognize circumstances
that are completely outside the TO’s control. Federal, State or regulatory interference is certainly a barrier
but there are actions available to mitigate such interference. The TO should be aware of such interference
and should take whatever corrective actions necessary, up to and including re-rating or de-energizing the
line, to avoid a vegetation conflict.
28
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Some minor comment issues are:
1.
One respondent would like to specifically define wind speed.
2.
Two respondents suggested moving the language elsewhere in the standard.
The VM SDT considerations for the minor comment issues are:
1.
The SDT recommends no change. Wind speed is addressed by “fresh gale”.
2.
The SDT moved it to a footnote.
Organization
1
MWDSC
(METROPOLITAN
WATER DISTRICT
OF SOUTHERN
CALIFORNIA)
2
Western Electricity
Coordinating Council
3
Central Maine Power
Company, Iberdrola
USA
4
NERC Staff
Yes or No
Question 2 Comment
No comment suggested.
No
NERC staff does not support the language in the Other Section. Staff
believes that the force majeure provision is unnecessary and calls into
question whether NERC and the regions have enforcement discretion to take
such things into account in applying other standards that do not include this
type of provision.
Response: The SDT thanks you for your comments. The SDT believes this language is appropriate for this
standard due to the many factors related to vegetation that are truly outside the TO’s control. Unlike the vast
majority of other NERC standards, implementation of FAC-003 is not under the absolute control of the
29
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
utilities. These influences range from landowner and agency obstacles to weather events, and as such the
SDT believes the force majeure provisions should be applicable. The recognition of this provision is also
supported by 90% of the industry. An attempt at similar language is contained in version 1 but it is
ambiguous and lacks clarity. This language adds clarity and reduces the opportunity for mis-application.
Further, TO’s who elect to invoke “force majeure” must have supporting evidence of such action.
5
BGE Forestry
Management
No
Suggest including in “4.4. Other” a phrase referencing government
interference, such as “Federal, State or other regulatory interference,
including legal or other legislative actions, that prevents performance to
comply with this reliability standard.”
Response: The SDT thanks you for your comments. The “force majeure” provision is intended to recognize
circumstances that are completely outside the TO’s control. Federal, State or regulatory interferrence is
certainly a barrier but there are actions available to mitigate such interference. The TO should be aware of
such interference and should take whatever corrective actions necessary, up to and including re-rating or
de-energizing the line, to avoid a vegetation conflict.
6
Kansas City Power &
Light
No
The theme of the “Other” section are the conditions for excluding applicable
transmission facilities under certain conditions. Recommend the Drafting
Team consider renaming this section to “Exclusions”. In addition, the term,
“Active Transmission Line Right-of-Way” is capitalized in the “Background”
section. If it is determined this term should not be a definition, then this
should be lower case.
Response: The SDT thanks you for your comments. The recommendation does not materially change the
“force majeure” provision and the SDT does not recommend any change. The SDT did modify the ROW
definition in response to industry concerns. Capitalization is now appropriate.
7
Xcel Energy
No
Xcel Energy urges the retention of the word "reasonable" as a modifier to
"control" in Introduction, Section 4.4. The concept that a Transmission
Owner should exercise reasonable control is sensible, and is of some aid in
countering claims that any incident could be prevented. For example, in
Colorado, the transmission of electricity has been judicially found to be
subject to the highest degree of care. Without the inclusion of the word
"reasonable," Xcel Energy could possibly be faced with a claim that for the
exceptions set forth in Introduction, Section 4.4, to apply, the circumstances
would have to be "beyond the control (using the highest degree of care) of
30
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
Xcel Energy." Retention of "reasonable" helps counter such claims. Since
this section appears to lean toward legal language, the use of the term
“reasonable” is better suited for the goal of this section.
Response: The SDT thanks you for your comments. While we understand the concerns, the word
reasonable is ambigous and open to intrepretation and therefore not an appropriate modifier to the language.
8
Allegheny Power
Yes
9
Ameren
Yes
10
American
Transmission
Company
Yes
11
Arizona Public
Service Company
Yes
12
Bonneville Power
Administration
Yes
13
Consolidated Edison
Company of New
York Inc
Yes
14
Consumers Energy
Company
Yes
15
FPL Corporate
Compliance
Yes
16
Dominion
Yes
17
Duke Energy
Yes
31
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
18
Entergy Services
Yes
19
Exelon
Yes
20
GDS Associates
Yes
21
Hydro One
Yes
22
Idaho Power
Company
Yes
23
ITC Transmission
Yes
24
Manitoba Hydro
Yes
25
MidAmerican Energy
Yes
26
Northeast Power
Coordinating Council
Yes
27
Northeast Utilities
Yes
28
Orange and Rockland
Utilities, Inc.
Yes
29
Pepco Holdings, Inc Affiliates
Yes
30
PNM
Yes
31
PPL Electric Utilities
Yes
32
Progress Energy
Yes
Question 2 Comment
32
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
33
South Carolina and
Gas
Yes
34
Southern Company
Transmission
Yes
35
The United
Illuminating Company
Yes
36
Tri-State Generation
& Transmission
Yes
37
Western Area Power
Administration
Yes
38
Great River Energy
Yes
Question 2 Comment
GRE believes that the new definition provides greater clarity with respect
what does not constitute a compliance violation versus the previous version.
Response: The SDT thanks you for your comments and we are in agreement.
39
CenterPoint Energy
Yes
No preference.
Yes
SCE generally agrees with the information contained in Part 5 - Background.
However, we question the value of placing a rationale within the body of the
standard. SCE respectfully recommends that the revised “Background”
information be added to the beginning of the “Guidelines and Technical
Basis,” which also includes explanations for various standard segments.
Response:
40
Southern California
Edison Company
Response: The SDT thanks you for your comments. It is not specific to “force majeure” and is best
answered in general comments.
41
MRO’s NERC
Standards Review
Yes
The NSRS believes that the new definition provides greater clarity with
respect what does not constitute a compliance violation versus the previous
33
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Subcommittee (nsrs)
Question 2 Comment
version.
Response: The SDT thanks you for your comments and we are in agreement.
42
Tampa Electric
Company
Yes
These changes add improved clarity and defintion to this section.
Response: The SDT thanks you for your comments and we are in agreement.
43
Idaho Power
Yes
This will allow the utilities to address conditions that are within their control.
Response: The SDT thanks you for your comments and we are in agreement.
44
FirstEnergy
Yes
While we agree with the changes proposed, we would recommend that the
list contained in the "Other" section should be revised to include judicial
actions such as injunctions. While this is not a natural occurring situation, it
is certainly one that will prevent an entity from removing vegetation when
needed or desired.
Response: The SDT thanks you for your comments. The “force majeure” provision is intended to recognize
circumstances that are completely outside the TO’s control. Legal and judicial actions are certainly a barrier
but there are other corrective actions available to mitigate such interference. The TO should be aware of
such interference and should take whatever actions necessary, up to and including re-rating or de-energizing
the line to avoid a vegetation conflict.
45
BC Hydro
Yes
Yes but there should be more commentary around exceptions. You should
get away from certain descriptive terms and be more empirical when you can
to avoid ambiguity. For example “Fresh Gale” on the Beaufort Scale is not
common as there are several variants to this scale and on some scales is
defined as “Gale”. So do you mean winds of 39-46 mph (62-74 kmh) or
greater wind speed? If so, why not state that?
Response: The SDT thanks you for your comments. The “force majeure” provision is not intended to
address every possible exclusion but to be a general statement intended to recognize circumstances that are
completely outside the TO’s control.
34
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
3. In response to comments received regarding the language in M1 and M2, the SDT modified the first
bulleted item and added a sentence to the end of the paragraph in M1 and M2. Do you agree? Please
explain.
Summary Consideration:
Of 45 respondents, there are 2 abstentions, 27 are in agreement, and 16 are in disagreement.
The major comment issues raised are:
1.
Definition of “qualified personnel”.
2.
Confusion around “real time observation of an encroachment into the MVCD” and documentation required to
report a violation or attest that a violation did not occur. Also issues regarding an encroachment with no
fault and/or momentary fault as being a violation.
The VM SDT considerations for the major comment issues are:
1.
SDT changed the language to “confirmation by Transmission Owner”.
2.
Considered language proposed by Duke in comment 16 and adopted and modified by SDT.
A minor comment issue is:
1.
The inclusion of examples in the requirement instead of the rationale box.
The VM SDT consideration for the minor comment issue is:
1.
The SDT changed the language to “confirmation by Transmission Owner”.
Organization
1
Yes or No
Question 3 Comment
MWDSC
(METROPOLITAN
35
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
WATER DISTRICT
OF SOUTHERN
CALIFORNIA)
2
Xcel Energy
3
GDS Associates
No comments/no position
No
- Need to specify who qualifies as “qualified personnel” to observe the
vegetation condition.
Response: Thank you for your comment. The SDT changed the wording to confirmation by the
Transmission Owner.
4
Hydro One
No
A clarification for M1 is needed regarding whether entities will have to attest
to the fact that there has never been an encroachment in the MVCD.
Response: Thank you for your comment. It is not the intent of this standard for entities to be required to
prove a negative. The SDT believes the proposed language does not imply that an entity will be required to
prove that an encroachment has not occurred.
5
Northeast Power
Coordinating Council
No
A clarification for M1 is needed regarding whether entities will have to attest
to the fact that there has never been an encroachment in the MVCD.
Response: Thank you for your comment. It is not the intent of this standard for entities to be required to
prove a negative. The SDT believes the proposed language does not imply that an entity will be required to
prove that an encroachment has not occurred.
6
PPL Electric Utilities
No
As written M1 requires evaluation of condition by “qualified person” but no
definition of qualified person given. Should be more direct and point to
physical evidence of vegetation encroachment into MVCD, i.e. burned
vegetation.
Response: Thank you for your comment. The SDT changed the wording to confirmation by the
Transmission Owner. It is not the intent of this standard for entities to be required to prove a negative. The
SDT believes the proposed language does not imply that an entity will be required to prove that an
encroachment has not occurred.
36
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
7
CenterPoint Energy
Yes or No
Question 3 Comment
No
CenterPoint Energy does not believe a performance based requirement
should require evidence of processes and procedures to demonstrate
compliance. However, if the majority of industry commenters agree with the
SDT’s approach, CenterPoint Energy has several concerns.Assuming R1.1
and R2.1 regarding observations of encroachments are not deleted from the
Standard, then only the first paragraph regarding forms of evidence is helpful
and necessary. The second paragraph is not relevant or necessary. The
special qualification of Sustained Outage should be contained in R1 and R2,
not M1 and M2. Also, the reference to a “Fault” in M1 and M2 instead of a
“Sustained Outage” changes the scope of what is specified in R1 and R2
which is not reasonable. A “Fault” can be associated with a Momentary
Outage or a Sustained Outage. The scope of R1 and R2 is specific to
Sustained Outages.
Response: Thank you for your comment. The SDT chose the word “fault” as it is a NERC defined term. A
fault associated with vegetation indicates that encroachment into the MVCD occurred.
8
Arizona Public
Service Company
No
Do not agree with real-time observation. Utility can use technology to
determine all rated conditions if a tree related outage occurred.
Response: Thank you for your comment. The real-time observation reference applies to cases where
vegetation encroaches into the MVCD but flash-over has not occurred. Enroachment into the MVCD where
no fault occurs is the least severe violation of the requirement.
9
MidAmerican Energy
No
Examples should be moved to the rationale boxes to avoid confusion on
what is required and what is an example. All rationale boxes should have a
disclaimer to the effect saying "For guidance only, not for enforcement".
Response: Thank you for your response. Examples were included in the Requirement at the response of
NERC staff to add clarity. By definition, verbiage within the rationale boxes are for guidance and are not
enforcable.
10
Kansas City Power &
Light
No
In response to the informal comment period, the SDT is clear that it believes
the use of encroachment as a basis for determining the effectiveness and
compliance of a vegetation management program. The purpose of this
Standard is to identify the criteria for effective monitoring of vegetation in
37
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
transmission right-of-way and to take appropriate actions when that
monitoring identifies the need to “clear” vegetation to prevent potential
transmission facility outages resulting from contact with vegetation. These
proposed Measures as written do not give credit to the Transmission Owners
for effectively monitoring their systems and taking appropriate actions in
regard to vegetation clearing. Why does it make sense to punish and
penalize a Transmission Owner for discovering an encroachment when they
take the appropriate actions to remedy the condition before any facility
outage occurs that results in compromising the reliability of the Bulk Electric
System? These Measures and Standard should recognize the good
practices of effective response to a vegetation condition and penalize
ineffective response. Highly recommend the SDT consider including
appropriate language to recognize effective remedial actions by
Transmission Owners and by doing so, recognize effective efforts instead of
punishing them.In addition, proving encroachments have not occurred will
pose audit challenges in determining that encroachments have not occurred
for the Auditors as well as Registered Entities. If no encroachments occur,
then there is nothing to report or record. This is a weak platform to stand
compliance on. Facility interruption events caused by vegetation contacts is
definitively measurable and recordable. Recommend the SDT reconsider the
concept of compliance with FAC-003 on the basis of sustained outages.
Response: Thank you for your comment. The real-time observation reference applies to cases where
vegetation encroaches into the MVCD but flash-over has not occurred. Enroachment into the MVCD where
no fault occurs is the least severe violation of the requirement. It is not the intent of this standard for entities
to be required to prove a negative. The SDT believes the proposed language does not imply that an entity
will be required to prove that an encroachment has not occurred.
11
BGE Forestry
Management
No
M1 & M2 bullet: “Real-time observation of any MVCD encroachments.”
implies that real-time observation of vegetation encroachment ensures
reliable operation the Bulk Electric System. The reliability standard objective
states;”To improve the reliability of the electric Transmission system by
preventing those vegetation related outages that could lead to
Cascading.”However, real time observation of current operating conditions
provides no assurance that vegetation will not lead to outages. BGE
recommends removing the language. If an inspector finds vegetation
encroaching into the MVCD during a visual inspection he / she should
38
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
immediately initiate an Immediate Threat Notification. Therefore, this
measure has no value.
Response: Thank you for your comment. The real-time observation reference applies to cases where
vegetation encroaches into the MVCD but flash-over has not occurred. Enroachment into the MVCD where
no fault occurs is the least severe violation of the requirement.
12
PNM
No
Needs a definition of Real Time Observations
Response: Thank you for your comment. The SDT believes that “Real Time” observations (the actual time
during which the observation occurs) is sufficiently clear.
13
Consumers Energy
Company
No
None of the three examples of acceptable forms of evidence provided in the
revision prove that a Transmission Owner actively managed vegetation to
prevent encroachment into the MVCD. The Measure should require proof of
active ROW clearing activity per the transmission vegetation management
plan, such as invoicing or crew field reports or vegetation inspection data
from the annual vegetation inspection.
Response: Thank you for your comment. The SDT would suggest you refer to R6 and R7, which addresses
evidence of an annual vegetation inspection and work plan.
14
BC Hydro
No
Overall, the definition of these measures is improved over draft 3. However,
the standard should better define who a “qualified person” is and who has the
authority to make attestations. R1 and R2 could be better defined relative to
the standard definitions in section 4.2 as to what voltage levels in R2 are part
of the standard and what is excluded. That is:R1 is any circuit that is an
element of an IROL or WECC transfer path regardless of the transmission
voltage.R2 is any circuit >200kV which is not an element of an IROL or
WECC transfer path.Lower voltage circuits that do not fit the R1 definition are
not part of this standard.
Response: Thank you for your comment. The SDT changed the wording to confirmation by the
Transmission Owner. R1 and R2 intentionally differentiate between the components of the transmission
system that are part of the IROL or WECC Transfer Path and the BES. The SDT believes that violations in the
IROL or WECC Transfer Paths pose a greater risk of cascading events, and therefore carry higher VSLs.
39
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
15
Central Maine Power
Company, Iberdrola
USA
Yes or No
No
Question 3 Comment
Recommend SDT create two measures one measure if a tree violated the
MVCD and no outage occurred and second measure and severity level if an
outage occurred
Response: The SDT believes that enroachments into the MVCD where no fault occurs are a violation to the
standard and should be included in R1 and R2.
16
Duke Energy
No
The last sentence of this modification could be misinterpreted by a
compliance representative to imply that all Faults must be investigated to
eliminate or confirm vegetation as the cause of the fault. There are several
sources (e.g. lightning, wind-blown debris) of Faults and several appropriate
operational responses, some of which may not include field investigations,
depending on the circumstances surrounding each Fault. Thus, the current
wording is gray and should be modified to aid industry’s understanding and
thus to ensure compliance.The interpretation we suggest may not be
obvious, but our experience with previous interpretations of certain facets of
FAC-003-01 would indicate the need to better define the expectation.A
potential modification to the last sentence of M1/M2 could be:If a later
confirmation of a Fault by a qualified person shows that a vegetation
encroachment within the MVCD has occurred, this shall be considered the
equivalent of a Real-time observation.
Response: Thank you for your comment. The SDT agrees with your recommendation and has adopted the
proposed language. The SDT believes that faults that occur on applicable lines included in R1 and R2
should be investigated to determine if the cause was vegetation related. If an entity can determine to their
satisfaction, through documentable means such as through technology or other sources, that the fault was
caused by some other reason (i.e. lightning), it is the entity’s decision whether or not to investigate further.
17
FPL Corporate
Compliance
No
The measure is adding to the requirement. The measure should define how a
requirement is met and not interpret or add to the requirement, otherwise this
will add to confusion, instead of clarity, which should be the goal of any
revised reliability Standard.Also, the measure implies that a fault
investigation must be done. As written, momentary outages are included, and
a fault investigation should not be required for momentary outage.It also
places the same weight of violation on a momentary outage as it does a
Sustained outage, which appears on its face not to appropriate nor
40
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
necessary to meet the goal of FAC-003-2. In addition, an outage
investigation is not a finite process that produces identical homogenous
results every time. Of particular concern is the possibility that should a
Transmission Owner have one or more momentary outages and not find the
cause, then later have another outage (Sustained or Momentary), such a
finding appears to lead to a multiple violation. This is inconsistent with
focusing requirements on reliability risks to the bulk electric system.
Response: Thank you for your comment. A fault caused by the grow-in, fall-in, or blow-in of vegetation on
the active right-of-way is a violation of the requirements regardless of whether the fault was momentary or
sustained. Based on other comments, the SDT has modified the language in M1/M2.
18
NERC Staff
No
With respect to both M1 and M2, NERC staff finds the “acceptable forms of
evidence” incomplete. To assess compliance, the auditors would also need
to see the processes and procedures identified under Requirement R3 and
the annual work plan under Requirement R7 to see how the entity planned to
prevent sustained outages and what the entity had done to implement that
plan. Finally, what is the purpose of the following sentence?: “If an
investigation of a Fault by a qualified person confirms that a vegetation
encroachment within the MVCD occurred, then it shall be considered a Realtime observation.” Recommend adding each report of a real-time observation
of encroachment into the MVCD to the periodic data submittal.
Response: Thank you for your comment. The SDT believes that an attempt to list all “acceptable forms of
evidence” would be difficult, as entities employ a myriad of documentation types. The SDT agrees that an
auditor would need to see the processes and procedures indentified under R3 and R7 to perform an audit.
An auditor with an understanding of vegetation management would be able to validate “acceptable forms of
evidence” as part of compliance audit process. Real time observations of an encroachment into the MVCD
is a violation of the standard and should be documented and self-reported. The RE’s currently require
periodic reporting.
19
Allegheny Power
Yes
20
Ameren
Yes
21
American
Yes
41
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
Transmission
Company
22
Bonneville Power
Administration
Yes
23
Consolidated Edison
Company of New
York Inc
Yes
24
Dominion
Yes
25
Exelon
Yes
26
Idaho Power
Yes
27
Idaho Power
Company
Yes
28
ITC Transmission
Yes
29
Manitoba Hydro
Yes
30
MRO’s NERC
Standards Review
Subcommittee (nsrs)
Yes
31
Northeast Utilities
Yes
32
Orange and Rockland
Utilities, Inc.
Yes
33
Pepco Holdings, Inc –
Affiliates
Yes
42
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
34
Progress Energy
Yes
35
South Carolina and
Gas
Yes
36
Southern Company
Transmission
Yes
37
The United
Illuminating Company
Yes
38
Tri-State Generation
& Transmission
Yes
39
FirstEnergy
Yes
Question 3 Comment
Although we agree with the language of M1 and M2 for the proposed R1 and
R2 in the standard being balloted, we support the alternate versions of R1
and R2 (see comments in Question 6) and wish to see M1 and M2
developed for the alternate R1 and R2.
Response: Thank you for your comment.
40
Great River Energy
Yes
GRE agrees with the revisions made to this standard since the last posting
and requests clarification on what constitutes a qualified person.
Response: Thank you for your comment. The SDT changed the wording to confirmation by the
Transmission Owner.
41
Western Electricity
Coordinating Council
Yes
however the statement of acceptable forms of evidence implies that a dated
attestation alone could provide evidence of compliance. An attestation alone
would not represent sufficient evidence to support a conclusion of
compliance with encroachment limits only of the absence of an outage.
Response: Thank you for your comment. Real time observations of an encroachment into the MVCD is a
violation of the standard and should be documented and self-reported.
43
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
42
Western Area Power
Administration
Yes or No
Yes
Question 3 Comment
However, the last sentence added to the measure is imprecise and
introduces undesirable subjectivity and confusion to the process for
determining a compliance violation.
Response: Thank you for your comment. Based on the recommendation from several commentors, the last
sentence in M1/M2 has been modified.
43
Southern California
Edison Company
Yes
SCE generally agrees with the revisions to M1 and M2, however we would
suggest the last sentence of the second paragraphs in both M1 and M2 be
modified to read: M1- Multiple Sustained Outages on an individual line, if
caused by the same vegetation, will be reported as one outage regardless of
the actual number of outages within a 24-hour period. If an investigation of a
Fault, by a qualified person, confirms that a vegetation encroachment, as
described in R1 items 2-4 (above), occurred within the MVCD occurred, then
it shall be considered a Real-time observation.M2- Multiple Sustained
Outages on an individual line, if caused by the same vegetation, will be
reported as one outage regardless of the actual number of outages within a
24-hour period. If an investigation of a Fault, by a qualified person, confirms
that a vegetation encroachment, as described in R2 items 2-4 (above),
occurred within the MVCD occurred, then it shall be considered a Real-time
observation.
Response: Thank you for your comment. Based on the recommendation from several commentors, the last
sentence in M1/M2 has been modified.
44
Tampa Electric
Company
Yes
These changes allow for qualified review of field findings.
Response: Thank you for your comment.
45
Entergy Services
Yes
We agree, IF the determination is made by a Qualified Person to have been
caused by vegetation breaking the MVCD (if not breaking MVCD in real time
when observed) based on close observation/inspection and hard evidence
that a Flashover occurred, and that there is no evidence that the issues
spotted on the tree were caused by environmental or biological symptoms or
stressors of the tree in question. Hard evidence has to be present to classify
44
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
the item as a vegetation outage if the tree is not within MVCD when the real
time observation is made.....an assumption cannot be made that vegetation
was the cause of an outage if the tree is situated at a distance that is greater
than MVCD when observed unless there is hard evidence supporting the
flashover as determined by a qualified person.
Response: Thank you for your comment.
45
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
4. In response to comments received that requirement R3 is deficient in detail, the SDT modified the
requirement. Do you agree? Please explain.
Summary Consideration:
Of 45 respondents, there are 32 in agreement, 12 in disagreement and1 abstention.
The major comment issues raised are:
1.
The additional wording placed in the requirement after the first sentence adds confusion to the extent of
documentation that will be required.
2.
The use of the phrase “incorporate the dynamics” adds confusion to the requirement.
The VM SDT considerations for the major comment issues are:
1.
The response pointed out that the reason that the additional wording was inserted was due to the numerous
comments from the previous posting that the requirement needed more specificity.
2.
The SDT agreed with some suggested wording to replace the phrase “incorporate the dynamics” and revised
the requirement accordingly.
Some minor comment issues are:
1.
One commenter questioned the use of the word “intent” in the rationale.
2.
One commenter questioned the language of the measure.
3.
One commenter was concerned that the removal of the programmatic details renders the requirement less
auditable and questionably effective.
The VM SDT considerations for the minor comment issues are:
1.
The wording in the rationale was changed to eliminate the word “intent”.
2.
In the response to the commenter questioning the language of the measure, the SDT explained that the
focus of the measure is on the logic test of the Transmission Owner’s vegetation maintenance program.
46
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
3.
In response to the commenter concerned about the programmatic details being removed, the SDT
responded by explaining various ways that this requirement could be audited and further explained the
main focus of the requirement.
Organization
1
MWDSC
(METROPOLITAN
WATER DISTRICT
OF SOUTHERN
CALIFORNIA)
2
GDS Associates
Yes or No
Question 4 Comment
No
- We suggest to eliminate / change the word “dynamics” because can create
confusion with regards to the extent of documentation that has to be
prepared.- Requirement should clearly state the criteria as in the maximum
design (rating) or maximum operat
Response: The SDT thanks you for your comment. The intent of the more detailed wording of R3 in this
version of the Standard is to make sure that the Transmission Owner adequately documents and
demonstrates that it understands the complex relationship of conductor movement under thermal and wind
load and vegetation growing and moving in proximity to the line. In light of your comment, and similar
comments from others, the SDT has revised the wording of R3. We feel that this change will alleviate any
perceived confusion.
3
PPL Electric Utilities
No
As written, R3 now requires documentation of conductor dynamics as related
to ratings and rated operational conditions. Not clear how this information is
to be presented and documented and how vegetation conditions that exist
are to be documented to provide evidence that management processes and
procedures are adequate to prevent encroachment into MCVD.
Response: The SDT thanks you for your comment. The Technical Reference Document attempts to provide
further explanation, along with examples, of how to present this information. While this information is not in
the Standard itself, the supplemental information in the Technical Reference Document should help the
Transmission Owner understand the SDT’s intent for the requirement. Also, The SDT has revised the
wording in R3 and has removed the word “dynamics”.
47
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
4
Great River Energy
Yes or No
Question 4 Comment
No
GRE does not believe that the new specificity that has been added to R3 will
improve the reliability of the BES. It is our opinion that the requirement would
have been clearer if it had ended after the first sentence. The additional
language after the first sentence does not improve clarity.In measures for
other requirements the SDT has done a very good job of stating and
clarifying (in their opinion) what acceptable forms of evidence are. M3 would
benefit from this type of clarification.
Response: The SDT thanks you for your comment. The previous version of the Standard was crafted very
much as you suggest. Many commenters disagreed with this approach, which led to the SDT crafting this
more verbose version.
5
Kansas City Power &
Light
No
It is unclear that this requirement may utilize the industry practice of “ruling
span” methods to determine the vegetation clearances for a transmission
facility. “Ruling span” methods are used to determine the construction
design for transmission facilities and includes maintaining safe clearance
distances. This requirement could be interpreted as being applied to every
individual span to determine vegetation clearances for a transmission facility
which would not be practical.
Response: The SDT thanks you for your comment. The intent of R3 in this version of the Standard is to
make sure that the Transmission Owner adequately documents and demonstrates that it understands the
complex relationship of conductor movement under thermal and wind load and vegetation growing and
moving in proximity to the line. It leaves the decision to the Transmission Owner how to satisfy this
“competency based” requirement. While a Transmission Owner could certainly take the approach that each
individual span be addressed separately, it is also possible for a Transmission Owner to have a specific
“vegetation maximum height” approach, based on the minimum ground clearance specification of an entire
line. Either approach would satisfy this requirement.
6
MidAmerican Energy
No
MidAmerican supports the additional detail the R3 should end after the first
sentence. The additional detail should be moved to the rationale box as
additional guidance.
Response: The SDT thanks you for your comment. If we understand your comment, the reason that R3 has
greater detail was due to comments received after the last posting. The SDT felt compeled to add this
additional information.
48
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
7
Xcel Energy
Yes or No
Question 4 Comment
No
R3 requires the Transmission Owner to have a documented process that
shall contain certain items. Please bulletize these items for
clarity.Additionally, the measure for this requirement indicates that the
process document elements ‘prevent’ encroachment. It is presumed that the
elements identified in the requirement are what need to be addressed in
order to minimize the likelihood of encroachment. Essentially, M3 should be
reworded to state “The procedures, processes, or specifications provided
incorporate the elements identified in R3 (dynamics of a transmission line
conductor’s...)
Response: : The SDT thanks you for your comment. The SDT feels that the requirement is adequate in a
non-bullet form. R3 has been revised to clarify the intent of this “competency based” requirement. The
measure for this requirement should be a “logic” test looking at the methodology that the Transmission
Owner uses in order to determine what vegetation actions need to take place. The Technical Reference
Document gives examples of several ways to satisfy this requirement. The SDT feels that the measure as
stated is adequate.
8
Southern California
Edison Company
No
SCE prefers the Draft 3 version of R3 which read:”Each Transmission Owner
shall have a documented transmission vegetation management program that
describes how it conducts work on its Active Transmission Line ROWs to
avoid Sustained Outages due to vegetation, considering all possible
locations the conductor may occupy assuming operation within Rating and
Rated Electrical Operating Conditions.”However, if the SDT believes it is
prudent to revise R3 in response to certain commenters, SCE would
respectfully recommend R3 be revised to read:”Each Transmission Owner
shall document the procedures, processes, or specifications it uses to
prevent the encroachment of vegetation into the MVCD. Such documentation
will account for the movement of transmission line conductors under their
Rating and Rated Electrical Operating Conditions; and the inter-relationships
between vegetation growth rates, vegetation control methods, and inspection
frequency, for the Transmission Owner’s applicable lines.”
Response: The SDT thanks you for your comment. The SDT agrees that the wording in R3 should be
modified. R3 has been revised to remove the reference to “incorporate the dynamics” and has recrafted the
requirement wording similar to your latter recommendation.
49
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
9
CenterPoint Energy
Yes or No
Question 4 Comment
No
See response to Q3 above. However, assuming R3 is not revised to exclude
processes and procedures, we have no preference to the wording between
the two drafts.
Response: The SDT thanks you for your comment.
10
Arizona Public
Service Company
No
Still lacks detailed information. SDT needs to specify the documentation it is
left up to interpretation by the utility.
Response: The SDT thanks you for your comment. The SDT feels that the combination of the requirement
wording and the examples and explanations in the Technical Reference Document are sufficient detail to
portray the intent.
11
MRO’s NERC
Standards Review
Subcommittee (nsrs)
No
The NSRS does not believe that the new specificity that has been added to
R3 will improve the reliability of the BES. It is our opinion that the
requirement would have been clearer if it had ended after the first sentence.
The additional language after the first sentence does not improve clarity.
The whole (as written) requirement may be interpreted as a requirement for
“each span” of Transmission line to which the Requirement will be applied. In
measures for other requirements the SDT has done a very good job of
stating and clarifying (in their opinion) what acceptable forms of evidence
are. M3 would benefit from this type of clarification.
Response: The SDT thanks you for your comment. The previous version of the Standard was crafted very
much as you suggest. Many commenters disagreed with this approach, which led to the SDT to address this
issue by adding the specificity.
R3 is a “competency based” requirement. The measure should be whether the methodology used by the TO
to maintain vegetation passes the basic logic test. (eg: Our max growth rate is 3’ per year. We have a
minimum ground clearance spec for 230 kV of 24 feet at maximum sag. We maintain the lines every three
years. During maintenance of 230 kV lines we remove all vegetation over 11.5 feet high) For a “results
based” standard, the emphasis should be on the Tranmssion Owner demonstrating competency in its
approach, however simple or complex that approach may be
12
NERC Staff
No
The removal of programmatic details from R3 renders the auditing task much
more difficult. How does one assess the quality of the program except
50
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
through the results required in R1 and R2? Since maintaining specific cut-to
clearances is not required, there is much greater subjectivity in application
that greatly complicates the auditor job. If the team does not want to limit the
available approaches, it could provide flexibility by offering an array of
deterministic formulas or approaches for maintaining vegetation. This might
include maintaining vegetation to remain within a certain height from the
ground given maximum sag distances.
Additionally, this requirement does not seem to require the entity to actually
follow its policies and procedures (unlike, for instance, R7). What is a
violation here? Not having the documented procedure(s) OR whether the
documented procedure(s) actually demonstrate that the entity can prevent
encroachment?
NERC staff is also concerned with some of the language in M3. Consider the
following modification: “The Transmission Owner will have procedures,
processes, or specifications as identified in Requirement R3, records
showing work done to support its annual work plan identified in Requirement
R7, and its quarterly vegetation reports, to demonstrate that it can prevent
encroachment into the MVCD.”
Finally, with respect to the Rationale associated with R3, how would NERC
enforce poor intent or a poor indication of competency (especially if the entity
was performing well)? Recommend: Provide a basis for evaluating whether
the Transmission Owner’s procedures, processes, or specifications used to
maintaining vegetation are achieving that goal. There may be many
acceptable approaches to controlling vegetation so that it does not encroach
into the MVCD.
And one small copyedit: “interrelationships” should not have a hyphen.
Response: The SDT thanks you for your comment.
51
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
Regarding the comments pertaining to the requirement wording: The intent of R3 in this version of the
Standard is to make sure that the Transmission Owner adequately documents and demonstrates an
understanding of the complex relationship of conductor movement under thermal and wind load and
vegetation growing and moving in proximity to the line. The SDT points out that inclusion of a programatic
list of activities by itself does nothing to to ensure reliability. R3 is a competency based requirement. The
audit test is simply one of logic. Does the methodology the TO conveys in R3 logically ensure that no
encroachments into the MVCD occur? The SDT feels that it is important for the Transmission Owner to have
the flexiblity to choose how it satisfies this requirement and not to provide a limited menu of approaches that
could be used. (eg: Our max growth rate is 3’ per year. We have a minimum ground clearance spec for 230 kV
of 24 feet at maximum sag. We maintain the lines every three years. During maintenance of 230 kV lines we
remove all vegetation over 11.5 feet high) For a “results based” standard, the emphasis should be on the
Tranmssion Owner demonstrating competency in its approach, however simple or complex that approach
may be. The violation for this requirement would be either the TO failed to specify its approach or that the
approach specified does not pass the logic test.
Regarding the comments pertaining to the measures M3: The SDT feels that an auditor knowledgeable of
utility vegetation management work would be capable to evaluate if a well documented approach is sufficient
to ensure no vegetation encroachments into the MVCD.
Regarding the comments pertaining to the Rationale: The drafting team agrees that “intent” is not
measurable or enforceable and has removed it from the rationale. The evaluation and measurement of the
competency is listed above.
13
Consumers Energy
Company
No
This really is another attempt at avoiding defining a minimum clearance
specification and is not practical. As written, this would require each
Transmission Owner to define and document the procedures, processes or
specification by individual span for every line owned or operated by the
Transmission Owner. Each span varies in length and profile and a single line
may have several different conductor types with different load ratings. Line
loadings will vary along the line based on substation taps, etc. The dynamics
described in the language could only be done on an individual span basis to
be reasonably accurate. This is not practical from a planning standpoint or
from a standpoint of implementing clearing work in the field.
Response: The SDT thanks you for your comment. The intent of R3 in this version of the Standard is to
make sure that the Transmission Owner adequately documents and demonstrates that it understands the
complex relationship of conductor movement under thermal and wind load and vegetation growing and
moving in proximity to the line. It leaves the decision to the Transmission Owner how to satisfy this
52
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
“competency based” requirement. While a Transmission Owner could certainly take the approach that each
individual span be addressed separately, it is also possible for a Transmission Owner to have a specific
“vegetation maximum height” approach based on the minimum ground clearance specification of an entire
line. Either extreme would satisfy this requirement. A Transmission Owner also could have an approach
that contained a mixture of the two extremes.
14
Allegheny Power
Yes
15
Ameren
Yes
16
American
Transmission
Company
Yes
17
BGE Forestry
Management
Yes
18
Bonneville Power
Administration
Yes
19
Central Maine Power
Company, Iberdrola
USA
Yes
20
Consolidated Edison
Company of New
York Inc
Yes
21
FPL Corporate
Compliance
Yes
22
Duke Energy
Yes
23
Entergy Services
Yes
53
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
24
Exelon
Yes
25
FirstEnergy
Yes
26
Hydro One
Yes
27
Idaho Power
Yes
28
Idaho Power
Company
Yes
29
ITC Transmission
Yes
30
Manitoba Hydro
Yes
31
Northeast Power
Coordinating Council
Yes
32
Northeast Utilities
Yes
33
Orange and Rockland
Utilities, Inc.
Yes
34
Pepco Holdings, Inc Affiliates
Yes
35
PNM
Yes
36
Progress Energy
Yes
37
South Carolina and
Gas
Yes
38
The United
Yes
Question 4 Comment
54
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
Illuminating Company
39
Tri-State Generation
& Transmission
Yes
40
Western Area Power
Administration
Yes
41
Western Electricity
Coordinating Council
Yes
Response:
42
Dominion
Yes
Although we agree with the intent of the proposed language, we feel the
requirement should be revised to read:Each Transmission Owner shall
document the procedures, processes, or specifications it uses to prevent the
encroachment of vegetation into the MVCD. Such procedures, processes, or
specifications shall consider the dynamics of a transmission line conductor’s
movement throughout its Rating and Rated Electrical Operating Conditions
and the inter-relationships between vegetation growth rates, vegetation
control methods, and inspection frequency, for the Transmission Owner’s
applicable lines.
Response: The SDT thanks you for your comment. The SDT agrees that the wording in R3 should be
modified. R3 has been revised to remove the reference to “incorporate the dynamics” and has recrafted the
requirement wording similar to your latter recommendation.
43
BC Hydro
Yes
As a competency requirement, R3 seems to be missing any requirement for
a utility to define who is qualified to develop these plans, which is a departure
from FAC-003-1 R1.3. I think that the utility should in their standards define
who is qualified to develop their transmission vegetation management
program
Response: The SDT thanks you for your comment. While the SDT agrees that personnel qualifications are
important in any pursuit for perfection, the overall approach for this version of the Standard is a “results
based’ product. In light of that, the SDT does not feel that a “fill in the blank” requirement for personnel
55
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
qualifications is necessary.
44
Tampa Electric
Company
Yes
This better clarifies section R3
Yes
While voting yes we are concerned about the interpretation of the expanded
verbiage, how much documentation will be enough.
Response:
45
Southern Company
Transmission
Response: The SDT thanks you for your comment. The Technical Reference Document attempts to provide
further explanation, along with examples, of how to present this information. While these examples are not
in the Standard itself, the supplemental information in the Technical Reference Document should help the
Transmission Owner understand the SDT’s intent for the requirement, and therefore the documentation
required to demonstrate competency.
56
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
5. In response to comments received that requirement R7 is unclear with respect to flexible work plans,
the SDT modified the requirement. Do you agree? Please explain.
Summary Consideration:
Of 45 respondents, there are 2 abstentions, 34 are in agreement, and 9 are in disagreement.
The major comment issues raised by those in disagreement are:
1.
2.
The Requirement is vague and needs more specificity and explanation.
•
Does not require development of the Annual Vegetation Work Plan
•
Language allowing modifications to the Work Plan should specifically require documentation of changes
•
M7 is measuring completion of Work Plan, not prevention of encroachments into the MVCD
•
The phrase “…provided they do not put the transmission system at risk of a vegetation encroachment”
could be better written as “…they do not allow encroachment of vegetation into the MVCD”
Examples describing potential reasons for plan modification should be clarified or eliminated.
•
Decreases in funding not valid.
•
Encroachments due to Major Storms are exempted in Footnote 2. R7 allows modification to Plan due to
major storms but does not allow encroachments associated with plan change.
•
Generally. the examples identified are broad in nature
Some minor comment issues are:
1.
Eliminate requirement or use the first sentence only.
2.
Some concern with lack of agreement of language with other parts of the Standard.
The VM SDT appreciated both the major and minor comment issues identified but decided that the requirement
and measures are appropriate and clear as currently written and did not modify any of the language. The SDT
reviewed the Funding Adjustment example for R7 and feels this is a valid reason for modifying the Annual Plan
keeping in mind that a modification must not place the transmission system at risk of vegetation encroachment
into the MVCD. In addition, as expressed in the Rationale, R7 sets the expectation that the work identified in the
57
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
annual work plan will be completed as planned. Documentation of the work completed (and any necessary
modifications) as written together with the lack of a violation to either Requirement 1 or Requirement 2 is the
overall reliability goal. The metric for the work plan is the percentage of the plan completed. The lack of a violation
of R1 or R2 is the outcome of the ideal work plan. It is the responsibility of the Transmission Owner to manage the
quality of the work plan and its associated modifications to mitigate the risk of a violation of R1 or R2. With
Version 2, an outage is now clearly a violation of R1 and R2 and should not be linked to a failure of the work plan.
The measure for the work plan is the percentage of the completed work as planned and we do not need to be
subjectively trying to evaluate the quality of the Transmission Owner’s work plan with this measure.
Organization
1
GDS Associates
2
MWDSC
(METROPOLITAN
WATER DISTRICT
OF SOUTHERN
CALIFORNIA)
3
Western Area Power
Administration
Yes or No
Question 5 Comment
No
As the list of “examples of reasons for modification” is not all inclusive, it is
unnecessary and could result in confusion regarding compliance when a
scenario other than one listed requires a change. Further, documentation of
changes to the annual plan adds unnecessary administrative burden which is
inconsistent with a performance based standards approach.
Response: Thank you for your response. The SDT feels the list of examples, while not all inclusive, is
helpful to the TO in determining how and when to apply flexibility to its annual plan, when required. It is
important the TO documents modefication to the plan to insure the work not completed during that period is
carried over and completed within a reasonable time frame.
4
Ameren
No
Funding Adjustments (increase or decrease) - need more description to imply
only when planned vegetation work is “over and above”.
58
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
Response: Thank you for your comment. The SDT reviewed the Funding Adjustment example for R7 and
feels this is a valid reason for modefying the Annual Plan keeping in mind that a modefication must not place
the transmission system at risk of vegetation encroachement into the MVCD.
5
MidAmerican Energy
No
MidAmerican supports the additional detail. However R7 should end after
the first sentence. All additional material should be moved to the rationale
box.
Response: Thank you for your comment. The position of the SDT is to have this langiage in the requirement
such to allow for flexibility to the work plan. Keep in mind Rationale language is clarifying documentation and
not enforcable. The SDT feels it is important that the TO have the flexibility to revise its Annual Plan which is
subject to many issues that can influence the completion of work.
6
The United
Illuminating Company
No
R1 and R2 are requirements that no encroachment occurs. R7, as
proposed, requires a VMP to be completed to ensure no encroachment
occurs. The Supplemental Reference for R7 does not describe the
requirement of the annual vegetation work plan to ensure no vegetation
encroachments occur within the MVCD. The Reference states the
requirement is established to diminish the risk of encroachment; which is
very different from ensuring no encroachment. In the Reference for R7 the
word “ensure” is only used to describe that flexibility in the VMP is allowed to
ensure the reliability of the Transmission System.M7 is measuring work plan
completion not the prevention of encroachment. United Illuminating suggests
that R7 be changed to: Each Transmission Owner shall complete the work in
an annual vegetation work plan to manage the prevention of vegetation
encroachments occur within the MVCD. In this way, a violation of R1/R2
does not necessarily mean R7 is violated. The entity does not avoid a
penalty for an encroachment because a violation of R1/R2 occurs for actual
encroachment. If an encroachment occurs the compliance enforcement
authority can review the entities vegetation management plan to determine if
it is compliance with R7/M7.
Response: Thank you for your comments. As expressed in the Rationale, R7 sets the expectation that the
work identified in the annual work plan will be completed as planned. Documentation of the work completed
(and any necessary modifications) as written together with the lack of a violation to either Requirement 1 or
Requirement 2 is the overall reliability goal. The metric for the work plan is the percentage of the plan
completed. The lack of a violation of R1 or R2 is the outcome of the ideal work plan. It is the responsibility of
59
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
the Transmission Owner to manage the quality of the work plan and its associated modifications to mitigate
the risk of a violation of R1 or R2. With Version 2, an outage is now clearly a violation of R1 and R2 and
should not be linked to a failure of the work plan. The measure for the work plan is the percentage of the
completed work as planned and we do not need to be subjectively trying to evaluate the quality of the
Transmission Owner’s work plan with this measure.
7
CenterPoint Energy
No
See response to Q3 above.However, assuming R7 is not revised to exclude
processes and procedures, the new wording is preferred since it is more
specific. Additionally, a new ambiguous phrase is introduced, “provided they
do not put the transmission system at risk of a vegetation encroachment”,
which we recommend to be changed to more specific wording, “provided
they do not allow encroachment of vegetation into the MVCD”.
Response: Thank you for your comments. The SDT felt the language was appropriate.
8
Southern Company
Transmission
No
The first sentence of the Requirement 7 Rationale conflicts with the second
sentence. The R7 Rationale should be reworded as follows:"This
requirement sets the expectation that the work identified in the annual work
plan should be completed as planned. However, an annual vegetation work
plan must allow for work to be modified in response to changing conditions.
These modifications must take into consideration the anticipated growth of
vegetation and all other environmental factors, provided that the changes do
not cause a vegetation encroachment within the MVCD."
Response: Thank you for your comments. The SDT felt the language was appropriate.
9
NERC Staff
No
This is the first instance in which an annual work plan is discussed. It would
appear necessary to first develop an annual work plan component of the
overall vegetation management program. There should also be some
performance review or expectation that the annual plan as implemented
achieved the intended program objectives, or that modifications would be
necessary.
Does R7 require both that a Transmission Owner has an annual vegetation
60
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
work plan AND that it completes the work plan? Detail is required as to what
is expected in the work plan, as there is currently no basis to judge whether
the work plan is adequate or not adequate. And what does a modification
entail? Does this mean reduction of performance, delay in performance, or
complete postponement of performance?
NERC staff is also concerned with the list of examples one might use to
modify an annual plan. Several of these items should not pose any greater
risk to vegetation contact and render the requirement virtually unenforceable.
It provides a wide array of reasons to postpone vegetation management and
may make it a very low priority for an entity:
• “Rescheduling work between growing seasons”: This could be an
honest change (if there are unexpected seasonal changes) or it could
reflect bad initial planning. If there will be occasion for auditors and
investigators to distinguish, there should be guidance on differentiating.
• “Crew or contractor availability”: This could be an honest change (if
there is an unexpected labor dispute or if crews are needed to help a
neighboring utility during an unexpected emergency) or it could reflect
bad initial planning. If there will be occasion for auditors and
investigators to distinguish, there should be guidance on differentiating.
Alternatively, it could be removed from the list as it is within the
exclusive control of the Transmission Owner.
• “Identified unanticipated high priority work”: This could be an honest
change or it could reflect bad initial planning. If there will be occasion for
auditors and investigators to distinguish, there should be guidance on
differentiating. It is also vague and would necessitate a judgment call for
enforcement.
• “Permitting delays”: Annual plans should account for anticipated
permitting schedules and maybe even add a factor for uncertainty. It is a
planning issue for the entity and should not be an acceptable excuse for
not conducting vegetation management.
• “Land ownership changed”: If a landowner has the ability to affect the
reliability of the bulk power system, the landowner should be subject to
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
the reliability standards. A registered entity should be responsible for the
land in its ROW, especially if it has turned control of the land, and the
ability to affect reliability of the BPS, over to another entity or person for
financial gain.
• “Funding adjustments”: NERC staff is not convinced that this is a
legitimate reason for adjusting an annual vegetation work plan.
Economic considerations should not be a reason to delay or modify
vegetation management.
• “Emerging technologies”: It is unclear what this example is intended to
accomplish.
In general, these examples should be bounded in some way to ensure that a
modification due to one of their occurrences does not impart a greater risk of
vegetation contact.
Response: Thank you for your comments. Per the SDT, developing the annual work plan is an understood
requirement in order for the TO to complete the work plan. Thus, a requirement to develop the plan is not
needed. R3 specifies the processes, procedures and/or specifications that are utilized by a TO to prevent an
encroachment of the MVCD. This “Competency Based” requirement sets the core foundation that a TO will
utilize to develop their annual work plan.
As expressed in the Rationale, R7 sets the expectation that the work identified in the annual work plan will be
completed as planned. Documentation of the work completed (and any necessary modifications) as written
together with the lack of a violation to either Requirement 1 or Requirement 2 is the overall reliability goal.
The metric for the work plan is the percentage of the plan completed. The lack of a violation of R1 or R2 is
the outcome of the ideal work plan. It is the responsibility of the Transmission Owner to manage the quality
of the work plan and its associated modifications to mitigate the risk of a violation of R1 or R2. With Version
2, an outage is now clearly a violation of R1 and R2 and should not be linked to a failure of the work plan. The
measure for the work plan is the percentage of the completed work as planned and we do not need to be
subjectively trying to evaluate the quality of the Transmission Owner’s work plan with this measure.
By bounding the flexibility as advocated, there are several variables involved such it makes it impractical to
be able to address the many operational scenerios that a TO may experience. Thus, without being very
prescriptive, the SDT feels that it is best to provide general guidance to what are valid modifications to the
work plan.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
10
Kansas City Power &
Light
Yes or No
Question 5 Comment
No
This requirement is in direct conflict with the “exclusions” as described in
section 4.4. Section 4.4 makes it clear that effects of “major storms” on a
vegetation programs efforts will be allowed as an exclusion toward
compliance with these requirements, yet, R7 does not allow any
encroachment due to modifications to a vegetation plans efforts due the
“Major Storms” (second bullet) or “Weather conditions/Accessibility” (bullet
6). Please explain what is intended here that is different than what was
intended in section 4.4.In addition, this presents some audit difficulties
regarding the notion of detecting a “modified work plan”. Once a work plan is
altered and new objectives are laid out, that becomes the plan and the plans
that were replaced may be discarded since they would be of no value.
Further, what difference does it make to track or monitor any changes to a
work plan provided effective vegetation management is maintained?
Recommend the SDT consider removing the language regarding “work plan
flexibility” as this may suggest and impose an unnecessary compliance
burden on Registered Entities and Auditors.
Response: Thank you for your comments. The SDT views Major Storms in the list of examples differently
than in Footnote 2. The example has more to do with schedules being revised as a result of a major storm
while Footnote 2 refers to issues of sustained outages caused by circumstanses beyond the control of the
Transmission Owner, and excepting resulting violations to the standard.
The SDT feels it is important to track and document changes in the work plan to insure rescheduled work is
completed at some later date. Work plan flexibility through modification to the work plan is critical and must
be recognized so that the Transmission Owner can propertly plan and revise work schedules when
necessary.
11
Xcel Energy
No
What exactly does complete an annual work plan mean? It infers that an
annual work plan must be developed/documented and executed. If this is
the case, then clearly state as such.In general, R6 & R7 go against the grain
of the results based standard concept. R1 already established that the
Transmission Owner cannot have encroachment. R3 requires annual
inspection (essentially establishing the plan). Why replicate in R6 & R7, it
does not seem to serve any useful purpose.
Response: Thank you for your comments. As stated in the Rationale, “This requirement sets the
expectations that the work identified in the annual work plan will be completed as planned.” Because the
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
work plan is recurring in nature, a new work plan must be developed each year to state work planned for that
period. This requirement directly supports Requirement 3 which calls for a documented vegetation
management approach to prevent MVCD encroachments.
12
Allegheny Power
Yes
13
American
Transmission
Company
Yes
14
Arizona Public
Service Company
Yes
15
BGE Forestry
Management
Yes
16
Bonneville Power
Administration
Yes
17
Central Maine Power
Company, Iberdrola
USA
Yes
18
Consolidated Edison
Company of New
York Inc
Yes
19
Consumers Energy
Company
Yes
20
FPL Corporate
Compliance
Yes
21
Dominion
Yes
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
22
Duke Energy
Yes
23
Entergy Services
Yes
24
Exelon
Yes
25
FirstEnergy
Yes
26
Great River Energy
Yes
27
Hydro One
Yes
28
Idaho Power
Yes
29
Idaho Power
Company
Yes
30
ITC Transmission
Yes
31
Manitoba Hydro
Yes
32
Northeast Power
Coordinating Council
Yes
33
Northeast Utilities
Yes
34
Orange and Rockland
Utilities, Inc.
Yes
35
Pepco Holdings, Inc Affiliates
Yes
36
PNM
Yes
Question 5 Comment
65
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
37
PPL Electric Utilities
Yes
38
Progress Energy
Yes
39
South Carolina and
Gas
Yes
40
Tri-State Generation
& Transmission
Yes
41
Western Electricity
Coordinating Council
Yes
Question 5 Comment
annual vegetation management plans must have some flexibility. If the TO
has the authority to create the plan they should have the authority to modify
the plan. The key point is that changes, particularly delays to planned work
would have to be approved. Do not believe “decreases in funding” should be
listed as a valid reason for modification of work plan related to a reliability
standard.From an enforcement viewpoint, there is ambiguity or perceived
ambiguity in “provided they do not put the transmission system at risk of a
vegetation encroachment.” Provided the potential that there may never be a
self-report addressing this violation.
Response: Thank you for your comments. The SDT agrees the plan needs flexibility and the Transmission
Owner has authority for plan oversite. No approval for changes is called for in the requirement, but
documentation is required to note the change.
The SDT reviewed the Funding Adjustment example for R7 and feels this is a valid reason for modifying the
Annual Plan keeping in mind that a modification must not place the transmission system at risk of vegetation
encroachment into the MVCD.
42
Southern California
Edison Company
Yes
SCE agrees with the revisions to R7, but notes the some minor edits to the
text are still needed.
Response: Thank you for your comments. The SDT felt the language was appropriate.
43
MRO’s NERC
Standards Review
Subcommittee (nsrs)
Yes
The NSRS has issue with the word “may” (and its components along with the
associated bulleted points) and recommends that it is removed and placed in
the rational box.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
Response: Thank you for your comments. The SDT believes the requirement as written is needed to insure
flexibility of work plan.
44
BC Hydro
Yes
The requirement as currently worded, seems to assume but does not
explicitly state that a utility must prepare and document an annual vegetation
work plan and document in some manner any modifications to that work
plan as they occur. The work plan change documentation should include any
risks of work deferral and mitigation plans to address those risks if there are
any.
Response: Thank you for your comments. Per the SDT, developing the annual work plan is an understood
requirement in order for the TO to complete the work plan. Thus, a requirement to develop the plan is not
needed. R3 specifies the processes, procedures and/or specifications that are utilized by a TO to prevent an
encroachment of the MVCD. This “Competency Based” requirement sets the core foundation that a TO will
utilize to develop their annual work plan.
The lack of a violation of R1 or R2 is the outcome of the ideal work plan. It is the responsibility of the TO to
manage the quality of the work plan and mitigate any risk to the system associated with modifications to the
work plan.
45
Tampa Electric
Company
Yes
These changes add greater clarity, as well as real world examples, to this
standard.
Response: Thank you for your comments.
67
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
6. In response to comments received that requirement R1/R2 may not adequately protect the
transmission conductors under all conditions of sag and sway, the SDT drafted alternate language for
the industry to provide feedback. The SDT did not opt to incorporate this language into “Draft 4” until
further comment was solicited from industry. Which do you prefer? Please comment on your choice
in the comment box below:
“Alternate R1/R2. Each Transmission Owner shall manage the floor of its Active Transmission Line ROW in
accordance to one of the following at all times:
A) A fixed maximum vegetation height of 15 feet from the ground at the mid-half of the span and 20 feet
in the outside quarters of the span, or,
B) A calculated maximum vegetation height that is the difference between the minimum conductor height
at “max sag” minus MVCD minus cycle growth, or,
C) A calculated minimum vegetation to conductor clearance that is the sum of “max sag” in the span plus
MVCD plus cycle growth, or,
D) A value determined by the Transmission Owner to provide a separation between the conductor and the
vegetation that is comparable to options A, B, or C.
E) Any alternative approach that ensures no encroachment occurs within MVCD, considering the sag and
sway of the conductor throughout its operating range under rated conditions.
F) A value to provide a separation between the conductor and the vegetation that is the sum of MVCD,
and a value that considers the sag and sway of the conductor throughout its operating range under
rated conditions plus 10 feet.”
NOTE: The SDT suggests similar language as found in the posted draft for measures M1/M2 may be appropriate
with this Alternate R1/R2.
Summary Consideration:
Of 45 respondents, there are 4 abstentions (expressed no preference for Draft or Alternate), 16 (two of which
appear to be from the same company) are in agreement (that Alternate Language is preferred), and 25 are in
disagreement (that Alternate is preferable, liking Draft language better).
The major comment issue raised is:
1.
The only real issue raised in the comments by the 41 respondents that had a preference was that of the
style of Requirement language appropriate for an RBS standard. Both groups agreed that either the Draft or
Alternate language addressed the root requirement(s). In fact, respondents in both groups indicated that Option E
68
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
of the Alternate language was in essence the Draft language. (And of those in Alternate group that discussed the 6
options, E was the clear favorite, receiving five (5) mentions with A and C only receiving one (1).)
However, those that preferred the Alternate language cited that written in the form proposed by the
Alternate language, the Requirements R1/R2 would provide much more flexibility and two respondents even cited
that the Alternate allowed Transmission Owners to specify their own clearances.
For those voting for the Draft language (the majority), the most common reason cited was Draft language
was less prescriptive. The second most common reason cited was that the Alternate Language would be confusing.
And a couple commenters in this group opined that the Alternate language appeared to be “fill-in-the-blanks”
language.
The VM SDT consideration for the major comment issue is:
1.
Based on the “vote” the team will retain the Draft language. Also, Option E was cited most often by the
Alternate group as the most desirable of the options and is in fact essentially the Draft language. The SDT
was additionally swayed by the comments about confusion and fill-in-the-blanks as two overriding premises
behind the standards should be clarity and acceptance by FERC.
A minor comment issue is:
1.
Commenters offered several minor wording changes to the Draft language.
The VM SDT consideration for the minor comment issue is:
1.
The team has incorporated some of these minor wording changes and rejected others when the change was
found to introduce other problems.
Organization
1
Yes or No
Question 6 Comment
MWDSC
(METROPOLITAN
WATER
DISTRICT OF
SOUTHERN
CALIFORNIA)
69
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
2
Progress Energy
3
South Carolina
and Gas
4
Arizona Public
Service Company
Yes or No
Question 6 Comment
Neither version is acceptable ANSI-A300 part 7 should be included here.
Having set distances will give federal agencies the ability to minimize a
utilities TVMP.
Response: The SDT thanks you for your comments. The team appreciates your concern about federal agencies and
other landowners’ interpretation of the Requirement to impede vegetation management but is not swayed that the
language currently in the Draft version suffers from a set distance specification as you cited.
5
Bonneville Power
Administration
Alternate version of R1/R2
6
Central Maine
Power Company,
Iberdrola USA
Alternate version of R1/R2
7
PNM
Alternate version of R1/R2
8
GDS Associates
Alternate version of R1/R2
- E) seem more appropriate. The alternate R1/R2 standard requirements
shall reduce the number of possibilities and simplify the criteria towards
the design / operating conditions and additional standards ought to be
considered in concert with current stan
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft.
9
Allegheny Power
Alternate version of R1/R2
Allegheny Power prefers the alternate version.
The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many choices which
70
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
may simplify the application by Transmission Owners but is concerned that a majority of commenters find the
alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has decided to retain the
language in the current Draft.
10
PPL Electric
Utilities
Alternate version of R1/R2
Alternate C provides assurances that growth rates, maintenance cycle,
and max-sag are taken into consideration.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft because the SDT believes it already addresses the provisions
you state, i.e. growth rates, maintenance cycle, etc.
11
Hydro One
Alternate version of R1/R2
Alternate Version E would allow a Transmission Owner to use an
approach consistent with the current version of FAC-003 by defining a
minimum clearance distance and a vegetation management clearance
distance. This approach has met the objectives of FAC-003 since 2006.
Use of version E would change the standard from a prescriptive
approach to a Transmission Owner defined approach. In addition,
Alternate Version E is preferred as it allows for variations based on
differences in conductor heights, topography and other situations where
a set height is not necessarily required in all instances and allows for the
utility to determine the maximum heights of vegetation without
performing detailed calculations of what the maximum heights must be
along the various distances within each conductor span. If the utility is
tasked with managing the vegetation to ensure no encroachments into
the MVCD then it should be up to the individual utility how best to
determine its management strategies that incorporate the determination
of maximum vegetation heights in each section on its system.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft.
12
Northeast Power
Coordinating
Alternate version of R1/R2
Alternate Version E would allow a Transmission Owner to use an
approach consistent with the current version of FAC-003 by defining a
71
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Council
Question 6 Comment
minimum clearance distance and a vegetation management clearance
distance. This approach has met the objectives of FAC-003 since 2006.
Use of version E would change the standard from a prescriptive
approach to a Transmission Owner defined approach. In addition,
Alternate Version E is preferred as it allows for variations based on
differences in conductor heights, topography and other situations where
a set height is not necessarily required in all instances and allows for the
utility to determine the maximum heights of vegetation without
performing detailed calculations of what the maximum heights must be
along the various distances within each conductor span. If the utility is
tasked with managing the vegetation to ensure no encroachments into
the MVCD then it should be up to the individual utility how best to
determine its management strategies that incorporate the determination
of maximum vegetation heights in each section on its system.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft.
13
Idaho Power
Alternate version of R1/R2
Alternative R1/R2 allows the utility to maintain adequate clearances with
their preferred approach.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft.
14
FirstEnergy
Alternate version of R1/R2
Although we agree with the alternate version of R1/R2, we have the
following comments:1. We assume that R1 and R2 will be written similar
to the current proposal with regard to IROL (High VRF) and non-IROL
(Medium VRF) transmission lines, respectively. This should be clear after
changes have been made to the standard before the final ballot.2.
Although the SDT states that it "suggests similar language as found in
the posted draft for measures M1/M2 may be appropriate with this
alternate R1/R2", we are not clear how these measures will be written
and would like to see a draft of the measures so we can review and
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
comment.3. The alternate requirements appear to be "planning" in nature
instead of "real-time"; we assume the intention of the SDT was the latter.
Therefore the requirements should be revised with language that is "realtime" in nature.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft.
15
BGE Forestry
Management
Alternate version of R1/R2
BGE believes R1/R2 should contain language that ensures that
vegetation is manage taking into account sag and sway throughout the
conductors operating range as the alternate language above outlines.
The six options proposed allows the Transmission Owner the flexability
needed to manage the active ROW a varity of ways and at the same
time ensures the reliable operation the Bulk Electric System with respect
to vegetation.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft because the SDT believes it already addresses the provisions you
state, i.e. sag and sway.
16
Idaho Power
Company
Alternate version of R1/R2
I think this gives us more flexibility to maintain our clearances.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft.
17
Northeast Utilities
Alternate version of R1/R2
Option E above is preferred as it allows for variations based on
differences in conductor heights, topography and other situations where
a set height is not necessarily required in all instances and allows for the
utility to determine the maximum heights of vegetation without
73
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
performing detailed calculations of what the maximum heights must be
along the various distances within each conductor span. If the utility is
tasked with managing the vegetation to ensure no encroachments into
the MVCD then it should be up to the individual utility how best to
determine its management strategies that incorporate the determination
of maximum vegetation heights in each section on its system.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft.
18
Consumers
Energy Company
Alternate version of R1/R2
Prefer Alternative A
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft.
19
Kansas City
Power & Light
Alternate version of R1/R2
Prefer Alternative E from the list above. Please clarify the meaning of
sway in Alternative E. Is that wind blowout?
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft. Sway is synonymous with wind blowout in Alternative E. Please
refer to the Technical Reference document for further clarification on this issue.
20
Southern
California Edison
Company
Alternate version of R1/R2
SCE prefers the operational flexibility provided by the alternate version of
R1/R2. We also note that dating back to development of FAC-003-1 and
related comment periods, Transmission Owners have repeatedly stated
that a “one-size-fits-all” TVMP is not viable or reasonable.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
74
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft. The SDT completely agrees with your comment about the ‘onesize-fits-all’ issue. The SDT has struggled with the proper wording that would allow each Transmission Owner the
flexibility necessary to minimize the risk of vegetation outages while adapting to their unique vegetation challenges
in a cost-effective-to-consumers manner. The SDT would encourage you, in future comment periods, to offer
specific wording that will address the deficiencies you identified and what persuaded you to choose the Alternate
version of R1/R2 as the preferred version.
21
Ameren
Draft 4 version of R1/R2
22
Duke Energy
Draft 4 version of R1/R2
23
Exelon
Draft 4 version of R1/R2
24
Great River
Energy
Draft 4 version of R1/R2
25
ITC Transmission
Draft 4 version of R1/R2
26
MidAmerican
Energy
Draft 4 version of R1/R2
27
Pepco Holdings,
Inc - Affiliates
Draft 4 version of R1/R2
28
Tri-State
Generation &
Transmission
Draft 4 version of R1/R2
29
Xcel Energy
Draft 4 version of R1/R2
Any of the alternate versions would amplify or create issues between
land owners and Transmission Owners and are contrary to concepts of
Integrated Vegetation Management, in particular, best management
practices.
Response: The SDT thanks you for your comments. Based on the industry support for the Draft 4 language, the SDT
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
has opted to retain the language in the current draft, in part because of the confusion you cited.
30
American
Transmission
Company
Draft 4 version of R1/R2
ATC feels that Draft 4 Version of R1/R2 is the preferred version. The
Alternate version is too prescriptive and has little flexability.
Response: The SDT thanks you for your comments. Based on the industry support for the Draft 4 language, the SDT
has opted to retain the language in the current draft; in part because of the prescriptive nature of the Alternate
versions that you mentioned as well as it being noted as confusing.
31
CenterPoint
Energy
Draft 4 version of R1/R2
CenterPoint Energy does not believe a performance based requirement
should be this prescriptive. However, if the majority of industry
commenters agree with the SDT’s approach, CenterPoint Energy has
several concerns. The terminology, “operating within Rating and Rated
Electrical Operating Conditions” is sufficiently definitive. There is no
need to be more prescriptive. Alternate R1/R2 (E) is already similar to
the Draft 4 wording. Of the two alternative, we recommend keeping the
Draft 4 wording as is; however, we recommend moving the applicability
of transmission line ratings to the Applicability section of the Standard as
“4.5 Other: The Standard does not apply to any occurrence, nonoccurrence, or other set of circumstances that are beyond the Rating and
Rated Electrical Operating Conditions of the Facilities defined in 4.2.”
These conditions should be applicable to all elements and requirements
of the Standard just as the force majeure statement does.
Response: The SDT thanks you for your comments. Based on the industry support for the Draft 4 language, the SDT
has opted to retain the language in the current draft, in part because of the prescriptive nature you mentioned as
well as it being noted as confusing. The SDT has considered your excellent suggestion about the Applicability
Section. However, after extensive discussion, the SDT opted not to add the language in the Applicability Section as
the NERC framework for Applicability Sections seems to guide against it.
32
Consolidated
Edison Company
of New York Inc
Draft 4 version of R1/R2
Consolidated Edison Company of New York, Inc prefers the Draft 4
version. The wording in the VSLs should be modified for both
Requirements to include the phrase 'manage vegetation'. The phrase
'manage vegetation' requires a utility to take specific action to prevent
encroachments/outages.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
Response: The SDT thanks you for your comments. The SDT has considered your excellent suggestion about the
VSLs and decided to change the Requirements in the manner you describe.
33
Entergy Services
Draft 4 version of R1/R2
Draft 4 is acceptable, but if alternate language is chosen, it should be
similar to option E, keeping the determination simple and with as few
variables for interpretation as necessary.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which could have simplified the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore the team has
decided to retain the language in the current draft.
34
Western
Electricity
Coordinating
Council
Draft 4 version of R1/R2
Draft 4 should be sufficient. If industry believes MVCD is not adequate
then the tables for MVCD should be modified to account for sag and
sway.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which could have simplified the application by Transmission Owners but is concerned that a majority of
commenters find the Alternate language confusing and potentially to be fill-in-the-blanks. Therefore the team has
decided to retain the language in the current draft. The SDT is convinced that the technically defensible MVCD is
adequate but appreciates the helpful suggestion nonetheless.
35
Manitoba Hydro
Draft 4 version of R1/R2
I would suggest adding verbage to the draft 4 version to explicitly include
the sag and sway of the conductor to the concept of "operating within
rating and electrical operating condition”
Response: The SDT thanks you for your comments. Based on the support for the Draft 4 language, the SDT has
opted to retain the language in the current draft, in part because of the prescriptive nature you mentioned as well as
it being noted as confusing. The SDT has considered your thoughtful and helpful suggestion about the explicit
language which could be added to the Requirement to make it stand-alone and not rely on the Technical Reference
document. The SDT, however, decided not to add the suggested verbiage because the team felt that the Rationale
Box addressed this issue and the Requirement, if modified, would become somewhat confusing.
36
MRO’s NERC
Standards Review
Draft 4 version of R1/R2
It is the NSRS’s opinion that that the requirement as currently written in
version 4 is consistent with the intent of a standard; i.e. stating what is
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Subcommittee
(nsrs)
Question 6 Comment
required as opposed to stating how to achieve what is required.
Response: The SDT thanks you for your comments. Based on the support for the Draft 4 language, the SDT has
opted to retain the language in the current draft, in part because of the prescriptive nature of the alternate that you
cited, as well as it being noted as confusing.
37
NERC Staff
Draft 4 version of R1/R2
NERC staff supports the Draft 4 version. The six options listed in the
alternative version of R1/R2 do not seem manageable from a utility
perspective. But while staff prefers the existing language, it continues to
emphasize that fall-ins from outside the ROW can impact the line and
need to be taken into consideration.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offered many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters, including you, find the alternate language confusing and some even cite that it may potentially be fillin-the-blanks. Therefore, the team has decided to retain the language in the current draft. Although the SDT
understands that fall ins from off-ROW trees can negatively impact the lines and a sound TVMP would include a
program to address these potential issues, it is not appropriate that off-ROW trees be included in a NERC Standard.
This is mainly because a utility does not have the rights to remove private trees and the process to acquire rights to
remove these trees is quite arduous and costly.
38
Orange and
Rockland Utilities,
Inc.
Draft 4 version of R1/R2
Orange and Rockland Utilities, Inc prefers the Draft 4 version. The
wording in the VSLs should be modified for both Requirements to include
the phrase 'manage vegetation.' The phrase 'manage vegetation'
requires a utility to take specific action to prevent
encroachments/outages.
Response: The SDT thanks you for your comments. The SDT has considered your excellent suggestion about the
VSLs and decided to change the Requirements in the manner you describe.
39
Tampa Electric
Company
Draft 4 version of R1/R2
Quite frankly, the alternatives listed above, or for that matter any other
vegetation managment options, should be establised by the utility. The
goals in R1 & R2 are very clear. The alternatives listed above will create
a double or triple standard of vegetation clearance for each different
type of Transmission construction.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
Response: The SDT thanks you for your comments. Based on the support for the Draft 4 language, the SDT has
opted to retain the language in the current draft, in part because of the confusion you mentioned.
40
Dominion
Draft 4 version of R1/R2
The alternate language proposed above suggests that methodologies
typically incorporated into processes, procedures, or specifications (as
required by R3) should also be included into performance-based
requirements R1 and R2. The incorporation of this language into R1 and
R2 would change these requirements from performance-based
requirements to hybrid performance/competency-based
requirements.The intent of R1 and R2 is to define a failure to prevent
encroachment into the MVCD. Ensuring that a TO’s processes,
procedures, or specifications demonstrate adequate means of protecting
conductors falls under R3, which incorporates transmission conductor
and vegetation dynamics and interrelationships. Therefore,
methodologies employed to manage the floor of active transmission
ROW should be incorporated into the documentation required by R3 and
proof that vegetation was managed in accordance with processes,
procedures, or specifications to prevent encroachment into the MVCD
will be demonstrated by compliance with R1 and R2.
Response: The SDT thanks you for your comments. Based on the support for the Draft 4 language, the SDT has
opted to retain the language in the current draft, in part because it was less prescriptive and more performancebased as you mentioned.
41
FPL Corporate
Compliance
Draft 4 version of R1/R2
The alternative is a fill in the blanks requirement.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which could have simplified the application by Transmission Owners but is concerned that a majority of
commenters find the Alternate language confusing and, as you cite, potentially to be fill-in-the-blanks.
42
BC Hydro
Draft 4 version of R1/R2
The alternatives above are too prescriptive. A utility should set a
preferred maintenance distance (i.e. clearance 1 in FAC-003-1) as
routine expectation and outline mitigation strategies as required in areas
where clearance 1 distances cannot be met to ensure that MVCD
distances are not encroached upon. Given the various line design
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
standards, it is the utility that must define those clearances and margins
of error based on engineering standards and the types of vegetation and
growth rates present in their operating area.
Response: The SDT thanks you for your comments. Based on the support for the Draft 4 language, the SDT has
opted to retain the language in the current draft, in part because it was less prescriptive as you cited.
43
Western Area
Power
Administration
Draft 4 version of R1/R2
The current language of Draft 4 is the most flexible and offers industry
the best opportunity for executing a cost effective and efficient program.
Response: The SDT thanks you for your comments. The SDT has struggled with wording to try to allow each
Transmission Owner the flexibility necessary to minimize the risk of vegetation outages while adapting to their
unique vegetation challenges in a cost-effective-to-consumers manner. Based on the support for the Draft 4
language, the SDT has opted to retain the language in the current draft, because the SDT believes it achieves the
goal you cited.
44
The United
Illuminating
Company
Draft 4 version of R1/R2
UI prefers the draft language because we believe the intent of R1/R2 is
to capture the actual occurrence of a vegetation related interruption or
encroachment of vegetaion into the MVCD based on actual conditions.
Response: The SDT thanks you for your comments. Based on the support for the Draft 4 language, the SDT has
opted to retain the language in the current draft. As you describe, this language captures the true intent of the
Requirements in the least confusing and prescriptive manner, as confirmed by other comments received.
45
Southern
Company
Transmission
Draft 4 version of R1/R2
We feel the alternative language is too confusing. Does a utility choose
one option from the list and expect it to cover all situations, or can the
utility pick one option from the list and apply that option to one span, and
then another option for the next span. The proposed alternate verbiage
makes no distinction as to when options can or cannot be utilized. The
language in Draft 4 seems to cover the various scenarios a utility will
face in its vegetation management program while giving the utility the
flexibility necessary to address these situations in an appropriate
manner.
Response: The SDT thanks you for your comments. Based on the support for the Draft 4 language, the SDT has
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
opted to retain the language in the current draft, in part because of the confusion you cited.
81
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
7. The drafting team and NERC staff disagree on an appropriate set of VSLs for Requirements R1 and R2
and the Standards Committee has directed that both sets of VSLs be posted for stakeholder
comments. Which set of proposed VSLs best supports NERC’s VSL Criteria?
Summary Consideration:
Of 45 respondents, 6 chose neither set of VSLs, 8 disagreed with the SDT, and 31 agreed with the SDT.
Among those who disagreed with the SDT the major comment issues raised are:
1.
VSLs are too low and they do not seem to differentiate between various levels of compliance. Commenter is
concerned that the difference between an encroachment that leads to an outage and one that does not is
based on nothing but luck.
2.
The NERC staff set requires a higher degree of accountability.
The VM SDT considerations for the major comment issues are:
1.
The VM SDT proposed a set of four VSLs to reflect the wide range of non-compliances to these
requirements. The NERC staff on the other hand view the outcomes as narrow.
The comment that SDT VSLs are “too low” lacks context. The commenter does not offer a frame of reference
in rendering its opinion of “too low”.
The comment about luck is without basis. The SDT asserts that vegetation related outages are directly
related to the encroachment mechanism, i.e., how vegetation contacts conductors.
The differing perspectives do not appear to be reconcilable. The VM SDT believes its VSL assignments follow
the NERC VSL Guidelines and are technically valid.
2.
The VM SDT believes the VSLs are precisely set to reflect the degree of accountability that best matches the
level of non-compliance. Grow-in’s are classified in the highest level of violation severity precisely because
it is indicative of the lowest quality of performance and therefore the entity must be held to the highest
degree of accountability in that case.
Some minor comment issues are:
1.
Criteria will be probably best represented by a mix of the two VSLs.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
2.
Neither set is correct.
The VM SDT considerations for the minor comment issues are:
1.
The VM SDT proposed a set of four VSLs to reflect the wide range of non-compliances to these
requirements. The NERC staff on the other hand view the outcomes as very narrow. The differing
perspectives do not appear to be reconcilable through a hybrid approach as you suggested.
2.
The VM SDT believes its VSL assignments follow the NERC VSL Guidelines and are technically valid.
Organization
1
MWDSC
(METROPOLITAN
WATER
DISTRICT OF
SOUTHERN
CALIFORNIA)
2
Progress Energy
3
Western
Electricity
Coordinating
Council
4
GDS Associates
Yes or No
Question 7 Comment
Criteria will be probably best represented by a mix of the two VSLs
as follows:- Keep the Lower and Moderate VSLs from SDT with both
absent Sustained Outage. Add the fall-in as specific encroachment to
the Lower VSL and grow-in as specific encroachment to the
Moderate VSL- Keep the High / Severe VSLs from NERC
Response: Thank you for your comment. The VM SDT proposed a set of four VSLs to reflect the wide range of noncompliances to these requirements. The NERC staff on the other hand view the outcomes as very narrow. The
83
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
differing perspectives do not appear to be reconcilable through a hybrid approach as you suggested.
5
Pepco Holdings,
Inc - Affiliates
Neither set is correct. The SDT proposed VSLs do not identify
encroachment into the MVCD of a line not in an IROL or Major
WECC transfer path, and the NERC Staff proposed VSLs do not do
not identify encroachment into the MVCD of a line that is in an IROL
or Major WECC transfer path
Response: Thank you for your comment. Measures M1 & M2 along with The Rationale boxes for R1 & R2 can be used
to understand what is meant by the MVCD. The Rational Box States:
“The MVCD is a calculated minimum distance stated in feet (meters) to prevent spark-over between conductors and
vegetation, for various altitudes and operating voltages. The distances in Table 2 were derived using a proven
transmission design method.”
6
CenterPoint
Energy
Neither. However, we recommend that High or Severe violations be
based only on Sustained Outages experienced and the reliability
importance of the transmission line. Any process or procedure based
requirement, if kept within the Standard, should have a Lower or
Moderate designation based on the utilities intent or capability to
comply with the Requirement.
Response: Thank you for your comment. The VM SDT proposed a set of four VSLs to reflect the wide range of noncompliances to these requirements. The NERC staff on the other hand view the outcomes as very narrow. The
differing perspectives do not appear to be reconcilable. Your suggestion is appreciated, however the VM SDT
believes its VSL assignments follow the NERC VSL Guidelines and are technically valid.
7
Consumers
Energy Company
VSLs proposed by NERC staff
8
Idaho Power
Company
VSLs proposed by NERC staff
9
FPL Corporate
Compliance
VSLs proposed by NERC staff
Again the drafting team is trying to control the terms of a requirement
by using the compliance elements. FPL agrees there is a direct link
between vegetation growing in to conductors from below has a direct
correlation to cascading events and fall-in and blow-in outages are no
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
more incidental than a cross arm failure to a cascading event. These
components should be handled in the requirements and not in the
compliance element.
Response: Thank you for your comment. The VM SDT proposed a set of four VSLs to reflect the wide range of noncompliances to these requirements. The NERC staff on the other hand view the outcomes as very narrow. The
differing perspectives do not appear to be reconcilable. The VM SDT believes its VSL assignments follow the NERC
VSL Guidelines and are technically valid.
10
Dominion
VSLs proposed by NERC staff
As all parts of R1/R2 seem to contribute equally to the intent of the
requirement - shall manage vegetation to prevent encroachment that
could result in a Sustained Outage - NERC’s proposed VSLs best
address noncompliance with the requirements.
Response: Thank you for your comment. The VM SDT proposed a set of four VSLs to reflect the wide range of noncompliances to these requirements. The NERC staff on the other hand view the outcomes as very narrow. The
differing perspectives do not appear to be reconcilable. The VM SDT believes its VSL assignments follow the NERC
VSL Guidelines and are technically valid.
11
NERC Staff
VSLs proposed by NERC staff
NERC staff supports the VSLs proposed by NERC staff. The SDT’s
VSLs are too low, and they do not seem to differentiate between
various levels of compliance. Still, staff is concerned that the
difference between an encroachment that leads to an outage and
one that does not is based on nothing but luck.
Response: Thank you for your comment. The VM SDT proposed a set of four VSLs to reflect the wide range of noncompliances to these requirements. The NERC staff on the other hand view the outcomes as very narrow.
The comment that SDT VSLs are “too low” lacks context. The commenter does not offer a frame of reference in
rendering its opinion of “too low”.
The comment about luck is without basis. The MVCD distances are conservative and it is quite possible to be well
within the MVCD and not have a flashover or an outage. This is based on physics, not “luck”. Prudent inspection
frequencies and a good imminent threat notification process are 2 things that could prevent encroachments from
becoming an outage. Stating that it is only dependent on luck does not give proper credit to prudent operations.
The SDT has revised R1 and R2 to clarify that the level of maintenance is the primary focus of this requirement that
must be attained to be compliant. The VM SDT feels these changes will ensure congruence between the requirements
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
and the VSL.
12
Arizona Public
Service Company
VSLs proposed by NERC staff
Requires a higher degree of accountability as it should be.
Response: Thank you for your comment. The VM SDT proposed a set of four VSLs to reflect the wide range of noncompliances to these requirements. The VM SDT believes the VSLs are precisely set to reflect the degree of
accountability that best matches the level of non-compliance. A grow-in is classified in the highest level of violation
severity precisely because it is indicative of the lowest quality of performance. Therefore, the entity must be held to
the highest degree of accountability for any maintenance failure that leads to a grow-in. The VM SDT believes its VSL
assignments follow the NERC VSL Guidelines and are technically valid.
13
Idaho Power
VSLs proposed by NERC staff
Seems like there should be a lesser severity level for violations for
R3-R7.
Response: Thank you for your comment. This question asks for feedback on the VSLs assigned to R1 and R2.
14
The United
Illuminating
Company
VSLs proposed by NERC staff
United Illuminating agrees with NERC Staff that the Requirement is
to prevent encroachment of any kind. Differentiating between fall-in
and grow-in is of no consequence to the intent of the requirement.
Response: Thank you for your comment. Please refer to the SDT response to NERC on this question.
15
Allegheny Power
VSLs proposed by the VM SDT
16
Ameren
VSLs proposed by the VM SDT
17
BGE Forestry
Management
VSLs proposed by the VM SDT
18
Bonneville Power
Administration
VSLs proposed by the VM SDT
19
Duke Energy
VSLs proposed by the VM SDT
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
20
Exelon
VSLs proposed by the VM SDT
21
ITC Transmission
VSLs proposed by the VM SDT
22
Manitoba Hydro
VSLs proposed by the VM SDT
23
MidAmerican
Energy
VSLs proposed by the VM SDT
24
MRO’s NERC
Standards Review
Subcommittee
(nsrs)
VSLs proposed by the VM SDT
25
Northeast Utilities
VSLs proposed by the VM SDT
26
PPL Electric
Utilities
VSLs proposed by the VM SDT
27
South Carolina
and Gas
VSLs proposed by the VM SDT
28
Tri-State
Generation &
Transmission
VSLs proposed by the VM SDT
29
Xcel Energy
VSLs proposed by the VM SDT
30
Central Maine
Power Company,
Iberdrola USA
VSLs proposed by the VM SDT
Question 7 Comment
Agrees with SDT that violation risk factors must be ranked in
accordance with impact on the bulk delivery system.
Response: Thank you for your comment.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
31
Organization
Yes or No
Question 7 Comment
Kansas City
Power & Light
VSLs proposed by the VM SDT
Although the Drafting Team is favored here, it makes little sense in
the NERC Staff VSL to have an encroachment with no sustained
outage as a HIGH VSL. No compromise of the real-time reliability of
the bulk electric system occurred. How could that be a HIGH? If it is
determined to use the VSLs proposed by NERC Staff, it is
recommended to change the HIGH VSL to LOWER.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
32
American
Transmission
Company
VSLs proposed by the VM SDT
ATC believes the VSLs proposed by the VM SDT best supports the
NERC’s VSL Criteria. The NERC Staff VSLs do not allow for Lower
or Moderate VSLs which recognizes significant value as nearly
meeting the intent of the requirement. Furthermore, it does not allow
for encroachment where absent a sustained outage. Every
encroachment in real time would not go directly to a “High” VSL
where performance has limited value.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
33
FirstEnergy
VSLs proposed by the VM SDT
FE supports the VSL proposed by the SDT. We believe these have
been developed in accordance with the FERC approved VSL
guidelines and represent the appropriate violation levels for situations
of varying probabilities. History has proven the grow-ins are the
biggest cause of vegetation contact issues, and fall-ins and blowing
together vegetation are very hard to predict and control and should
be at lower violation levels. Although we believe that an
encroachment into the MVCD that causes no system disturbance
should not be penalized if an entity takes immediate action to restore
the minimum clearance, the assignment of a Lower VSL is
appropriate. We believe that the NERC staff opinion that this situation
warrants a High VSL does not demonstrate thorough rationalization
because it fails to consider the consequences that would place a
severe monetary penalty on an entity for a situation that did not
cause a fault, outage, or cascade of the BES.Furthermore, it is clear
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
from the bullet points under R1 and R2 of the proposed standard
language that the SDT intended that an encroachment with a
sustained outage is different than and encroachment without a
sustained outage otherwise they would not have specified the
bulleted situations in detail. Had the SDT intended for there to be
only two violation severity levels they would have only specified two
bullet items: an encroachment with a sustained outage and an
encroachment without a sustained outage. The requirements are the
only tools the drafting team has to specify its intent in this area and
the approach they used is reasonable to provide these levels of
differentiation.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
34
Great River
Energy
VSLs proposed by the VM SDT
GRE prefers the Drafting Team’s VSLs over the VSLs written by the
NERC staff. The VSLs that were written by the SDT appear to be
clearer and less subjective as opposed to the VSLs that were written
by NERC staff. The VSLs written by the NERC staff came across as
being less clear and more subjective.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
35
Southern
California Edison
Company
VSLs proposed by the VM SDT
SCE agrees with the SDT's rationale and proposals for VSL Criteria.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
36
Tampa Electric
Company
VSLs proposed by the VM SDT
Tampa Electric agrees with the SDT statement ... “For example, not
all encroachments lead to Sustained Outages.” As such, we agree, a
lower level of VSL is appropriate. Tampa Electric also agrees with
this statement “ Moreover, there is an operational differentiation
between a fall-in, blow-together or grow-in event. “Recommend the
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
team examine the analytical rational for the following statements so
as to better explain and clarify this issue to NERC. “A fall-in has
never been known to cause a cascading outage. Therefore the team
feels that a Lower VSL is appropriate. A blowing-together-caused
fault is somewhat more egregious than a fall-in, as it has the potential
for re-occurring and is therefore assigned a Higher VSL.”
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
37
PNM
VSLs proposed by the VM SDT
The expectation is for perfection or zero encroachments at all times.
It would be cost prohibitive to maintain the system under those rules.
PNM recommends the VM SDT VSL’s.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
38
BC Hydro
VSLs proposed by the VM SDT
The NERC staff recommendation is too restrictive and does not seem
realistic in an operational sense. We do not agree that the standard
should apply to outages from vegetation falling into the conductor
from within the active transmission right of way. This normally would
not occur except during storm events that would be excluded from
this standard. It is operationally difficult to know precisely where the
edge of the right of way is in all situations and under all conditions.
Further, in clearing some sections to this degree, the utility could end
up destabilizing what is currently a stable, windfirm edge and pose
higher security risks to the transmission system from destabilizing the
vegetation through excessive clearing. So this gets down to
semantics of how a utility might define their active right of way
corridor relative to the legal statutory right of way edge. The risk of
fall into outages needs to be managed but as currently defined this is
too absolute a requirement. Fall-into outage risks need to be
mitigated but they have not been a key element of any cascading
failure and are hard to prevent. Even if a right of way were cleared
sufficiently wide to avoid a fall-into outage, there is always a risk of
branches being blown into the conductors from sailing during higher
winds (e.g. Douglas-fir branches have excellent airborne gliding
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
abilities). The greatest risk is from grow-into outages or from
conductors and vegetation being blown into one another within the
active right of way. Therefore, we prefer the VSLs set by the VM
standard development team.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
39
Consolidated
Edison Company
of New York Inc
VSLs proposed by the VM SDT
The wording in the VM STD VSLs should be modified to include
whether or not the TO managed any vegetation on that particular
line. A more severe VSL should be assigned to any encroachment or
sustained outage that was caused as a result of a TO not performing
any vegetation management activities on that line. For example, if
vegetation management activities were completed on 80% or 90% of
the line and additional work was in progress on the remainder of the
line but an encroachement or sustained outage occurred on the
spans that were scheduled to be done as part of the annual plan, the
TO should be held accountable for this but at a lower severity level.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
40
Hydro One
VSLs proposed by the VM SDT
The wording in the VM STD VSLs should be modified to include
whether or not the TO managed any vegetation on that particular
line. A more severe VSL should be assigned to any encroachment or
sustained outage that was caused as a result of a TO not performing
any vegetation management activities on that line. For example, if
vegetation management activities were completed on 80% or 90% of
the line and additional work was in progress on the remainder of the
line, but an encroachment or sustained outage occurred on the spans
that were scheduled to be done as part of the annual plan, the TO
should be held accountable for this but at a lower severity level.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
41
Northeast Power
Coordinating
Council
Yes or No
Question 7 Comment
VSLs proposed by the VM SDT
The wording in the VM STD VSLs should be modified to include
whether or not the TO managed any vegetation on that particular
line. A more severe VSL should be assigned to any encroachment or
sustained outage that was caused as a result of a TO not performing
any vegetation management activities on that line. For example, if
vegetation management activities were completed on 80% or 90% of
the line and additional work was in progress on the remainder of the
line, but an encroachment or sustained outage occurred on the spans
that were scheduled to be done as part of the annual plan, the TO
should be held accountable for this but at a lower severity level.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
42
Orange and
Rockland Utilities,
Inc.
VSLs proposed by the VM SDT
The wording in the VM STD VSLs should be modified to include
whether or not the TO managed any vegetation on that particular
line. A more severe VSL should be assigned to any encroachment or
sustained outage that was caused as a result of a TO not performing
any vegetation management activities on that line. For example, if
vegetation management activities were completed on 80% or 90% of
the line and additional work was in progress on the remainder of the
line but an encroachement or sustained outage occurred on the
spans that were scheduled to be done as part of the annual plan, the
TO should be held accountable for this but at a lower severity level.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
43
Entergy Services
VSLs proposed by the VM SDT
This gives the option to activate and follow the Imminent Threat
Process if a breach of the MVCD is located and reported for isolated
events absent a sustained outage. It gives the TO the opportunity to
mitigate the issue when it is identified and corrected prior to
experiencing an outage..
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
44
Organization
Yes or No
Western Area
Power
Administration
VSLs proposed by the VM SDT
Question 7 Comment
Unlike a “grow-in”, a “fall-in” or “blow-in” has never caused or
contributed to a cascading outage. Further, the “zero tolerance”
approach of this standard remains impractical and unreasonable.
The gradated indicators of program performance associated with a
“fall-in”, “blow-in” and “grow-in” offer some measure of
reasonableness to the requirement.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
45
Southern
Company
Transmission
VSLs proposed by the VM SDT
We support the SDT version of the VSLs. The version proposed by
staff does not recognize the objective of FAC-003-2 which clearly
states, “To improve the reliability of the electric Transmission system
by preventing those outages that could lead to Cascading.” If a fall-in
occurs in an afternoon thunder storm and investigation reveals the
tree was on the right-of-way by one or two feet, staffs VSLs would
treat this outage with the same severity as an outage where a fully
loaded line in a heat wave sagged into unmaintained brush growing
directly beneath the conductor. The first case would rarely, if ever,
lead to cascading. The second case could easily lead to cascading.
Staff’s VSLs seem to indicate a desire to “gold plate’ the system to
insure 100% reliability, which will never be achieved absent of
unlimited resources and with total disregard to cost.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
8. Is there anything that you have not addressed above regarding the draft FAC-003-2 Transmission
Vegetation Management standard or the Technical Reference Document? If yes, please provide what
you believe should be changed, added or deleted and the rationale for your proposal.
Summary Consideration:
Of the 45 respondents, 29 provided a comment. In general, there were no common themes and as such each
comment was responded to individually. Of some note, two comments were especially lengthy and their wellconsidered responses are found below.
Organization
Yes or No
1
Great River Energy
2
Allegheny Power
No
3
Central Maine Power
Company, Iberdrola
USA
No
4
Consumers Energy
Company
No
5
Duke Energy
No
6
Exelon
No
7
Manitoba Hydro
No
8
Northeast Utilities
No
9
Pepco Holdings, Inc Affiliates
No
10
PNM
No
Question 8 Comment
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
11
PPL Electric Utilities
No
12
South Carolina and
Gas
No
13
Tri-State Generation
& Transmission
No
14
Western Area Power
Administration
No
15
Western Electricity
Coordinating Council
No
16
Tampa Electric
Company
No
No additional comments
17
GDS Associates
Yes
- Effective Dates. Clarify effective dates in paragraphs 2 and 3. This should
only be applicable to Canada as Standard are not mandatory and
enforceable in the US unless further approved by FERC.- Exceptions.
Regional Differences must be approved just li
Response: The SDT thanks you for your response. NERC staff will review the effective date section and
modify as necessary.
18
Progress Energy
Yes
1) On p. 3 of the redline, the table of Effective Dates is struck out, but the key
(listed as 1, 2, 3 below the table: “1. First calendar day...”) remains but now
the numbers 1, 2, and 3 no longer refer to the table of Effective Dates as the
table has been struck. 2) The first paragraph under “Exceptions” could be
reworded to be clearer. As currently proposed, it states lines below 200kV
become subject to the standard 12 months after the lines are designated as
being subject to the standard, which is somewhat circular. We propose
instead:”A line operated below 200kV becomes subject to this standard 12
months after the date the Planning Coordinator or WECC initially designates
the line as an element of an IROL or as a Major WECC transfer path.”3)
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
Applicability Section 4.2.4 says the standard does not apply to Facilities
located in the fenced area of a switchyard. However, p. 8 in Section 5
Background says the standard does not apply to underground or submarine
lines or line sections inside a station boundary. Two things should be
addressed to make these consistent: “Facilities” is a NERC-defined term that
includes more than just lines, and includes lines, generators, compensators,
transformers, etc. Also, is the “station boundary” always defined by the
fenced area? Any potential conflict due to this inconsistency should be
resolved.4) In the redline of Draft 4, in R5 and M5, the word “interim” is struck
through. However, the Rationale box says “....the intent is for the
Transmission Owner to put interim measures in place...” The use of “interim”
should be consistent between R5, M5 and the Rationale box.5) R6 requires
the TO to perform Vegetation Inspections “at least once per calendar year”.
There could potentially be future interpretation requests that question
whether “once per calendar year” means performance sometime during each
year (i.e. 2010, 2011, etc.), or whether no more than 365 calendar days can
elapse between inspections. The first interpretation could allow up to almost
2 years to elapse between inspections even when doing it “once per calendar
year”. This should be clarified.
Response: The SDT thanks you for your response. NERC staff will review the effective date section and
modify as necessary. Thank you for the wording, but overall industry consensus does not dictate a verbiage
change.
Regarding station boundaries and underground lines, overall industry consensus is that line-based
vegetation programs do not apply inside the station boundary. The SDT believes that “fence” is the best
overall term for a station boundary.
As to the use of “interim”, the Rationale intends to provide clarifying text and there is no imperative that its
language should be identical to the requirement verbiage. The SDT believes that the Rationale language
properly conveys the intent.
Regarding the inspection frequency, the SDT added an 18 month clause.
19
CenterPoint Energy
Yes
1. CenterPoint Energy believes the proposed FAC-003-2 is not a performancebased standard, despite being labeled as such, because it remains too
focused on processes and procedures. CenterPoint Energy fails to see
much difference in the approach from the current Standard.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
CenterPoint Energy believes a performance based requirement would
provide performance criteria that an entity would be measured against. An
example of a performance based requirement would be the following:
R1. “Each Transmission Owner shall manage vegetation to prevent
encroachment that results in no more than one (1) Sustained Outage
per XXX circuit miles of applicable lines within any twelve (12) month
period.”
M1. Each Transmission Owner has evidence that it had in no more than
one (1) Sustained Outage per XXX circuit miles of applicable lines within
any twelve (12) month period. Examples of acceptable forms of
evidence may include dated reports of vegetation-related Sustained
Outages or dated attestations as to no vegetation-related Sustained
Outages have occurred.
However, if the majority of industry commenters agree with the SDT’s
approach, CenterPoint Energy has the following additional concerns:
2. The phrases “active transmission line ROW” and “Active Transmission Line
ROW” are no longer considered defined terms and should be deleted from
the Standard along with footnote 2, the Compliance Section for Periodic
Data Submittal as well as the Guidelines and Technical Basis. As found
throughout the Standard, the phrase should be replaced with the common
terms utilized in the Guidelines and Technical Basis section, “Transmission
Owner’s transmission ROW as defined by easement, fee simple, or other
legal rights”.
3. In the Background section fall-ins are characterized as “statistically
intermittent” and “these types of events are highly unlikely to cause largescale grid failures”. We agree and therefore recommend that fall-ins be
excluded from the Requirements R1, R2, and Periodic Data Submittal of
outages.
4. R4 should be deleted. R4 is related to processes and procedures and
should be combined into R3. The result of not following the notification
process or procedure is that a Sustained Outage may occur that would be
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
captured by M1 and M2. The process and procedure would be measured
by M3.
5. R5 and M5 contain the ambiguous phrase, “where a transmission line is put
at risk due to the constraint”. This phrase should be replaced with the more
specific terminology in R1 and R2 as, “where a transmission line cannot
perform within its Rating and Rated Electrical Operating Conditions due to
the constraint” or as in R3 as “where a transmission line will be subjected to
an encroachment into the MVCD due to the constraint”.
6. For R6, the detailed rationale and studies used for the determination of the
required one year inspection cycle should be included in the Guidelines and
Technical Basis. The explanation provided in the Rationale that it is “based
upon average growth rates across North America and on common utility
practice” are unfounded and arbitrary without a specific reference to a North
American study.
7. R7 contains the ambiguous phrase, “provided they do not put the
transmission system at risk of a vegetation encroachment”. This phrase
should be replaced with the more specific terminology in the Rationale for
R7 and Requirement R3 as “provided they do not allow encroachment of
vegetation into the MVCD.”
8. Just as the force majeure statement was moved to the Applicability section
of the Standard, the exception for applicability beyond the Rating and Rated
Electrical Operating Conditions should be included in the Applicability
section as well. Currently, it is only included in R1, R2, and R3. It should be
made clear that the other Requirements and Measurements ARE NOT
applicable in situations beyond the Rating and Rated Electrical Operating
Conditions. This is already discussed in the Guidelines and Technical Basis
but not evident within the Standard.
9. The Periodic Data Submittal should be clarified to as to the specific
conditions under which Sustained Outages are reported. The Applicability
section includes the force majeure; however, other exclusions are not so
evident. We recommend the wording be changed to include all applicable
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
exclusions for added clarity.
We recommend the following wording: “The Transmission Owner will submit
a quarterly report to its Regional Entity, or Regional Entity’s designee,
identifying the Sustained Outages caused by vegetation, as defined in the
categories below, of transmission lines operating within Rating and Rated
Operating Conditions as determined by the Transmission Owner, exclusive
of the force majeure conditions in Section 4.4, that include, as a minimum,
the following.”
Also, the within the Categories listed, the phrases “active transmission line
ROW” should be deleted and replaced with “Transmission Owner’s
transmission ROW as defined by easement, fee simple, or other legal
rights”. This places the determination of the width of the ROW for
determination of fall-in violations clearly on the Transmission Owner and the
within the limits of its legal rights to control the vegetation that has fallen into
the line under R1 and R2 causing the submittal of a reportable sustained
outage.
10. The Guidelines and Technical Basis and the Technical Reference with the
Gallet Equation should be combined into one document as a supplement to
the Standard to avoid duplication in wording and misinterpretation of
context.
11. We agree that the Rationale test boxes should be deleted from the Standard
and applicable explanatory text be included within the Guidelines and
Technical Basis.
12. The Guidelines and Technical Basis should include the background and
basis for 4.2.4 that excludes the Standard from applying to fenced
substations.
13. The Guidelines and Technical Basis should contain more specific examples
of violations of the Requirements and highlight specific exceptions related to
vegetation related outages, especially fall-ins and force majeure exclusions.
14. The language in R6 refers to inspecting “transmission lines” and Table 1 for
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
R6 refers to inspecting “ROW”. Both areas should use consistent
terminology.
15. In the Guidelines and Technical Basis section for R6, the reference to the
VSL calculation units and the example units should be consistent-the
example should use “circuit miles”, not just “miles”.
16. In general, the proposed FAC-003-2 has gone FAR beyond what was
contemplated by the Commission in FERC Order 693 and equates to a total
re-writing of the Standard for no apparent reason. The Commission's
determination dealt with the following areas:
(1) applicability;
(2) inspection cycles; and
(3) minimum clearances on National Forest Service lands.
For instance in Paragraph 729, the Commission states, “As proposed in the
NOPR, the Commission approves Reliability Standard FAC-003-1 with no
proposed modification on the issue of clearances. The Commission
reaffirms its interpretation that FAC-003-1 requires sufficient clearances to
prevent outages due to vegetation management practices under all
applicable conditions....” Rewriting the minimum clearances introduced a
new set of confusing definitions, and further burdens the Transmission
Owners with new documentation requirements with little if any benefit when
compared to the Clearance 2 concept in the existing Standard.
A preferred approach should be to incorporate the following few items into
the existing Standard FAC-003-1:
(1) the RC versus the RRO;
(2) the designation of a specific inspection frequency;
(3) the Gallet equation; and
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
(4) the applicability to National Forest Service lands.
Response:
1) The SDT thanks you for your responses. The standard is intended to be a Results-based standard and
includes requirements that are risk-based, competency-based and performance-based. The SDT and
NERC staff feels that it represents a significant departure from previous versions. The SDT has
considered “per-mile”-based metrics, but believes that FERC will not approve such a metric due to
statutory constraints and its stated criteria for approval of a standard.
2) Based on your comment and others, the SDT has revised the definition of ROW in the NERC Glossary
and removed Table 3.
3) While the SDT agrees that fall-ins are statistically intermittent, the fall-ins from inside the ROW are under
the control of the TO and represent an erosion of reliability.
4) The SDT agrees that there is some logic in your proposal, but the SDT feels that all TOs should have a
procedure that results in a defense-in-depth strategy as is in the current draft.
5) R5 applies in the longer-term Operations Planning time horizon, whereas R1 and R2 apply in real time.
On the other hand, R3 is a competency-type of requirement that applies in the Long-Term Planning Time
Horizon.
6) The SDT posed the question of inspection frequency to the overall industry in an earlier posting and
received general consensus that a one-year interval would be appropriate but did add an 18 month
clause.
7) R7 addresses shorter-term risks, whereas the language in R3 is about the prevention of encroachments
in the wider long-term horizon.
8) The SDT has considered your suggestion about the applicability section; however, after extensive
consideration, the SDT opted not to add the language you suggested since the NERC framework for the
Applicability section guides against it.
9) Thank you. The SDT agrees and hereby adds “. . . except as excluded in Footnote 2” before “that
includes.” Regarding your suggestion on active TLROW, the SDT changed the definition of ROW in the
NERC Glossary.
10) The issue of combining these documents will be addressed by NERC as the results-based standard-
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
making procedural document is finalized.
11) The final resolution of this issue will be addressed by NERC as the results-based standard-making
procedural document is finalized.
12) The SDT believes that industry generally supports the exclusion of substations from applicability of the
standard, and does not believe that every clause or portion of the Standard needs an explanation in the
Guidelines and Technical Basis.
13) The team does not feel that extensive examples, especially of violations, have a place in the Standard.
14) You have pointed out a conflict in nomenclature between two portions of the standard. The team will
resolve the conflict.
15) As mentioned in both M6 and the VSL table for R6, the TO may choose its unit of measure.
16) The SDT considered the SAR and FERC Order 693 directives together with the imperative that reliability
not suffer with the revised standard, and feels that it has improved the Standard accordingly.
20
Kansas City Power &
Light
Yes
1. Part R4.3, “Enforcement, under Section 4, “Applicability”, is confusing as
to why it is needed. What is the intended purpose of this part? It is clear that
each Requirement, Measure, VRF and VSL when adopted by the NERC
BOT and FERC become mandatory and enforceable on the declared
effective date(s). There is no need for Part R4.3 to reinforce the compliance
enforcement dictated by the established NERC Rules of Procedure.2.
Requirement R4: The requirement is clear to notify the appropriate control
center regarding conditions that might cause a fault on a transmission facility.
The requirement should be clear, this for the Transmission Owners
applicable lines and recommend the SDT modify the language in R4 to that
end. In addition, there is no action other than notification in regards to this
operating condition. Highly recommend the SDT consider adding language
to take “immediate actions” to remedy the vegetation condition and remove
the threat.3. Requirements R5 & R7 are not clear in that they are for the
Transmission Owners applicable lines. This has been a common theme
throughout this Standard and by the omission of this language, it is not clear
that the intended scope of the requirements do not go beyond the applicable
lines.
Response:
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
1. Thank you for your comment. NERC staff will address this concern.
2. The SDT feels that the applicability of lines is sufficiently clear in R4. However, it is not appropriate for
this Standard to specify any particular action for the TOP to take; this is the realm of TOP-006.
3. The SDT feels that the applicability of lines is sufficiently clear in R5 and R6.
21
American
Transmission
Company
Yes
1.) Rationale boxes associated with R1, R2 and R3 within the standard
include reference Tables and Figures in the “Guidelines and Technical Basis”
without specifying where they are located. ATC recommends inserting this
information as applicable.2.) ATC raises a previous draft concern on
including Rationale Boxes plus Guidelines and Technical Basis as part of the
NERC Reliability Standard. ATC recommends that the SDT either remove
these sections or make them separate from the formal standard to eliminate
any risk that these may be construed as requirements. An alternative
method is to very clearly identify which parts of the standard are subject to
compliance and considered mandatory and which are not considered
requirements and are only for guidance in meeting the requirements. 3.)
ATC believes the Measurements are well written and provide guidance on
acceptable compliance evidence related to the requirement.4.) Measurement
M2 related to R2 states that outages related to encroachments have records
confirming no Real-Time observations of any MVCD encroachments. ATC
feels this would be hard to prove as a negative. It could require one to show
every single patrol or inspection has documentation stating no real time
encroachments were observed.5.) Editorial Comment on Draft SDT VSLs for
R2: To clarify the statements made for the Moderate, High and Severe
VSLs. please add the verbiage, “into the MVCD” after “The TO had an
encroachment.......”
Response:
1) The formatting of these Rationale boxes is not set and will be addressed by NERC as the results-based
standard-making procedural document is finalized.
2) This issue will be addressed by NERC as the results-based standard-making procedural document is
finalized.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
3) Thank you for your comments.
4) As stated in the Measure, an attestation serves as adequate evidence.
5) Thank you for noticing this oversight. It will be corrected.
22
MRO’s NERC
Standards Review
Subcommittee (nsrs)
Yes
1.) The NSRS notices that a previous draft concern on including Rationale
Boxes plus Guidelines and Technical Basis as part of the NERC Reliability
Standard. The NSRS recommends that the SDT either remove these
sections or make them separate from the formal standard to eliminate any
risk that these may be construed as requirements. An alternative method is
to very clearly identify which parts of the standard are subject to compliance
and considered mandatory and which are not considered requirements and
are only for guidance in meeting the requirements. Such as; State within in
the text that this information “Is not subject to enforcement”. 2.) The NSRS
believes the Measurements are well written and provide guidance on
acceptable compliance evidence related to the requirement.3.) Measurement
M2 related to R2 states that outages related to encroachments have records
confirming no Real-Time observations of any MVCD encroachments. The
NSRS feels this would be hard to prove as a negative. It could require one to
show every single patrol or inspection has documentation stating no real time
encroachments were observed.4.) Editorial Comment on Draft SDT VSLs for
R2: To clarify the statements made for the Moderate, High and Severe
VSLs. please add the verbiage, “into the MVCD” after “The TO had an
encroachment.......”
Response:
1. This issue will be addressed by NERC as the results-based standard-making procedural document is
finalized.
2. Thank you for your comments.
3. As stated in the Measure, an attestation serves as adequate evidence.
4. Thank you for noticing this oversight. It will be corrected.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
23
Organization
Yes or No
Question 8 Comment
BGE Forestry
Management
Yes
4.2.4 States that the Standard is not applicable to “...to Facilities .... located
inside the fenced area of a switchyard, station or substation”. This implies
that anything within the fenced area of a switchyard, substation or power
plant does not fall within the jurisdiction of FAC-003-2. Some fenced in areas
could be very large and susceptible to vegetation encroachments issues.
Suggest reference to “inside the fence” be removed.Disagree with R6. Inspection Frequency. Very prescriptive. Please consider allowing TO’s to
select an annual frequency that best fits their requirements, such as calendar
year, every growing season, every non-growing season, etc. BGE currently
defines their inspection frequency as annually during the non-growing
season, October 1 to May 1. BGE believes inspecting during the dormant
season is a best practice due to the ability of the inspector to identify
vegetation defects, especially off the ROW, which could be hidden during the
growing season due to foliage, canopy cover, etc. Also, if a utility elects to
leverage an advance technology, such as LiDAR, it provides the most
effective results when LiDAR is utilize during the growing season, therefore
allowing the results of the advance technology to enhance the fall to spring
inspection cycle. Table 1 - Time Horizons, Violation Risk Factors, and
Violation Severity Levels The VSL’s for R7 all include “the Transmission
Owner failed to complete.....% of its annual work plan (including
modifications if any)”. This is not clear to BGE. R7. allows plans to be
modified due to changing conditions, for example ROW maintenance could
be deferred to the following year due to mutual assistance agreements if the
deferment does not violate the encroachment within the MVCD. The VSL
implies this is a violation since the “modification” deferred a certain
percentage of the planned worked to the following year, therefore 100% of
the planned worked wasn’t completed. If the modification was excluded, than
100% of the planned work would have been completed.
Response:
1. Regarding station boundaries, overall industry consensus is that line-based vegetation programs do not
apply inside the station boundary. The SDT believes that “fence” is the best overall term for a station
boundary.
2. While the SDT lauds BGE’s approach, it feels that a calendar year basis affords sufficient flexibility for
BGE and other TOs to schedule their inspections.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
3. The Standard suggests that the TO will begin with an original plan which may then be modified; it is
implicit that measurements of plan completion are against the modified plan, not against the original
plan.
24
MidAmerican Energy
Yes
Any references to "observed in real time" should be removed. Vegetation
contacts must be verified and references to real time are inappropriate. This
causes difficulties in proving a negative in real time.
Response: The SDT believes that the commenter has misinterpreted the requirement. It is not necessary for
the TO to continuously observe; rather, a violation can only be reported if observed in real time.
25
NERC Staff
Yes
Effective Dates
•
•
•
The first item should be re-written to “First calendar day of the
first calendar quarter one year after the date of the order
approving the standard from applicable regulatory authorities
where such explicit approval is required.”
The second item is not needed and should be removed.
The third item is okay but the phrase “where explicit regulatory
approval is not required” should be removed.
Exceptions
•
Identifying a critical line and then waiting 12 months to
perform vegetation management is counter to the risk
avoidance strategy that the standard is attempting to
accomplish. In effect, this standard permits an entity to
identify a major WECC path or an IROL just prior to peak
season and then not complete any vegetation management
activities until just before the next season 12 months later.
This is wholly inappropriate. The Planning Coordinator will
identify these lines sufficiently far in advance that the 12month window will prevent encroachments
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
•
•
Using the phrase “an element of an IROL” seems confusing
because “Element” is a term defined in the glossary. Further,
IROL is an identified limit, not a physical component. This
should be reworded to say “a facility that is identified to be
part of an interface or path impacting an IROL.” This is also
seen in R1 and R2 and needs to be adjusted there as well. The
industry has reviewed this language and has found it to be
sufficiently clear.
For newly acquired assets, the 12 month window may be
appropriate, but there needs to be a much nearer term
inspection undertaken to identify “risky” vegetation.
Definition
•
•
The modified definition assumes the ROW is maintained, which
may not be the case (for instance, if a newly acquired asset
has not yet been acted upon). An entity could interpret the
new definition to indicate that the new owner cannot be
performing an initial vegetation inspection if the ROW has not
yet been maintained. The phrase “maintained transmission
line” should be changed to “applicable transmission line.”
The inclusion of the phrase “which may be combined with a
general line inspection” is unnecessary and should be
removed. In fact, the current definition does not restrict
combining the inspection with other field visits, while in the
proposed definition that vegetation inspection can only be
combined with a general line inspection.
Objectives (Section 3)
• NERC staff is concerned that the purpose states “that could
lead to Cascading.” This qualifier limits the purpose of the
standard, which should be to prevent vegetation-related
outages. The more outages there are, the less the overall
system reliability; it does not necessarily have to lead to
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•
Cascading to be significant and represent a reasonable risk to
the BES.
The term “maintain” might be better than “improve.”
Applicability (Section 4)
• 4.1 Functional Entities
• Noticeably absent from the standard is coverage for
transmission facilities that connect generators to the
interconnected bulk power system. As such, the team should
add Generator Owners to the applicability and include such
language that was proposed by the ad hoc team: transmission
facilities that connect generators to the bulk power system that
exceed two spans from the fence-line of the generating plant;
coupled with the previous discussion, this provides complete
coverage for all transmission facilities and switchyards and
substations. This is what is needed to ensure no gaps in
vegetation management coverage.
• 4.2 Facilities
o The identification of critical facilities herein does not
recognize the overarching criteria that are being
developed in support of the PRC-023 order, and in some
respects, in response to Order 693 directives to define
the criteria for “critical facilities.” The FAC-003-2 SDT
should work in conjunction with the PRC-023 team,
which is establishing a set of criteria for identifying
critical facilities such that the outcome across all NERC
standards is consistent.
• “Transmission line” should be capitalized as a NERC-defined
term.
o
4.2.4: This exclusion seems strange. It would appear
that there are no expectations for vegetation
management in switchyards, which is unacceptable.
We should be able to develop language that requires
that a Transmission Owner or Generator Owner
maintain vegetation within fenced areas of the
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switchyard, station, or substation to the same
clearances as one does for the ROWs, without
necessarily obligating them to an annual cycle of
inspection or management.
o
Requirement R4
•
“Qualified personnel" should be defined. In the Rationale,
some examples are listed, but who else counts as “qualified
field personnel”? This was intended to be an incomplete partial
list.
• “At any moment” is an unnecessary qualifier and should be
removed (same for M4).
• With respect to the phrase “intentional time delay,” intent is a
tricky thing to prove. Most standards set clear timelines which
kick in regardless of intent, because it diminishes reliability to
base a standard on intent. The SDT should consider doing so
here.
Requirement R5
• NERC staff is confused by the overall purpose of this
requirement. It appears to be a defense to a possible violation
for failure to perform some planned vegetation work, but it
flips it around and makes it a requirement. A better approach
would be to just deal with this in addressing the
mitigating/aggravating factors under a violation of R1 and R2.
This concept is already part (R1.4) of the existing in-force
FERC-approved FAC-003-1, but has been renamed to avoid
conflict with terminology in the current NERC compliance
guidelines.
• The team should be more specific with respect to expectations
for “corrective action.” There needs to be an expectation that
the corrective action needs to maintain an equivalent level of
performance consistent with the intent of the vegetation
management program. This could include, for example re-
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•
rating lines to reduce max sag until the condition is rectified,
enhanced inspection cycles to monitor conditions, etc. It would
be useful to define a metric for the success of corrective
actions.
The team should be clearer on what constitutes a “constraint.”
Is it only legal constraints? One interpretation could be
resource constraints, which would certainly not be appropriate
in this context. The phrase “due to constraints” is also used in
the Rationale section. In this context, “constraint” appears to
mean congestion on a transmission line. This seems very
different from being “constrained from performing planned
vegetation work.” In fact, the existence of congestion on a line
does not necessarily create risk. We would not want entities to
make the economic determination that they will put off
required vegetation work because it would cost too much in
energy sales profits.
Requirement R6
• It would appear necessary to require the use of the inspection
information to guide or modify program development as is
identified in the Rationale box accompanying the requirement.
This is referred to in R7 but is not identified as an expectation
from R6.
• What are "all applicable transmission lines"? Are those lines
covered by both R1 and R2? Clarify this.
•
“Once per calendar year" requires more guidance. Would two
inspections on 12/31/2010 and 1/1/2011 satisfy this
requirement? Shouldn't there be a requirement to space these
inspections out? Recommend: once per calendar year with no
more than 15 months between inspections.
•
The last sentence of R6’s Rationale states that “Transmission
Owners should consider local and environmental factors that
could warrant more frequent inspection.” But the way the
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requirement is written, there is no basis for requiring anything
more frequent than once per calendar year. If the intent is to
have stricter timelines for different registered entities, then the
standard would need to be revised.
Compliance
• Additional Compliance Information
o Categories of Sustained Outages
Category 3 (Fall-ins from outside the ROW)
should be reinstated. Even if it is not required by
the standards, Category 3 reporting should be
kept. The SDT believes that the current NERC
TADS process captures such information
adequately.
There is currently a public bulletin to encourage
Transmission Owners to report Category 1 and 2
outages within 48 hours. The SDT should
consider adding this as a requirement and
including it in the new standard as such. The
SDT has considered your suggestion and
believes that the recognized requirement to
promptly self-report any potential violations is
sufficient.
VSLs
• The VSL for R3 should be shifted to an approach that simply
counts the missing elements: Thanks for your comments. The
SDT has modified the VSLs for R3.
o lower = missing one element
o moderate = missing two elements
o high= missing three elements
o severe = not having documents
• The VSL for R4 uses the phrase “vegetation threat,” which
needs to either be conformed to the text of the drafting team
or defined. This VSL also uses the phrase “intentional delay” A
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•
•
•
truly intentional delay should be labeled as severe, not just
high. (And as already stated, intent is a very tricky thing to
prove.) In the context of the requirement, Measure and VSL,
the term “vegetation threat” is self-evident. Refer to the SDT’s
earlier reply regariding “intentional delay”.
For the VSL for R5, there may be ways to differentiate
violations based on whether the entity identified appropriate
corrective actions (versus missing obvious alternatives),
attempted corrective actions but failed, considered alternative
corrective action, etc. The SDT has considered this but has not
identified a good means of differentiation. Additionally,
industry stakeholders have not offered any means of
differentiation. The SDT would welcome a proposal.
For the VSL for R6, the SDT should differentiate between the
criticality of different lines. At the very least, a failure to
inspect R1 lines should be a more severe violation than a
failure to inspect R2 lines. The risk to the system is properly
addressed by the VRFs, not by the VSLs.
The VSL for R7 should perhaps be differentiated based on
whether the incomplete work related to critical versus noncritical or less critical lines (i.e., R1 lines vs. R2 lines). The risk
to the system is properly addressed by the VRFs, not by the
VSLs.
Guidelines and Technical Basis
• R1/R2
o “If an investigation of a fault by a qualified person
confirms that a vegetation encroachment within the
MVCD occurred, then it shall be considered a Real-time
observation”: This is an important statement and
should be included as part of the requirement itself. The
SDT feels that this is really more of a “Measure” issue
than a “Requirement” issue, and is adequately captured
in M1.
• R3
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o
o
•
With respect to the phrase “an adequate transmission
vegetation management program,” the standard talks
about factors to consider, but the requirement does not
include any provisions on which to base a determination
of adequacy. NERC staff believes it should. With NERC’s
movement to the results-based standard-making
techniques, this is an outstanding issue that can best be
resolved once RBS techniques are firmly established.
The guideline states, “This approach provides the basis
for evaluating the intent, allocation of appropriate
resources and the competency of the Transmission
Owner in managing vegetation,” but nothing in the
requirements actually provide explicitly for such
evaluations. The SDT asserts that with the totality of
R3, M3 and associated VSLs, it is possible for the
auditor to assess the TO’s intent, competency, etc.
R4
o
o
o
“Cellular service or two-way radio disabled” should not
be considered an acceptable unintentional delay. This
seems to be within the entity’s control: there may be a
difference between whether the cell service problems
are due to network problems as opposed to the entity
failing to charge the phone or pay the bill. The SDT has
considered the comments, but believes the verbiage is
adequate.
“Remote field locations” should not be considered an
acceptable unintentional delay. This is not entirely
beyond the registered entity's control. There may be a
difference between a work site that is isolated from
radio or cellular networks versus the fact that the
employee simply left the radio in the truck. The SDT
has considered the comments, but believes the
verbiage is adequate.
“Vegetation-related conditions that warrant a response”
should be defined in the standard. Qualified personnel
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o
o
o
•
are ab;le to assess the conditions as called for in the
Requirement.
It is not clear to NERC staff that a lineman or an
arborist is capable of completing “an assessment of the
possible sag or movement of the conductor” out in the
field in real time. However, if this is the expectation, it
should be written into the requirements. The SDT
believes it is necessary to rely on field personnel for
routine decisions in the field, and that it is impractical
and unworkable for engineering or survey teams to
examine every questionable site. The SDT has
considered the comments, but believes the verbiage is
adequate.
The fourth paragraph states that the “Transmission
Owner has the responsibility to ensure the proper
communication…” Earlier in this section, however, it
says that the condition of the communication system is
not considered to be intentional delay. This
inconsistency needs to be addressed. This sentence
should also include a requirement for correcting the
vegetation encroachment. The SDT agrees with your
observation and will clarify the wording to indicate
communication “processes” between field personnel and
control centers are the issue being addressed.
The phrase “minutes or hours” is used in the final
sentence of the fourth paragraph of this sentence. This
detail should be written more clearly and written into
the standards. Is 24 hours still hours? What about 48
hours? The SDT has conceived of cases where a 10hour or more delay may be perfectly acceptable, but
others where a 10- or 20-minute delay is inexcusable.
The SDT believes that no rigid timeline is appropriate.
R6
o
With respect to the following sentence, beginning with
“Therefore it is expected,” NERC staff is concerned that
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nothing in the requirement actually makes this
expectation enforceable. It would be best to require
each TO that experiences a vegetation related sustained
outage to investigate the outage and make revisions to
its TVMP if the investigation shows that the growth
rates of vegetation under the TO’s control do not match
those anticipated in the TVMP. The primary definition of
“expected” is “looking forward to a probably
occurrence”, not a “required activity,” and so the SDT
believes that the verbiage is appropriate.
•
R7
o
o
The second paragraph states that “recent line
inspections may identify unanticipated high priority
work.” But the fifth bullet in R7 does not indicate that
the higher priority work was identified in a recent line
inspection. R7 should be revised to make that caveat
clear. The SDT suggests that it is unnecessary to state
that the TO will use all information available to it
(including inspection results) in identifying
unanticipated high-priority work.
The second paragraph references “Modifications to the
annual work plan.” Presumably, these modifications
would not excuse compliance with R1, R2, and R6. That
should be made clearer in the requirements. Thank you
for the comments.
Table 3
• None of the requirements actually reference this table. That
should be modified. Thank you. The Table will be removed.
•
Response:
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Effective Dates
The SDT assumes that NERC staff will correct implementation timetable conflicts.
Exceptions
The SDT considered such language, but ultimately determined that it was unnecessary, partly because the
response to “hot-spot”-type conditions is not part of this standard.
Definition
•
•
Thank you for your excellent comments. The SDT has made changes to meet this concern.
Previous overwhelming industry comments have dictated the need for the SDT to clarify this language
as it exists in the current draft. The current definition offers no restrictions that the vegetation restriction
may only be combined with a general line inspection.
Objectives (Section 3)
• The Purpose as currently stated reflects broad industry consensus that earlier Purpose statements were
over-reaching.
• The Purpose as currently stated reflects broad industry consensus.
Applicability (Section 4)
• Re: generators - There is a NERC GO/TO team established to address this issue.
• Re: critical facilities - While the SDT is aware of the interest in FERC to consolidate tests or criteria for
so-called “critical” facilities, NERC leadership have indicated to FERC staff its commitment to separate
efforts for use by PRC-023 and this standard.
• Re: capitalizing Transmission Line - The SDT agrees and thanks you for your comments.
• Re: 4.2.4 - Wide industry consensus is that line-based vegetation programs should not apply inside the
station boundary. Also, as previously mentioned, another NERC team is examining the TO/GO issue.
Requirement R4
• Re: qualified personnel - The SDT changed the language to confirmation by the Transmission
Operator.
• Re: “At any moment” - The SDT believes that “at any moment” is a necessary but sufficient qualifier.
• Re: “intentional time delay,” - The SDT has considered this. FERC has already approved other
standards with the same language.
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Requirement R5
• Re: corrective action - Past and recent industry comments indicate little confusion on this portion of
the Standard.
• Re: constraints - Past and recent industry comments indicate little confusion on this portion of the
Standard.
Requirement R6
• Re: inspection information - The SDT suggests that it is unnecessary to state that the TO will use all
information available to it (including inspection results) in developing its annual plan.
• Re: “all applicable transmission lines” - Please refer to section 4 (“Applicability”) of the draft.
• Re: calendar year - The SDT posed the question of inspection frequency to the overall industry in an
earlier posting and received general consensus that a one-year interval would be appropriate.
• Re: Rationale - The SDT does not intend that stricter timelines be rigidly defined or employed.
Compliance
• Re: Category 3 (Fall-ins from outside the ROW) - The SDT added this back in.
• Re: Public bulletin - The SDT has considered your suggestion and believes that the recognized
requirement to promptly self-report any potential violations is sufficient.
VSLs
•
•
•
•
•
Re: VSL for R3 - The SDT has modified the VSLs for R3.
Re: VSL for R4 - In the context of the requirement, Measure and VSL, the term “vegetation threat” is selfevident. Refer to the SDT’s earlier reply regarding “intentional delay”.
Re: VSL for R5 - The SDT has considered this but has not identified a good means of differentiation.
Additionally, industry stakeholders have not offered any means of differentiation. The SDT would
welcome a proposal.
Re: VSL for R6 - The risk to the system is properly addressed by the VRFs, not by the VSLs.
Re: VSL for R7 - The risk to the system is properly addressed by the VRFs, not by the VSLs.
Guidelines and Technical Basis
• Re: R1/R2 - The SDT feels that this is really more of a “Measure” issue than a “Requirement” issue, and
is adequately captured in M1.
• Re: R3 –
o With NERC’s movement to the results-based standard-making techniques, this is an outstanding
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issue that can best be resolved once RBS techniques are firmly established.
The SDT asserts that with the totality of R3, M3 and associated VSLs, it is possible for the
auditor to assess the TO’s intent, competency, etc.
Re: R4 o Re: “Cellular service or two-way radio disabled” - The SDT has considered the comments, but
believes the verbiage is adequate.
o Re: “Remote field locations” - The SDT has considered the comments, but believes the verbiage
is adequate.
o Re: “Vegetation-related conditions that warrant a response” - Qualified personnel are able to
assess the conditions as called for in the Requirement.
o Re: “assessment of the possible sag or movement of the conductor” out in the field - The SDT
believes it is necessary to rely on field personnel for routine decisions in the field, and that it is
impractical and unworkable for engineering or survey teams to examine every questionable site.
The SDT has considered the comments, but believes the verbiage is adequate.
o Re: The fourth paragraph - The SDT agrees with your observation and will clarify the wording to
indicate communication “processes” between field personnel and control centers are the issue
being addressed.
o Re: The phrase “minutes or hours” - The SDT has conceived of cases where a 10-hour or more
delay may be perfectly acceptable, but others where a 10- or 20-minute delay is inexcusable. The
SDT believes that no rigid timeline is appropriate.
Re: R6 o Re: sentence beginning with “Therefore it is expected,” - The primary definition of “expected” is
“looking forward to a probable occurrence”, not a “required activity,” and so the SDT believes
that the verbiage is appropriate.
Re: R7 o Re: The second paragraph - The SDT suggests that it is unnecessary to state that the TO will use
all information available to it (including inspection results) in identifying unanticipated highpriority work.
o Re: The second paragraph references “Modifications to the annual work plan.” - Thank you for
the comments.
o
•
•
•
Table 3
• Thank you. Table 3 has been removed.
26
FirstEnergy
Yes
FE has the following additional comments:1. In the SDT consideration of
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comments from Draft 3, it was indicated that "The subcommittee will ask that
NERC's legal department write a statement for addition to each standard to
clarify which parts/elements of the standard are mandatory and enforceable
and which are provided only as information". We would appreciate this
statement be placed into the standard before the final ballot so stakeholders
have an opportunity to review and comment on the wording.2. We cannot
comment on the Technical Reference Document since the latest draft was
not posted for review. Does NERC intend to post this at a later time? If so,
we ask that NERC give the industry enough time to adequately review the
document so that we can provide quality feedback.3. In the Guidelines and
Technical Basis Section, in the first paragraph of Requirement R5, second
sentence, the word "temporarily" should be removed since it was removed
from the requirement.
Response:
The SDT thanks you for your comments.
1) The NERC legal department has been contacted to provide a statement to clarify which parts/elements
of a standard are mandatory and enforceable and which are provided only as information. This
statement is nearing finalization and when completed will be posted as a separate document when the
next draft of FAC-003-2 is posted.
2) The Technical Reference Document is not a mandatory and enforceable document but your feedback is
definitely appreciated once the document is finalized. The Technical Reference will be updated during
the next ballot which will start during early August. The SDT will finalize the Technical Reference
document at the August meeting in Toronto, ON which is scheduled from 8/17-8/19/10 and will post for
comment.
The word ‘temporarily’ has been removed from the Guidelines and Technical Basis as requested. Thank you
for your comment.
27
Ameren
Yes
Funding Adjustments (increase or decrease) - need more description to imply
only when planned vegetation work is “over and above”.
Response: Thank you for your comment. The SDT believes your observation and question is the same as
voiced in Question 5. As stated in the SDT’s response to Ameren’s Question 5, we reviewed the Funding
Adjustment example for R7 and feels this is a valid reason for modifying the Annual Plan keeping in mind
that a modification must not place the transmission system at risk of vegetation encroachment into the
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Yes
Hydro One wants to thank the SDT for the effort that has gone into
developing this proposed revision to FAC-003. Overall the new version is
consistent with FERC Order 693 and will be a straightforward, workable, and
auditable standard. One item requiring clarification and change is the Active
ROW definition. The recent addition of a centerline distance to edge of
Active ROW is not acceptable. In many areas design standards allow a
smaller ROW width with no compromise to “cleared width” or tree related
reliability of the line. The SDT needs to address this issue. In R5, the phrase
'where a transmission line is put at potential risk due to the constraint' should
be better defined. This is vague and could lead to inconsistent practices
between utilities. All undesirable species on the full width of the ROW are
defined as 'potential risks to the transmission line' regardless of height or
location at the time of vegetation management. Interim corrective action
should only be required when the potential risk is approaching the imminent
threat classification.
MVCD.
28
Hydro One
Response: The SDT thanks you for your response. Your objection to our attempt to define a minimum width
of the Active Transmission Right of Way was very similar to many other commenters. The SDT has
subsequently revised the definition of ROW.
The issue you mention with R5 and “potential risk to the system” is understandable. The SDT changed this.
29
Idaho Power
Company
Yes
I would like to see something more from NERC to clear the way for utilities to
do vegetation management on federal lands that will allow timely vegetation
management without delays from these federal entities.
Response:
Thank you for your comments. This Standard places requirements on the Transmission Owners, not on
landowners. There is no legal mechanism for this Standard to take rights from property owners and assign
them to the Transmission Owner. There is joint UAA/EEI Task Force that is working on an MOU with the
Federal Agencies to address these issues which are outside the purview of NERC Reliability Standards.
30
Idaho Power
Yes
I'd like to see language or NERC support to encourage federal agencies to
expedite vegetation management maintenance requests and minimize the
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barriers to perform work on federal lands.
Response:
Thank you for your comments. This Standard places requirements on the Transmission Owners, not on
landowners. There is no legal mechanism for this Standard to take rights from property owners and assign
them to the Transmission Owner. There is joint UAA/EEI Task Force that is working on an MOU with the
Federal Agencies to address these issues which are outside the purview of NERC Reliability Standards.
31
Dominion
Yes
In R4 and M4, the phrase "without any intentional time delay" has been
added. We recommend removing this language from the requirement as it is
not possible to measure intent.
Response:
Thank you for your comment. Please refer to the SDT response to NERC staff above regarding R4.
32
Consolidated Edison
Company of New
York Inc
Yes
In R5, the SDT should better define the phrase 'where a transmission line is
put at potential risk due to the constraint.' This is rather vague and could lead
to inconsistent practices between utilities. Con Edison defines all undesirable
species on the full width of the ROW as 'potential risks to the transmission
line' regardless of height or location at the time of vegetation management.
Interim corrective action should only be required when the potential risk is
approaching the imminent threat classification.
Response:
The SDT thanks you for your comments. As described in the Technical Reference document (See Page 30),
R5 is not intended to address situations where the transmission line is not at potential risk, meaning risk of a
Sustained Outage, and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on non-threatening, low
growth vegetation but agree to the use of mechanical clearing. In this case the Transmission Owner is not
under any immediate time constraint for achieving the management objective, can easily reschedule work
using an alternate approach, and therefore does not need to take interim corrective action. However, in
situations where transmission line reliability is potentially at risk due to a constraint, the Transmission
Owner is required to take an interim corrective action to mitigate the potential risk to the transmission line.
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Orange and Rockland
Utilities, Inc.
Yes or No
Question 8 Comment
Yes
In R5, the SDT should better define the phrase 'where a transmission line is
put at potential risk due to the constraint.' This is rather vague and could lead
to inconsistent practices between utilities. Orange and Rockland Utilities, Inc.
defines all undesirable species on the full width of the ROW as 'potential
risks to the transmission line' regardless of height or location at the time of
vegetation management. Interim corrective action should only be required
when the potential risk is approaching the imminent threat classification.
Response: The SDT thanks you for your comments. As described in the Technical Reference document (See
Page 30), R5 is not intended to address situations where the transmission line is not at potential risk,
meaning risk of a Sustained Outage, and the work event can be rescheduled or re-planned using an alternate
work methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the Transmission
Owner is not under any immediate time constraint for achieving the management objective, can easily
reschedule work using an alternate approach, and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint, the
Transmission Owner is required to take an interim corrective action to mitigate the potential risk to the
transmission line.
34
Entergy Services
Yes
ITEMS of concern listed below:ITEM 1: Page 13 of the Standard Draft 4
under Add'l Compliance Information - Periodic Data Submittal......Clarify if
Immediate Reporting is expected for outages in Outage Categories 1A, 1B,
2, or 4........or if Quarterly Reporting is all that is expected. It does not
specifically say that IMMEDIATE Reporting is Required for any outage type.
It is assumed that IMMEDIATE reporting is required for some outages, but is
unclear.ITEM 2: Agree that text boxes being used for additional clarity is a
benefit if used in a correct and clear manner, but it needs to be specifically
stated in the document that the text boxes are to be used for reference only,
we will not be required to specifically follow the language in the rationale, and
that and each utility should specify their own exact process for addressing
each Requirement.ITEM 3: Language should be added to the Guideline and
Technical Basis Section to clarify or re-state that this section that this section
is for assisting entities in understanding how to comply with the standard but
does not contain mandatory actions/activities.ITEM 4: Please clarify defining
factors that constitute "wind shear or fresh gale" as referenced in Section 4.4
Other. This is a very unclear interpretation and will most likely be interpreted
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differently by all involved if not specified.
Response: Thank you for your comments.
ITEM 1: There is no requirement in this Standard for immediate reporting of any vegetation outage to the TO’s
RE. The TO’s RE may require more frequent reporting or immediate reporting of any vegetation related outage.
There may be other standards that apply to any transmission line outage that require immediate notification to
the RE, NERC FERC, FBI, DOT and/or DOE. The SDT has considered your suggestion and believes that the
recognized requirement to promptly self-report any potential violations is sufficient.
ITEM 2: The Rationale boxes are intended to provide clarity and foundation behind each requirement. They are
not a part of the requirement and are not sanctionable, as such. You are correct that every TO is required to
structure its TVMP to comply with the standard as vegetation conditions exist. The NERC legal department has
been contacted to provide a statement to clarify which parts/elements of a standard are mandatory and
enforceable and which are provided only as information. This statement is nearing finalization and when
completed will be posted as a separate document when the next draft of FAC-003-2 is posted.
ITEM 3: The Guideline and Technical Reference paper Disclaimer on Page 6 of the document clearly states that
the supporting document is supplemental to the reliability standard FAC-003-2 – Transmission Vegetation
Management and does not contain mandatory requirements subject to compliance review.
ITEM 4: Wind Shear and Fresh Gale are defined terms by the National Oceanic Atmospheric Administration
(NOAA). Fresh gale is defined as straight line winds of between 39-46 mph. Wind Shear according to NOAA is a
complicated formula that no one will ever use. Wind Shear definition according to NOAA Glossary is “The rate
at which wind velocity changes from point to point in a given direction (as, vertically). The shear can be speed
shear (where speed changes between the two points, but not direction_, direction shear (where direction
changes between the two points, but not speed) or a combination of the two.
35
Northeast Power
Coordinating Council
Yes
NPCC wants to thank the SDT for the effort that has gone into developing
this proposed revision to FAC-003. Overall the new version is consistent
with FERC Order 693 and will be a straightforward, workable, and auditable
standard. One item requiring clarification and change is the Active ROW
definition. The recent addition of a centerline distance to edge of Active
ROW is not acceptable. In many areas design standards allow a smaller
123
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
ROW width with no compromise to “cleared width” or tree related reliability of
the line. The SDT needs to address this issue. In R5, the phrase 'where a
transmission line is put at potential risk due to the constraint' should be better
defined. This is vague and could lead to inconsistent practices between
utilities. All undesirable species on the full width of the ROW are defined as
'potential risks to the transmission line' regardless of height or location at the
time of vegetation management. Interim corrective action should only be
required when the potential risk is approaching the imminent threat
classification.
Response: The SDT thanks you for your response. Your objection to our attempt to define a minimum width
of the Active Transmission Right of Way was very similar to many other commenters. The SDT has revised
the definition of ROW.
The issue you mention with R5 and “potential risk to the system” is understandable. The SDT amended the
language.
36
Arizona Public
Service Company
Yes
Qualifications needs to be put back in the standard. There needs to be a
clearance 1 requirement.
Response: Thank you for your comments. Training and qualifications are best addressed in the NERC PER
standards. Additionally please refer to the SDT response to question 8, comment 42, regarding the issue of
Clearance 1.
37
Xcel Energy
Yes
R1 & R2 states that “types of encroachments include:” - is the way this is
worded intended to imply there can be other types of encroachments that are
not listed? If not, then rephrase the leading sentence to be definitive and
indicate that the types are the only categories to be considered. We suggest
that the wording from the prior draft, i.e., “ . . . limited to”.MCVD should be a
defined term in the glossary, not in a “Rationale” box.R1 “1” should Real-time
be capitalized to reflect the glossary definition? The term is used as “real
time”, “Real time” and “Real Time” throughout the standard. This seems to
be just a drafting issue, but the same term should be used consistently. Need
to establish somewhere that the entity defines what constitutes a “qualified”
person. Further, some portions of the standard use the term “qualified
person” (e.g., see M1) and others reference “qualified field personnel” (e.g.,
see the Rational Box near M3). It seems that all references should be to
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
“qualified field personnel.”R1 & R2 are duplicative. It appears the only
reason for the separation is so that different VRFs can be assigned. Why not
just have 1 requirement and indicate that the VRF is High for one set of lines
and Med for others?In general, the “Rationale” boxes force the requirement
language into a difficult to read format.R5/M5 - the measures identified do
not constitute “corrective actions”, they merely identify documentation that
work was attempted. Corrective actions should be “actions”, such as
establish an increased monitoring plan, re-rating of the line, removal from
service, etc.R6 - Xcel Energy still believes the requirement in R6 that
mandates an annual inspection is too onerous and is at odds with the resultsbased approach of these revisions. Xcel Energy urges the retention of the
provision in the existing standard that allows the Transmission Owner to set
the frequency of inspection. In some areas of the country, annual
inspections may not be adequate. Yet in other areas, a longer inspection
frequency may be perfectly reasonable and practical. Our point is that
inspection frequency should not be treated as if it were “one size fits all”. If
treated this way, we feel this could pose a risk to reliability and is not likely to
be cost-effective. The Transmission Owner should be allowed some
flexibility. However, if the drafting team disagrees and determines that an
annual inspection is to be mandated, Xcel Energy believes that an exception
to the annual inspection is appropriate when a non-subjective advanced
technology such as LIDAR is utilized to achieve actual clearance distances.
This places the Transmission Owner in a situation where it can rationally
determine that the objectively measured distances result in a situation where
an inspection need not be performed within the next year. It is suggested
that R6 be revised to read as follows: Each Transmission Owner shall
perform a Vegetation Inspection of all applicable transmission lines at least
once per calendar year, unless the Transmission Owner, based on a nonsubjective advanced technology, such as LIDAR, determines that a longer
inspection period is appropriate.The Effective Dates section is confusing exactly when would this standard be in effect? It lists 3 approvals...do all
three have to be met or just one?The reference to Major WECC transfer
paths in the requirements introduces a weak element. The WECC major
path designation and elements that comprise those paths should be
controlled through a robust process and easily available to WECC members.
Currently, there are some concerns around that process in general.NERC’s
concerns regarding reporting vegetation related outages within 48 hours
125
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
should be addressed or clarified in the Compliance section. (i.e., incorporate
or indicate that this supersedes that recommendation). Ref: Public Notice NERC Compliance Process #2008 - 001
Response: Thank you for your comments. The yellow highlighting refers to commenter issues. The SDT
response follows.
R1 & R2 states that “types of encroachments include:”: To address your concern, there are only (4) types of
failure- to- manage types of encroachment as defined in R1 and R2 as it relates to compliance with FAC-0032. The SDT appreciates your perspective but believes the requirement as written is clear to the point of only
four encroachment types.
MCVD should be a defined term in the glossary, not in a “Rationale”: This term refers to a Table of values
that is clearly defined within the standard itself.
The term is used as “real time”, “Real time” and “Real Time” throughout the standard. : Thanks for
identifying this inconsistency and the SDT will review and address as appropriate.
Need to establish somewhere that the entity defines what constitutes a “qualified” person.: This was
replaced with confirmed by the Transmission Owner.
Further, some portions of the standard use the term “qualified person” (e.g., see M1) and others reference
“qualified field personnel” (e.g., see the Rational Box near M3).: Thanks for recognizing this inconsistency.
The term “qualified” was replaced with confirmed by the Transmission Owner.
R1 & R2 are duplicative. It appears the only reason for the separation is so that different VRFs can be
assigned. Why not just have 1 requirement and indicate that the VRF is High for one set of lines and Med for
others?: The SDT is following the VSL and VRF Guidelines which required us to designate two requirements
since the VRFs are different for the applicable lines in the two requirements.
R5/M5 - the measures identified do not constitute “corrective actions”, they merely identify documentation
that work was attempted.: The measures in R5 are evidence that appropriate corrective action was taken by
the TO. Trying to identify very specific actions would be prescriptive in nature and difficult to cover a broad
spectrum of potential corrective actions.
R6 that mandates an annual inspection is too onerous and is at odds with the results-based approach of
these revisions: As stated in previous comment responses, the SDT was directed by Order 693 to set a
minimum inspection criteria and the SDT feels that an annual inspection is a reasonable minimum frequency.
Effective Dates section is confusing - exactly when would this standard be in effect? The SDT has revised
the effective date language for clarity. Please refer to change in revised draft.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
WECC major path designation and elements that comprise those paths should be controlled through a
robust process and easily available to WECC members. Currently, there are some concerns around that
process in general. : This is an issue that needs to be directed to WECC rather than the SDT.
48 hours should be addressed or clarified in the Compliance section. (i.e., incorporate or indicate that this
supersedes that recommendation). Ref: Public Notice - NERC Compliance Process #2008 – 001: This Public
Notice is a requirement for a Regional Entity to report to NERC.
38
BC Hydro
Yes
1. R4 - There will likely be issues of definition over what constitutes an
“intentional delay” in notification. The time for reasonable reporting
needs to be quantified.
2. The standard references Tables 2 and 3 but there is no Table 1 in the
document. This is confusing and should be renumbered. This is likely a
carry over from an earlier draft where a Table 1 has been renamed or
dropped.
3. As noted earlier in Q1, table 3 is poorly developed and should be
revisited.C
4. How does one objectively measure compliance to MVCD distances?
Use of LiDAR technology, laser rangefinders, etc. should be used and
evidence of potential violations should be empirical and not based solely
on subjective observations, even if they are performed by “qualified
personnel”.
5. The technical document should include a glossary of all the acronyms
used throughout the document as it has some excessive jargon and
does not always read smoothly, especially compared to FAC-003The use of explanation boxes is helpful.
Response:
1
2
3
The SDT debated a set time limit. The team could not find a time that would fit all situations. Intentional
would apply if a TO withheld notification after having confirmed that risk conditions exist.
The standard has been revised
The SDT thanks you for your comments. Based on your comment and others, the SDT has revised the
definition of ROW.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
4
5
6
39
Yes or No
Question 8 Comment
The determination of a potential violation should employ any technology available
SDT has defined unusual terms not found within the industry.
Thank you
The United
Illuminating Company
Yes
R4:In R4 the phrase: without any intentional time delay, is a concern. There
is a time line between identification and reporting of an imminent hazard that
represents the minimal time required to complete this Requirement. Any
situation where the time between observation and reporting is greater than
this minimal time line indicates a time delay occurred. It will be left to the
compliance enforcement authority to determine if this delay was intentional or
not. It is not proper for the test to be based on Intentional versus NonIntentional. Using other synonyms such as reasonable, expeditious, prompt,
immediate or without hesitation all introduce a qualitative not a quantitative
attribute to the measurement. The Supplemental Reference for R4 indicates
that the imminent threat requirement is measured in minutes or hours; again
no guidance for enforcement. R4 would be improved with an explicit time
requirement of 6 hours between observation and report. This is measurable
and clear.R4 should be: Each Transmission Owner shall notify the control
center holding switching authority for the associated transmission line no
more than 6 hours of a qualified personnel confirm the existence of a
vegetation condition that is likely to cause a Fault at any moment.Other
commenter’s will argue that 6 hours is arbitrary or unduly prescriptive. I
believe it is in line with the Supplemental Reference and adds clarity to the
enforcement process.M4 becomes Each Transmission Owner that has a
vegetation condition likely to cause a Fault at any moment, as confirmed by
qualified personnel, will have evidence that it notified the control center
holding switching authority for the associated transmission line within 6 hours
of observation.The Transmission Owner can use the inspection as evidence
of the time of observation.Effective Dates: The effective dates in the
implementation Plan is in a different form then UI was expecting. Effective
Date 1 UI has no comment.Effective date number 2 implies that if the BOT
approves the standard and FERC takes no action (neither approves,
remands or withholds approval of the standard) then the standard will
become effective in one year. This seems to create the possibility of an
effective standard without enforceability.Effective Date number 3 implies that
regardless of any action by FERC the standard will become effective at least
128
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
one year following BOT approval. Again this creates an effective standard
without enforceability. Also the use of “at least one year” does not add any
clarity to when the Standard would be effective any way.
Response:
Thank you for your comments. The SDT considered a fixed time as you offer. We rejected that alternative as
the situations under which conditions are found that can cause a Fault at any moment vary widely based on
the terrain, weather and available transportation and communication methods. This Requirement is directing
the TO to communicate the condition as soon as the above mentioned constraints will allow.
We have addressed your concerns by revising the effective date language.
40
FPL Corporate
Compliance
Yes
R5 as written is vague. It leads to confusion in interpretation. FPL
recommends the following wording.R5. The Transmission Owner shall certify
each corridor or line section that it meets the standards it set forth under R3
until the next planned management cycle when it is completed. If a location
in known to not meet the criteria defined under R3, a mitigation plan must be
in place to prevent a violation of R1 or R2.R1 and R2 are too inclusive. They
equate vegetation growing in to conductors from below the same as
vegetation falling or blowing into the conductors from within the Active ROW.
There is no evidence that a cascading event has ever been caused by the
latter two events. This standard should concentrate on vegetation growing
from below the conductor. Suggested wording of R1 and R2 is as follows.R1.
Each Transmission Owner shall manage vegetation to prevent encroachment
into the Minimum Vegetation Clearance Distance (MVCD) as shown in Table
2 from within the active ROW on of any line identified as an element of an
Interconnection Reliability Operating Limit (IROL) or Major Western Electricity
Coordinating Council (WECC) transfer path (operating within Rating and
Rated Electrical Operating Conditions). Encroachments are determined by:
1. An encroachment, observed in real time, 4. An encroachment due to a
grow-in from below the conductor in the active ROW that caused a Fault.R1.
Each Transmission Owner shall manage vegetation to prevent encroachment
into the Minimum Vegetation Clearance Distance (MVCD) as shown in Table
2 from within the active ROW on of any line that is not an element of an
Interconnection Reliability Operating Limit (IROL) or Major Western Electricity
Coordinating Council (WECC) transfer path (operating within Rating and
Rated Electrical Operating Conditions). Encroachments are determined by:
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
1. An encroachment, observed in real time, 4. An encroachment due to a
grow-in from below the conductor in the active ROW that caused a Fault.
Response: The STD recognizes that defining any risk is subjective. Removing the term does not change the
fact that each TO must determine the risk and respond accordingly.
The SDT has placed reference to the different severity of the respective violations into R1 and R2. Both
NERC and FERC are on record that fall-in and blow-in interruptions place sufficient risk to the system that
they should be part of the standard.
41
MWDSC
(METROPOLITAN
WATER DISTRICT
OF SOUTHERN
CALIFORNIA)
Yes
Requirement R4.uses the phrase "notify the control center holding switching
authority for the associated transmission line" when a vegetation condition is
confirmed which is likely to cause a Fault. Switching jurisdiction may be
assigned to a manned substation located closer to a line rather than a
remote 24/7 manned control center. However, the switching substation will
notify its control center. The control center may need to notify and coordinate
with its Balancing Authority or neighboring control centers. Suggest
changing the phrase as follows: "notify the appropriate control center(s)for
the associated transmission line"
Response: The SDT thanks you for your comments. The example you provided in your comment is in
compliance with the Requirement as written. The local procedure developed by a Transmission Owner may
involve multiple notification steps but, as long as the proper operating personnel holding switching authority
for that associated line is notified without any intentional delay, the Requirement is met. Due to multiple
variations in utility notification procedures across North America, the SDT has decided to retain the existing
language in the current draft.
42
Southern California
Edison Company
Yes
SCE questions the need for including the “Guidelines and Technical Basis”
section within the body of the standard and is also curious as to the criteria
used in developing new Table 3.SCE finds this Draft (4) to be the best work
product thus far, and commends the SDT for its efforts and continued
dedication to crafting a best-in-class standard.
Response: The SDT thanks you for your comment. The ‘Guidelines and Technical Basis” is part of the
format change with a “results based” standard. The idea is to bring some of the technical reference
documentation into the Standard. This will hopefully make the entire Standard a more complete document
and will reduce the need to have both the Standard and the Technical Reference Document in hand.
130
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
Table 3 was an attempt to define a “minimum width” of the Active Transmission Right of Way. This table,
along with the footnote, has been removed from the Standard. The definition of Right of Way has been
changed in the Glossary.
43
Bonneville Power
Administration
Yes
The basis of managing vegetation to MVCD in Table 2 (essentially withstand
distances) will likely prove problematic. BPA believes NERC should develop
an additional table that calls out minimum "buffers" based on attributes such
as line voltage, line rating etc. This table should be a companion to Table 2.
It is NERC's responsibility to regulate and we believe that they should do so.
In this case, the loss of flexibility for the owners is not necessarily a bad
thing.
Response: The SDT thanks you for your comments. As described in the Background Section of the
Standard, FAC-003-2 is being drafted utilizing a Results Based Standard approach. One component of this
type of Standard is that requirements within a standard are not too prescriptive allowing for flexibility. An
additional Table would be considered overly prescriptive and in direct conflict with our guidance. It is the
Transmission Owner’s responsibility to identify the ‘buffers’ that you mention, not NERC. Since conditions
vary significantly across North America, maintaining this specific buffer distance may not be feasible for all
utilities.
44
Southern Company
Transmission
Yes
The NERC Glossary of Terms provides a definition for Flashover. The
Rationale boxes for R1 and R2 use the term “spark-over”. This is
inconsistent with other references in the Standard. Note that the term
Flashover is used in footnote No.4. Please resolve the inconsistency
between these terms.We are concerned FAC-003-2 is being developed
under a zero tolerance philosophy, while other NERC standards do not adopt
a zero tolerance philosophy. Industry performance under FAC-003-1
indicates the standard is working and that industry is responding to ensure
reliability of the electric Transmission system.We would like to thank the SDT
for the work they have put into developing the proposed draft.
Response:
The SDT thanks you for your response. The technically correct term for the electric discharge through air is
“spark-over”. In the Technical Reference Document this term is used. The technical definition of “flashover” refers to the electric discharge over the surface of insulation when the “withstand” of the air is less
than the “withstand” of the insulation and the insulator “flashes over”.
131
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
However, the commonly used term in industry for both phenomena is “flash over”. The NERC Glossary
definition has actually rolled the technical definition of both terms together into one definition.
The SDT has decided to use the term “flash-over” in all sections of the Standard except for the derivation of
the Gallet equations in the appendix of the Technical Reference Document. Hopefully this will alleviate any
confusion.
The SDT recognizes that the current version of the Standard is zero tolerance and believes it is compelled to
write the new version it that way. FERC staff and NERC assert that a revised standard cannot result in less
reliability than the one it replaces, and, their belief is the current Standard is zero tolerance.
45
ITC Transmission
Yes
We were beginning to except Version 3 to the standard but with the addition
of “Table 3, Minimum Distance from the Centerline of the Circuit to the edge
of the active transmission line ROW” is totally unacceptable. This entire
reference should be stricken from the standard. ITC can not support this
table #3 and Version 4 is unacceptable.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has revised
the definition of ROW in the NERC Glossary.
132
Consideration of Comments on Initial Ballot — Project 2007-07 Vegetation Management FAC-003-2
Date of Initial Ballot: 7/9/2010 - 7/19/2010
Summary Consideration: In general, there were no common themes and as such each comment was responded to individually.
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment serious
consideration in this process. If you feel there has been an error or omission, you can contact the Vice President and Director of Standards, Gerry
1
Adamski, at 609-452-8060 or at [email protected]. In addition, there is a NERC Reliability Standards Appeals Process.
Voter
Kirit S. Shah
Entity
Ameren Services
Segment
Vote
Comment
1
Negative
(1) Need clarification on Footnote number 2 and Table 3 : Does this mean wider ROW
easements will need to be acquired to be compliant or will this apply to ROW’s for new
circuits going forward? (2)R7 - Funding Adjustments (increase or decrease) - need more
description to imply only when planned vegetation work is “over and above”. (3) R5 - What
constitutes a “potential risk”? Breaking the MVCD or getting close to it? (4) R7 - No work
plan can ensure that NO vegetation encroachments will occur; can language be added
similar to “to ensure that no vegetation encroachments ‘from vegetation within the active
right of way’ occur within the MVCD”?
Response:
(1) No, the SDT has re-established the concept of an Active Transmission Line ROW by changing the definition of Right of Way with the same
principles which was almost universally accepted by industry. After thorough analysis of potential modifications to Table 3 and other
alternatives, the team found no specific, prescriptive, or formulaic language which can be applied across the US, Canada and Mexico, thus the
team reverted to the Active Transmission Line ROW, removed Footnote 2 and Table 3.
(2) The SDT limits the reasons for plan adjustment by whether the changes place the system at risk of a violation of the MVCD as defined in R1 and
R2.
(3) The SDT recognizes that defining any risk is subjective. Removing the term does not change the fact that each TO must determine the risk and
respond accordingly.
(4) The SDT has incorporated your suggestions.
Danny
McDaniel
Cleco Power LLC
1
Negative
Bryan Y
Harper
Cleco Utility Group
3
Negative
1
1. Encroachment into the MVCD should require the owner to take immediate corrective
action to mitigate the threat. But such an encroachment should not be reportable as a
violation. Owners may be hesitant to report if they known it is a violation. Recommend the
SDT consider modifying the measures for R1 and R2 to be applicable only in the interruption
of transmission facility or allow the reporting but don't make it a violation of compliance. R4
states "Each Transmission Owner, without any intentional time delay, shall notify the control
center holding switching authority for the associated transmission line when qualified
The appeals process is in the Reliability Standards Development Procedure: http://www.nerc.com/files/RSDP_V6_1_12Mar07.pdf.
Voter
Matthew D
Cripps
Entity
Cleco Power LLC
Segment
Vote
Comment
6
Negative
personnel confirm the existence of a vegetation condition that is likely to cause a Fault at
any moment" 2. In R4, the use of "intentional" is a vague term. As other standards
prescribe, set a time at which the control center should be notified. R5 states: "Each
Transmission Owner shall take corrective action when it is constrained from performing
planned vegetation work, where a transmission line is put at potential risk due to the
constraint." 3. In R5, the use of "potential risk" is a vague term. R5 should read as follows:
Each Transmission Owner shall take corrective action when it is constrained from
performing planned vegetation work. R7 states: "Each Transmission Owner shall complete
the work in an annual vegetation work plan to ensure no vegetation encroachments occur
within the MVCD ...." 4. The first sentence should not include the phrase "to ensure no
vegetation encroachments occur within the MVCD" since the requirement is to do the work
in the work plan. The added phrase adds ambiguity, e.g., if there is an encroachment, is R7
violated since it does not meet the "ensure" phrase? Would this cause a double jeopardy
situation with R1 and R2?
Response:
1. The SDT discussed this issue at length. However, NERC and FERC interpret vegetation growing into MAID as too great a risk to allow. While MAID
is replaced with the MVCD the risk is still there.
2. The SDT debated a set time limit. The team could not find a time that would fit all situations. Intentional would apply if a TO withheld notification
after having confirmed that risk conditions exist.
3. The SDT removed the vague language.
4. There are opportunities for double jeopardy between R1/R2 and R7 without this language. The occurrence of double jeopardy has not been born
out.
Saurabh
Saksena
National Grid
1
Negative
Michael
Schiavone
Niagara Mohawk
(National Grid
Company)
3
Negative
1. The recent addition of a centerline distance to edge of Active ROW is not acceptable to
National Grid. In many areas we use design standards that allow a much lesser ROW width
with no compromise to “cleared width” or tree related reliability of the line. Instead of using
the term “Centerline” as referenced on Table 3, the use of “outer phase” or “phase closest
to tree line” would be more appropriate. 2. National Grid also has issues with the term
"easements" in the definition and seek clarification on several questions - is there a reason
the Active ROW only includes easements, not fee ownership, license or some other right to
occupy and manage the ROW? Would Active ROW include “danger tree rights” on land?
Response: 1&2. The SDT thanks you for your comments. Based on your comment and others, the , the SDT has re-established the concept of an
Active Transmission Line ROW by changing the definition of Right of Way with the same principles which was almost universally accepted by
industry. After thorough analysis of potential modifications to Table 3 and other alternatives, the team found no specific, prescriptive, or formulaic
language which can be applied across the US, Canada and Mexico, thus the team reverted to the Active Transmission Line ROW, removed Footnote
2 and Table 3.
Claudiu
GDS Associates, Inc.
1
Negative
All comments have been included in the NERC comment form.
2
Voter
Entity
Segment
Vote
Comment
Cadar
Response: Please refer to the SDT responses on the comment form.
Michael
Gammon
Kansas City Power &
Light Co.
1
Negative
Scott
Heidtbrink
Kansas City Power &
Light Co.
5
Negative
Although the proposed FAC-003 standard has many improvements and advancements that
are desirable over the existing FAC-003 standard, the handling and treatment of
encroachments as proposed without consideration of recognizing an organizations efforts in
responding to an encroachment situation makes this proposal less desirable and is a major
concern regarding the risk that the associated penalties and assessments place on
organizations.
Response: The SDT thanks you for your comments. Zero tolerance for vegetation caused outages is a stated goal of FERC and NERC as it relates to
this standard. Quote from NERC:
Vegetation Management — While four transmission outages due to vegetation occurred in a single afternoon five years ago, preliminary data suggests that only six such
outages occurred in the first six months of 2008 – none of which caused customers to lose power. Transmission line outages due to vegetation contact are still a cause for
concern, however, and this remains a top priority for NERC. Through its standards and compliance enforcement, NERC now has a zero-tolerance policy in place, where the
goal is to correct issues that may arise long before any customers are affected.
This policy is part of FAC-003-1 and in concept did not change with the proposed version. The SDT recognizes this concern and has developed
gradation taking into account line criticality in VRF’s and type of outage not contained in the current version FAC-003-1. Finally, It is also important
to note that each and every incident or potential violation is investigated and addressed based on the specific circumstances surrounding the
particular event. These investigations should necessarily take into consideration and recognize the utility's individual efforts in responding to an
encroachment situation.
Thomas R.
Glock
Arizona Public Service
Co.
3
Negative
APS supports retention of FAC-003-1 as currently effective, as it is working well for the
industry. APS does not support a change to this standard for the following reasons: o The
minimum clearances must be sufficient to avoid any sustained vegetation-related outages
for all applicable conditions. ? . ? Clearance 1 should remain in the standard as it ensures
clear direction to the utility on how the system is to be maintained, and provides assistance
to the Transmission Owners in dealings with federal land agencies on vegetation
management issues. Elimination of the discretion in clearance 1 will significantly degrade
this support. ? ANSI-A300 should remain in the standard. Though simply a footnote in the
currently effective version, ANSI-A300 should be a requirement in the standard. Relevant
Registered Entities should be held to following ANSI A-300 standards and BMP’s for best
management practices. o APS does not agree with the removal of ‘fill in the blank’
components where the Transmission Owner determines the requirement with no limits or
direction. Examples include and “personnel requirements” in version 1. The SDT removed
this requirement from the current version. ? Personnel qualifications should be remain a
requirement. The standard should recognize certification programs through the
International Society of Arboriculture that certify a minimum level of competence to manage
3
Voter
Entity
Segment
Vote
Comment
a vegetation management program which required ongoing training and education to keep
up with the latest technologies on UVM. ? There are other standards that require
qualifications and training. ? The revised standard dilutes accountability for maintaining the
full width of utilities easement. The active ROW should be wide enough to prevent outages
caused by grow-in and blow-in events. ? The changes to R1, allowing a real-time
observations to evidence encroachments, does not take into account all rated conditions
and the time the recording was made. Real-time observations will not account for changing
conditions and increase in load. Available technologies, such as LIDAR, can simulate allrated conditions, contour and tree height to remove these potential trees hazards before an
outage occurs. ? The utilities should be required to inspect all the lines annually. ? The
standard should include a footnote that provides that a utility will not be held accountable
for not completing its annual work plan if federal or state agencies fail to approve annual
work plans within 90 days of submittal, or that takes into account the time it takes the
utility to get approval.
Response: Thank you for your comments.
•
The SDT is changing the Standard in response to the SAR. The success of the existing standard will be preserved and enhanced with this
revision.
•
If vegetation is maintained as required in this draft of the standard in requirements R1 and R2, then no vegetation-related sustained outages,
caused by vegetation from within the ROW, within the control of the TO can occur.
•
Clearance 1 was a fill-in the blank requirement and did not provide the TO any new easement rights, or land permit rights across any lands
whether those land be privately owned or publicly owned; therefore Clearance 1 remains removed from this draft. Furthermore, the relevance
of Clearance 1 depends on several other factors such as length of maintenance cycles, inspection frequency and growth rates. R3 is now
used as a more comprehensive method to address these concerns in lieu of a Clearance 1 requirement.
•
In order to meet the SAR FAC-003 is required. ANSI-A300 is not sufficient to meet the SAR requirements and contains many elements that do
not need to be related to transmission system electrical reliability.
•
The SDT suggests that the submittal of a NERC SAR on the PER standards be considered to address any proposed personnel qualifications,
certifications or training issues.
•
The SDT is following NERC guidelines as they understand them.
•
The SDT has re-established the concept of an Active Transmission Line ROW by changing the definition of Right of Way with the same
principles which was almost universally accepted by industry. Outages arising from vegetation from outside the ROW are not violations of
the standard. The SDT had determined this to be the most appropriate assignment of an area of maintenance responsibility considering the
numerous variations in easements and permit rights across North America.
•
The Standard requires the maintenance to be performed such that loading to Rating and Rated Conditions, and the dynamics of sag and
sway are taken into consideration. Additionally any real time observations of encroachments into the MVCD are to be reported as violations
of the standard. The SDT does not see the need to be prescriptive as to the technology or tools the TO used to be compliant with the
Standard, but is confident that if the vegetation in maintained such that no encroachments are ever observed, and no outages are ever occur,
then the reliability purpose of the standard will be fully accomplished. Furthermore, the results from a LIDAR survey are temporal in nature.
4
Voter
Entity
Segment
Vote
Comment
Any program relying on LIDAR would incur a substantial cost with a long term commitment that may not be justified for many Transmission
Owners.
•
FERC requested a defined period for inspection. The SDT agrees with you that annual inspection is required. Therefore the SDT has made
annual inspections a Requirement of this Standard. As to all lines versus applicable lines, FERC has accepted the 200 kV bright line for this
standard. They did order the SDT to ensure that no sub-200 kV lines that are important to the Bulk Electric System are missing from the
Applicability of the standard. The SDT has incorporated a FERC accepted test (as found in the referenced Standard) to make sure no such
important lines are missing.
•
The SDT agrees that erroneous obstacles to compliance with the standard should be addressed. However, they cannot be resolved in this
forum, or through language inserted in this standard. This Standard places requirements on the Transmission Owners, not on landowners.
There is no legal mechanism for this Standard to take rights from property owners and assign them to the Transmission Owner.
John J.
Moraski
Baltimore Gas &
Electric Company
1
Negative
BGE feels that the new standard does nothing to improve reliability over the existing
standard. Furthermore, it could be argued that it potentially diminishes reliability, based on
the new MVCD vs. Clearance 2 guidelines. It also includes requirements which could be
perceived as being more confusing than the existing requirements in the current standard,
e.g., the Active Right-of-Way, Calendar Year Inspections, etc. The new standard, If
adopted, would almost certainly require a complete restructuring of all TVMPs and related
compliance processes, with no commensurate value-added for individual utilities or the
industry in general. In addition, it would do little to enhance the overall intent of the
standard, which is to improve vegetation-related transmission reliability in North America.
Response: The SDT thanks you for your comments. The SDT believes the proposed version addresses concerns outlined in FERC Order 693 and
improves reliability of the BES. The industry overwhelmingly agrees the MVCD based on the Gallet Equation is superior to that of the Clearance 2
fill-in the blank requirement in the current version and in fact can be a greater distance depending on the basis used for Clearance 2 determination.
Based on your comment and others, the SDT has re-established the concept of an Active Transmission Line ROW by changing the definition of Right
of Way with the same principles which were almost universally accepted by industry. After thorough analysis of potential modifications to Table 3
and other alternatives, the team found no specific, prescriptive, or formulaic language which can be applied across the US, Canada and Mexico, thus
the team reverted to a ROW definition, removed Footnote 2 and Table 3. While it is true that any change to the standard may result in changes to
current documentation of practices and procedures (such as the TVMP), the SDT believes changes will be minor and be an improvement.
5
Voter
Paul Rocha
Entity
CenterPoint Energy
Segment
Vote
Comment
1
Negative
CenterPoint Energy believes the proposed FAC-003-2 is not a performance-based standard,
despite being labeled as such, because it remains too focused on processes and procedures.
CenterPoint Energy fails to see much difference in the approach from the current Standard.
CenterPoint Energy believes a performance based requirement would provide performance
criteria that an entity would be measured against. An example of a performance based
requirement would be the following: R1. “Each Transmission Owner shall manage
vegetation to prevent encroachment that results in no more than one (1) Sustained Outage
per XXX circuit miles of applicable lines within any twelve (12) month period.” M1. Each
Transmission Owner has evidence that it had no more than one (1) Sustained Outage per
XXX circuit miles of applicable lines within any twelve (12) month period. Examples of
acceptable forms of evidence may include dated reports of vegetation-related Sustained
Outages or dated attestations as to no vegetation-related Sustained Outages have occurred.
Response: The SDT thanks you for your comments. FAC-003-2 is a “results based standard” (RBS) with a stated objective to prevent outages that
could lead to cascading. Any requirement that has an allowance for a certain number of outages does not meet that objective.
Russell A
Noble
Cowlitz County PUD
3
Negative
Cowlitz votes negative with reluctance over two items: 1. Requirement R4 has a qualitative
nature in the statement “without intentional time delay” which will leave room for subjective
judgment on the part of the auditor in determining intent or the state of mind of the
Transmission Owner. Cowlitz understands the need to communicate to the control center a
vegetation condition that may cause a Fault at any moment as soon as possible. In this
light, it is not possible to set a quantitative time limit for this report to occur for all
occasions. In one scenario, a very short time limit may be arguable due to the proximity of
available radio/telephone communications. However, in another remote situation it may
take up to several hours to access communication equipment after discovery. Compounding
the problem is the need to document the time of day versus location progress of the
vegetation inspector to establish a discovery time stamp; this is not covered in M4. Cowlitz
suggests the following changes (see standards VAR-002-1, IRO-006-3, TOP-003-0, TOP-
6
Voter
Bob Essex
Entity
Cowlitz County PUD
Segment
Vote
Comment
5
Negative
007-0 for similar verbiage): R4. Each Transmission Owner shall notify the control center
holding switching authority for the associated transmission line when qualified personnel
confirm the existence of a vegetation condition that is likely to cause a Fault at any moment
as soon as possible, but no longer than one hour with the following exception: In areas
where communication with the control center is not possible within one hour due to lack of
radio/telephone service, the Transmission Owner shall document these areas along with the
reasonable time frame for reaching radio/telephone service. 2. Cowlitz agrees with United
Illuminating in that R7, as proposed, requires a VMP to be completed to ensure no
encroachment occurs. The Supplemental Reference for R7 does not describe the
requirement of the annual vegetation work plan to ensure no vegetation encroachments
occur within the MVCD. The Reference states the requirement is established to diminish the
risk of encroachment; very different from ensuring no encroachment. In the reference for
R7 the word “ensure” is only used to describe that flexibility in the VMP is allowed to ensure
the reliability of the Transmission System. M7 is measuring work plan completion not the
prevention of encroachment. United Illuminating and Cowlitz suggest that R7 be changed
to: Each Transmission Owner shall complete the work in an annual vegetation work plan to
manage the prevention of vegetation encroachments occur within the MVCD. In this way, a
violation of R1/R2 does not necessarily mean R7 is violated. The entity does not avoid a
penalty for an encroachment because a violation of R1/R2 occurs for actual encroachment.
If an encroachment occurs the compliance enforcement authority can review the entities
vegetation management plan to determine if it is compliance with R7/M7.
Response: The SDT thanks you for your comments.
1. The time required by the TO to report an issue is subject to many variables such as available communication for the area which could be a
hike-in location with no radio or cell phone coverage. For this reason it is difficult to establish a time period which would fairly apply to all
TO’s.
2. Please refer to the following responses to questions (which are responsive to your reference to your conncurrence with the United
Illuminating):
Question 1: Comment 12
Question 5: Comment 6
Question 6: Comment 44
Question 7: Comment 14
Question 8: Comment 39
7
Voter
Jason L.
Murray
Entity
Segment
Vote
Alberta Electric System
Operator
2
Negative
Comment
Due to slow vegetation growth rates in many parts of Alberta, not all transmission right-ofways require annual inspection as required in R6. TOs should be able to include planned
inspection cycles in their Transmission Vegetation Management Plan.
Response: Thank you for your comment. For the sake of consistency for all applicable entities, the SDT believes that an annual inspection
complements the required annual work plan. The standard allows for both maintenance inspections and vegetation inspections to be performed
concurrently. Additionally, annual inspections are useful to not only track growth, but also other potential issues such as identifying danger trees,
landslides, erosion, and tree damage caused by animals.
Ralph
Frederick
Meyer
Empire District Electric
Co.
1
Negative
EDE agrees with the concers raised by United Illuminating and therefore also provides the
following comments related to R7 and R4 for FAC-003-2. R4: The use of intentional time
delay is a qualitative attribute and not a quantitative measure. It will lead to endless
arguments over intentional versus non-intentional. EDE agrees with UI's comment: "In R4
the phrase: without any intentional time delay, is a concern. There is a time line between
identification and reporting of an imminent hazard that represents the minimal time
required to complete this Requirement. Any situation where the time between observation
and reporting is greater than this minimal time line indicates a time delay occurred. It will
be left to the compliance enforcement authority to determine if this delay was intentional or
not. It is not proper for the test to be based on Intentional versus Non-Intentional. Using
other synonyms such as reasonable, expeditious, prompt, immediate or without hesitation
all introduce a qualitative not a quantitative attribute to the measurement. The
Supplemental Reference for R4 indicates that the imminent threat requirement is measured
in minutes or hours; again no guidance for enforcement. R4 would be improved with an
explicit time requirement of 6 hours between observation and report. This is measurable
and clear. M4 becomes Each Transmission Owner that has a vegetation condition likely to
cause a Fault at any moment, as confirmed by qualified personnel, will have evidence that it
notified the control center holding switching authority for the associated transmission line
within 6 hours of observation." R7: R7, as proposed, requires a VMP to be completed to
ensure no encroachment occurs. The Supplemental Reference for R7 does not describe the
requirement of the annual vegetation work plan to ensure no vegetation encroachments
occur within the MVCD. The Reference states the requirement is established to diminish the
risk of encroachment; very different from ensuring no encroachment. In the reference for
R7 the word “ensure” is only used to describe that flexibility in the VMP is allowed to ensure
the reliability of the Transmission System. M7 is measuring work plan completion not the
prevention of encroachment. EDE agrees with United Illuminating suggestion that R7 be
changed to: Each Transmission Owner shall complete the work in an annual vegetation
work plan to manage the prevention of vegetation encroachments occur within the MVCD.
In this way, a violation of R1/R2 does not necessarily mean R7 is violated. The entity does
not avoid a penalty for an encroachment because a violation of R1/R2 occurs for actual
8
Voter
Entity
Segment
Vote
Comment
encroachment. If an encroachment occurs the compliance enforcement authority can review
the entities vegetation management plan to determine if it is compliance with R7/M7. EDE
also agrees with concerns raised by FMPA that Periodic data submittals as written are really
periodic self-certifications and ought to be named such, or 100% compliance reduced to a
more reasonable target
Response: Thank you for your comment. The SDT believes that it was not prudent to suggest a quantitative time element for notification in R4. The
technical reference offers examples of acceptable unintentional delays for your review. Confirmation that a threat actually exists due to vegetation is
key.
Based on comments, the language in R7 has been modified.
Robert
Martinko
FirstEnergy Energy
Delivery
1
Negative
Kevin
Querry
FirstEnergy Solutions
3
Negative
Douglas
Hohlbaugh
Ohio Edison Company
4
Negative
Kenneth
Dresner
FirstEnergy Solutions
5
Negative
Mark S
Travaglianti
FirstEnergy Solutions
6
Negative
FirstEnergy appreciates the hard work of the drafting team, but unfortunately we must cast
a Negative vote for the standard as written. If the SDT agrees with our comments below
and makes the suggested changes, we will consider supporting this standard in the
recirculation ballot. In the latest Draft 4, the SDT added a Table 3 titled "Minimum Distance
from the Centerline of the Circuit to the edge of the active transmission line ROW". We do
not support the addition of Table 3 because we believe it adds unnecessary prescriptiveness
to the requirements. It is also not clear if this Table was intended to be mandatory because
the only reference in the table is in Footnote #2. Furthermore, the SDT did not offer any
rationale for the minimum distances shown. If the SDT feels this table is a useful tool that
should be included in the standard, then we suggest adding it to the Guidelines and
Technical basis section as optional information with a discussion of the basis for the values
chosen. The standard being balloted includes an R1 and R2 detailing requirements for
managing vegetation. In addition, the SDT has asked for industry feedback on an alternate
R1/R2 through the comment form which may lead to changes to the standard after this
initial ballot. FirstEnergy supports the alternate R1/R2 but as we stated in the comment
form, we still need to see the final verbiage of the alternate R1/R2 along with their
associated measures M1 and M2 which have not yet been developed. Therefore, we cannot
support the standard until the alternate R1, R2, M1 and M2 are developed.
Response: Thank you for your comment. In response to comments regarding the addition of the “Minimum Distance from the Centerline of the
Circuit to the edge of the active transmission line ROW” Table 3, the SDT agrees to remove this table and use the new definition of Right of Way.
Additionally, language in M1/M2 has been modified based on comments received.
9
Voter
Frank
Gaffney
Entity
Florida Municipal
Power Agency
Segment
Vote
Comment
4
Negative
My biggest problem is with R1 and R2 "Each Transmission Owner shall manage vegetation
to prevent encroachment that could result in a Sustained Outage of applicable lines ....
Types of encroachment include: 1. An encroachment into the Minimum Vegetation
Clearance Distance (MVCD) as shown in Table 2, observed in real time, absent a Sustained
Outage, 2. An encroachment due to a fall-in from inside the active transmission line ROW
that caused a vegetation-related Sustained Outage, 3. An encroachment due to blowing
together of applicable lines and vegetation located inside the active transmission line ROW
that caused a vegetation-related Sustained Outage, 4. An encroachment due to a grow-in
that caused a vegetation-related Sustained Outage" One fundamental problem with all the
standards is the demand for no faults, no errors, 100% compliance. Requirements 1 and 2
basically say that any vegetation related outage, except for blow ins from outside the ROW,
is a violation. A few issues with this: How would we "prove" that an outage is vegetation
related or not, and if vegetation related, where the vegetation came from? Would this be a
"guilty until proven innocent" paradigm, e.g., if we don't know what the cause was, then we
assume guilty, or an "innocent until proven guilty" paradigm, e.g., clear evidence is needed
to prove guilt? Current compliance monitoring and enforcement methods are to assume
guilt with the need for clear evidence of innocence until a hearing is requested, at which
point the paradigm is reversed. If this is how we expect it to happen? I could see a large
number of "Possible" and "Alleged" violations where the cause of the sustained outage or
the source of the vegetation is unknown, and a large number of hearings, unless we begin
with the paradigm with "innocent until proven guilty", which is not the approach monitoring
and enforcement take currently. The requirement and the measures do not match. The
requirement is to "manage". Sometimes a well managed environment can still fail. The
measures are "failures". If the measures are failures and any failure is a violation, then, the
requirement should be to "prevent" not to "manage". Staff's proposed VSLs highlight this
inconsistency. The 100% compliance requirement, as opposed to a statistical measure such
as 99.99% availability, and Measures that say that any Sustained Outage is a possible
violation unless proven otherwise leads us to extreme methods of management, such as
possibly having video cameras monitoring the ROW at all times. Is this what the Drafting
Team intends? FMPA would suggest that if perfromance is the real purpose of these
standards, then "manage" is the wrong requirement, and "prevent" is a more appropriate
term. If prevention is the real requirement, then we need a paradigm of "innocent until
proven guilty" and any unknown source of a sustatined outage is assumed not to be a
vioaltion until proven guilty, and, 100% is not a reasonable target, 99.99% or similar umber
over a number of years (e.g., so many years rolling average) is a more reasonable target.
Do we require 100% compliance with vehicle brakes (ala Toyota Prius)? Or tire blowouts
(ala Ford Explorer)? With associated fines? If we did, the auto manufacturers would
probably not offer cars to the American market due to too much risk and liability. TQM (total
10
Voter
Entity
Segment
Vote
Comment
qulaity management) processes, such as six sigma (i.e., 6 standard deviations) do not
mandate 100% reliability becuase 100% reliability is too expensive. Rather, we need a
conservative target where outliers beyond regional management controls do not result in
huge fines and huge liability (especially in consideration with FERC's proposed Policy
Statement on Sanctions) R4 "Each Transmission Owner, without any intentional time delay,
shall notify the control center holding switching authority for the associated transmission
line when qualified personnel confirm the existence of a vegetation condition that is likely to
cause a Fault at any moment" How is R4 even measureble? How are we to measure how
someone would determine "the existence of a vegetation condition that is likely to cause a
Fault at any moment"? Having the requirement in the standard may have the unintended
consequence of reverse psychology e,g., not notifying may not even open up the question
of compliance with this requirement. However, if a sustained outage were to occur as a
result violating R1 or R2, would this requirement necessitate launching an investigation of
whether or not "qualified" personnel would have seen a problem. I see this requirement as
fraught with difficulties. Would this requirement essentially require a procedure for
"detecting" in R3 in addition to "preventing" If 100% compliance is the chosen method for
R1 and R2, why is R4 (and R5 for that matter) even needed? Obviously, if there is an
impending failure that would cause a vioaltion of R1 and R2, then there is obviously
incentive to report it to the System Operator. R7 "Each Transmission Owner shall complete
the work in an annual vegetation work plan to ensure no vegetation encroachments occur
within the MVCD. Modifications to the work plan in response to changing conditions or to
findings from vegetation inspections may be made and documented provided they do not
put the transmission system at risk of a vegetation encroachment. Examples of reasons for
modification to annual plan may include ...." The first sentence should not include the
phrase "to ensure no vegetation encroachments occur" since the requirement is to do the
work in the work plan. The added phrase sinply adds ambiguity, e.g., if there is an
encroashment, is R7 violated since it does not meet hte "unsure" phrase in addition to R1
and R2? Periodic Data Submittals Due to R1 and R2, this is really a self-certification process
because essentially only violations to R1 and R2 as curently drafted would be reported. So,
this section should be deleted in favor of a CMEP process for periodic self-certifications on
the standard.
Response: Thank you for your comments. Based on recommendations, the language in M1/M2 has been modified. Proof that an outage was
vegetation related will be determined through the investigation of the outage. If clear evidence as determined by the Transmission Owner exists, the
entity would then self-report. R4 exists to ensure that “expeditious communication between the Transmission Owner and proper operating personnel
when a critical situation is confirmed.” This situation does not necessarily imply a violation of R1 and R2. The intent is to minimize the risk of an
event that could cause a cascading event. Regarding the inclusion of the phrase “to ensure no vegetation encroachments occur” in R7, the intent of
the SDT is to include language to indicate who should do what when, where, and why as part of the Results Based Standards format.
11
Voter
Silvia P
Mitchell
Entity
Florida Power & Light
Co.
Segment
Vote
Comment
6
Negative
NextEra Energy, Inc believes that this standard is a step in the right direction; however, it is
not ready for ballot. The posted version uses the Measures and Compliance sections to
define and interpret Requirements. The Requirements should stand by themselves. This
version of the standard lumps grow-in violations with fall-in and blow-in violations. Fall-in
and grow-in violations have no correlation to the cascading events stated in the purpose.
We believe it needs more work before ballot approval.
Response: The SDT thanks you for your comment. The SDT modified R1 and R2 to incorporate the severity into the requirement. This will allow for a
graded VSL. The team also modified the measure so that it does not qualify the requirement. These changes should resolve your issues.
Larry E
Watt
Lakeland Electric
1
Negative
o The draft standard requires perfection, which is an unreasonable performance metric o
The standard is prone to arguments of whether or not an outage was caused by vegetation
encroachment in the current "guilty until proven innocent" paradigm we are currently in o
Are the requirements measurable (e.g., R4 and R5)? o Goals of requirements should not
be mixed with the requirement itself. Goals add ambiguity of what is being measured, the
requirement (e.g., "complete the work plan" in R7) or the goal (e.g., "ensure no vegetation
encroachment occurs"). o Periodic data submittals as written are really periodic selfcertifications and ought to be named such, or 100% compliance reduced to a more
reasonable target
Response: The SDT thanks you for your comments. The SDT recognizes that the Standard as written is zero tolerance and believes it is compelled to
write it that way. FERC staff and NERC assert that a revised standard cannot result in less reliability than the one it replaces, and, their belief is the
current Standard is zero tolerance. The SDT believes that R4 and R5 are measurable as described. The RBS process is essentially “Who should
perform What actions under What conditions.” Thus the Goals are included. Finally, FERC would prefer to have early warnings that reliability is at
risk, rather than wait for that indication when the next blackout occurs. Hopefully, periodic data offers that early warning detection.
David H.
Boguslawski
Northeast Utilities
1
Negative
Our main issue is with the change in the Active ROW definition. The recent addition of a
centerline distance to edge of Active ROW is not acceptable as it does not take into
consideration the construction of the line (e.g., mono-pole vs. H-frame). For mono-pole
construction, the use of the Table 3 centerline distance could result in additional clearing of
the forested edge on existing ROWs with no value added to system reliability. Instead of
using the term "Centerline" as referenced on Table 3, the use of "outer phase" or "phase
closest to tree line" would be more appropriate.
Response: The SDT thanks you for your response. Due to many commenters having issues with trying to define a “minimum” width, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way subsequently the definition of Active
Transmission Line Right of Way and Table 3 have been removed.
Mace
Hunter
Lakeland Electric
3
Negative
Perfection is not a reasionable performance metric
Response: The SDT thanks you for your comment. The SDT recognizes that the Standard as written is zero tolerance and believes it is compelled to
12
Voter
Entity
Segment
Vote
Comment
write it that way. FERC staff and NERC assert that a revised standard cannot result in less reliability than the one it replaces, and, their belief is the
current Standard is zero tolerance.
Brenda L
Truhe
PPL Electric Utilities
Corp.
1
Negative
Please refer to the Comments submitted by Earl Burnside, PPL Electric Utilities, via the NERC
Comment Form on 7/16/2010.
Response: See responses to Earl Burnside, PPL Electric Utilities.
Mark A.
Heimbach
PPL Generation LLC
5
Negative
Please refer to the comments submitted by Earl Burnside, PPL Electric Utilities, on 7/16/10.
Response: See responses to Earl Burnside, PPL Electric Utilities.
John C.
Collins
Platte River Power
Authority
1
Negative
Terry L
Baker
Platte River Power
Authority
3
Negative
PRPA appreciates the SDT’s reliability objective through a defense-in-depth strategy and the
improvements made to the standard since its last posting. However, several issues will
cause us to vote negative. Our first concern is that a violation caused by an encroachment
into the Minimum Vegetation Clearance Distance as shown in Table 2, observed in real time,
absent a Sustained Outage does not improve reliability of the BES. Instead we believe the
clearances to be achieved in the current version of the standard under R1.2. are a better
measurement of expectations because they establish a clearance to be achieved at the time
of work. Our next concern is with the ambiguity of the wording “without any intentional
time delay” in R4 of the proposed standard. For instance, would a call from the lineworkers
to his/her supervisor prior to a call to the control center constitute an intentional delay or
would that be part of the confirmation process? We also question what constitutes qualified
personnel in R4. Does this imply that R1.3. in the current standard requiring appropriate
qualifications and training is still applicable although not implicated stated and will those
qualifications be audited as they are now? Our last concern is that landowners will
intentionally constrain and delay work through court orders pointing to our Federal
requirement to take corrective action. We know this isn’t the intent of the requirement but
have some concern that it might be misinterpreted by landowners as their defense to force
us to investigate or perform alternate work methodology.
Response: Thank you for your comments. While the SDT has struggled with the issue of encroachments into the MVCD being a violation, the fact
that a TO would allow vegetation to approach, let alone encroach the MVCD indicates a serious flaw in the TO’s vegetation management program and
its application. The TO has every right and should under the proposed standard establish clearance distances at the time of work (Clearance 1 in
FAC-003-1) to allow for growth. With regard to Clearance 1 of version 1 the SDT considered it a “fill in the blank” requirement. Thus, including it in
version 2 was considered prescriptive and unnecessary.
The time required by the TO to report an issue is subject to many variables such as available communication for the area which could be a hike-in
location with no radio or cell phone coverage. For this reason it is difficult to establish a time period which would fairly apply to all TO’s. Thus, the
SDT has taken the approach which does create some subjectivity. With regard to your question regarding a call from a line worker to a supervisor
being viewed as intentional delay, we would need to know if this call is part of your process for reporting imminent threats. If your process has this
13
Voter
Entity
Segment
Vote
Comment
check point or the flexibility for the lone worker to call a supervisor, then the SDT would not view this as an intentional delay.
Qualified personnel is a function of many variables such as the size of the TO’s system, type and density of vegetation, access and complexity of the
vegetation management program. All these factors will drive the qualification requirements as defined by the TO for personnel developing and
administering the program. For instance a TO with little vegetation on its ROW may require little in the way of knowledge and methodologies in
meeting this standard while those TO’s with extensive and significant vegetation must use varied methodologies to control vegetation on its ROW
such as mechanical control, manual control, herbicides and so on. Thus, the standard leaves it to the TO to define what defines qualified personnel.
Refer to the reference document for more guidance.
As you point out, it is not the intent of this standard to cause the landowner to intentionally constrain and delay work. But, it is also not the intent of
the standard to drive the land owner or land manager to any other behaviors. It is the TO’s responsibility to manage relationships and develop
methodologies within and to the full extent of the easement or permit language. Requirement R5 deals with this issue and additional clarification is
given in the Rationale for this requirement.
David
Schumann
Florida Municipal
Power Agency
5
Negative
R1 & R2 My biggest problem is with R1 and R2 "Each Transmission Owner shall manage
vegetation to prevent encroachment that could result in a Sustained Outage of applicable
lines .... Types of encroachment include: 1. An encroachment into the Minimum Vegetation
Clearance Distance (MVCD) as shown in Table 2, observed in real time, absent a Sustained
Outage, 2. An encroachment due to a fall-in from inside the active transmission line ROW
that caused a vegetation-related Sustained Outage, 3. An encroachment due to blowing
together of applicable lines and vegetation located inside the active transmission line ROW
that caused a vegetation-related Sustained Outage, 4. An encroachment due to a grow-in
that caused a vegetation-related Sustained Outage" One fundamental problem with all the
standards is the demand for no faults, no errors, 100% compliance. Requirements 1 and 2
basically say that any vegetation related outage, except for blow ins from outside the ROW,
is a violation. A few issues with this: How would we "prove" that an outage is vegetation
related or not, and if vegetation related, where the vegetation came from? Would this be a
"guilty until proven innocent" paradigm, e.g., if we don't know what the cause was, then we
assume guilty, or an "innocent until proven guilty" paradigm, e.g., clear evidence is needed
to prove guilt? Current compliance monitoring and enforcement methods are to assume
guilt with the need for clear evidence of innocence until a hearing is requested, at which
point the paradigm is reversed. If this is how we expect it to happen? I could see a large
number of "Possible" and "Alleged" violations where the cause of the sustained outage or
the source of the vegetation is unknown, and a large number of hearings, unless we begin
with the paradigm with "innocent until proven guilty", which is not the approach monitoring
and enforcement take currently. The requirement and the measures do not match. The
requirement is to "manage". Sometimes a well managed environment can still fail. The
measures are "failures". If the measures are failures and any failure is a violation, then, the
requirement should be to "prevent" not to "manage". Staff's proposed VSLs highlight this
inconsistency. The 100% compliance requirement, as opposed to a statistical measure such
14
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Comment
as 99.99% availability, and Measures that say that any Sustained Outage is a possible
violation unless proven otherwise leads us to extreme methods of management, such as
possibly having video cameras monitoring the ROW at all times. Is this what the Drafting
Team intends? FMPA would suggest that if perfromance is the real purpose of these
standards, then "manage" is the wrong requirement, and "prevent" is a more appropriate
term. If prevention is the real requirement, then we need a paradigm of "innocent until
proven guilty" and any unknown source of a sustatined outage is assumed not to be a
vioaltion until proven guilty, and, 100% is not a reasonable target, 99.99% or similar umber
over a number of years (e.g., so many years rolling average) is a more reasonable target.
Do we require 100% compliance with vehicle brakes (ala Toyota Prius)? Or tire blowouts
(ala Ford Explorer)? With associated fines? If we did, the auto manufacturers would
probably not offer cars to the American market due to too much risk and liability. TQM (total
qulaity management) processes, such as six sigma (i.e., 6 standard deviations) do not
mandate 100% reliability becuase 100% reliability is too expensive. Rather, we need a
conservative target where outliers beyond regional management controls do not result in
huge fines and huge liability (especially in consideration with FERC's proposed Policy
Statement on Sanctions) R4 "Each Transmission Owner, without any intentional time delay,
shall notify the control center holding switching authority for the associated transmission
line when qualified personnel confirm the existence of a vegetation condition that is likely to
cause a Fault at any moment" How is R4 even measureble? How are we to measure how
someone would determine "the existence of a vegetation condition that is likely to cause a
Fault at any moment"? Having the requirement in the standard may have the unintended
consequence of reverse psychology e,g., not notifying may not even open up the question
of compliance with this requirement. However, if a sustained outage were to occur as a
result violating R1 or R2, would this requirement necessitate launching an investigation of
whether or not "qualified" personnel would have seen a problem. I see this requirement as
fraught with difficulties. Would this requirement essentially require a procedure for
"detecting" in R3 in addition to "preventing" If 100% compliance is the chosen method for
R1 and R2, why is R4 (and R5 for that matter) even needed? Obviously, if there is an
impending failure that would cause a vioaltion of R1 and R2, then there is obviously
incentive to report it to the System Operator. R7 "Each Transmission Owner shall complete
the work in an annual vegetation work plan to ensure no vegetation encroachments occur
within the MVCD. Modifications to the work plan in response to changing conditions or to
findings from vegetation inspections may be made and documented provided they do not
put the transmission system at risk of a vegetation encroachment. Examples of reasons for
modification to annual plan may include ...." The first sentence should not include the
phrase "to ensure no vegetation encroachments occur" since the requirement is to do the
work in the work plan. The added phrase sinply adds ambiguity, e.g., if there is an
15
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encroashment, is R7 violated since it does not meet hte "unsure" phrase in addition to R1
and R2? Periodic Data Submittals Due to R1 and R2, this is really a self-certification process
because essentially only violations to R1 and R2 as curently drafted would be reported. So,
this section should be deleted in favor of a CMEP process for periodic self-certifications on
the standard.
Response: Thank you for your comments. Your concern with respect to the cause of an outage is well-taken. As you know, transmission systems
are subject to many different influences which can cause a sustained outage. Among those causes is the encroachment of vegetation into the MVCD
which could be due to improper maintenance of vegetation on one’s ROW. However, there are many other causes which can initiate a sustained
outage. A TO usually investigate a sustained outage in the field to determine, if possible, the cause of the outage. Typically, a vegetation caused
outage will leave some evidence of the flashover such as burn marks on the conductor together with burned portions of the vegetation. Indications
may be found to explain the outage due to other causes but in some cases the cause cannot be determined and the line is successfully re-energized
without ever knowing what caused the outage. It is incumbent upon the TO to self- report those outages obviously caused by vegetation but
unexplained outages would not fall under this requirement or standard.
The SDT believes the language in the requirement matches the language in the measure such as in R1 “Each Transmission Owner shall manage
vegetation to prevent encroachment…” and in M1 “Each Transmission Owner has evidence that it managed vegetation to prevent encroachment…”.
Your suggestion of using statistical analysis may work well with large TO’s with many miles of transmission ROW to spread small numbers of
outages over but would disadvantage the small TO with significantly fewer miles of line. Only one outage on its system could result in huge fines.
The SDT believes R4 is a valid “Risk Based Requirement” giving guidance to industry on what to do upon discovery of an encroachment into the
MVCD in order to prevent a sustained outage. The key is for the TO to communicate with the appropriate switching authority and the measure is
evidence of such communication when a potential vegetation imminent threat occurs. R7, as documented in the Rationale, “…sets the expectation
that the work identified in the annual work plan will be completed as planned”. Documentation of the work completed (and any necessary
modifications) as written together with the lack of of a violation to either Requirement 1 or Requirement 2 is the overall reliability goal. The metric for
the work plan is the percentage of the plan complete. The lack of a violation of R1 or R2 is the outcome of the ideal work plan. It is the responsibility
of the TO to manage the quality of the work plan and its associated modifications to mitigate the risk of a violation of R1 or R2. With Version 2, an
outage is now clearly a violation of R1 and R2 and should not be linked to a failure of the work plan. The measure for the work plan is the percentage
of the completed as planned and we do not need to be subjectively trying to evaluate the quality of the TOs plan with this measure. With regard to
the “Periodic Reporting Data Submittal” section the SDT agrees with reporting outage to the Regional Entity on a quarterly basis. In addition
regulatory authorities are looking for leading reliability indicators which will support quarterly reporting rather than an annual self-certification.
Kenneth
Simmons
Gainesville Regional
Utilities
3
Negative
R4 The use of intentional time delay is a qualitative attribute and not a quantitative
measure. How does one judge intentional versus non-intentional on a qualitative basis;
subjective at best leading to many arguments between auditor and auditee?
Response: Thank you for your comment. We agree the time required by the TO to report an issue is subject to many variables such as available
communication for the area which could be a hike-in location with no radio or cell phone coverage. For this reason it is difficult to establish a time
period which would fairly apply to all TO’s. Thus, the SDT has taken the approach which does create some subjectivity. The key is for the TO to have
an imminent threat process that includes the communication with the appropriate switching authority. The measure for compliance will be evidence
such as written and taped radio/telephone logs maintained by the control center; written daily diaries kept by the patrollers and inspectors could
also be used for this purpose.
16
Voter
Luther E.
Fair
Entity
Gainesville Regional
Utilities
Segment
Vote
Comment
1
Negative
R4: The use of intentional time delay is a qualitative attribute and not a quantitative
measure. It will lead to endless arguments over intentional versus non-intentional. R4
should be: Each Transmission Owner shall notify the control center holding switching
authority for the associated transmission line no more than 6 hours of a qualified personnel
confirm the existence of a vegetation condition that is likely to cause a Fault at any
moment. R7: R7, as proposed, requires a VMP to be completed to ensure no encroachment
occurs. The Supplemental Reference for R7 does not describe the requirement of the annual
vegetation work plan to ensure no vegetation encroachments occur within the MVCD. The
Reference states the requirement is established to diminish the risk of encroachment; very
different from ensuring no encroachment. In the reference for R7 the word “ensure” is only
used to describe that flexibility in the VMP is allowed to ensure the reliability of the
Transmission System. The above comments are from United Illuminating and shared by
myself. Earl
Response: Thank you for your comments. We agree the time required by the TO to report an issue is subject to many variables such as available
communication for the area which could be a hike-in location with no radio or cell phone coverage. For this reason it is difficult to establish a time
period which would fairly apply to all TO’s. Thus, the SDT has taken the approach which does create some subjectivity. The key is for the TO to have
a imminent threat process that includes the communication with the appropriate switching authority. The measure for compliance will be evidence
such as written and taped radio/telephone logs maintained by the control center; written daily diaries kept by the patrollers and inspectors could
also be used for this purpose.
R7, as documented in the Rationale, “…sets the expectation that the work identified in the annual work plan will be compiled as planned”.
Documentation of the work completed (and any necessary modifications) as written together with the lack of of a violation to either Requirement 1 or
Requirement 2 is the overall reliability goal. The metric for the work plan is the percentage of the plan complete. The lack of a violation of R1 or R2 is
the outcome of the ideal work plan. It is the responsibility of the TO to manage the quality of the work plan and its associated modifications to
mitigate the risk of a violation of R1 or R2. With Version 2, an outage is now clearly a violation of R1 and R2 and should not be linked to a failure of
the work plan. The measure for the work plan is the percentage of the completed as planned and we do not need to be subjectively trying to evaluate
the quality of the TOs plan with this measure.
David A.
Lapinski
Consumers Energy
3
Negative
Table 3 does not adequately address ROW width requirements based on the type of
construction used for structures, especially for the two lower voltage classes, 69-138kV and
17
Voter
David Frank
Ronk
Entity
Consumers Energy
Segment
Vote
Comment
4
Negative
139-230 kV. Lines constructed on H-Frame structures have a much wider footprint across
the ROW than do single pole construction and most steel tower construction types. The
minimum ROW width listed in Table 3 for a 138 kV line constructed on a wooden H-Frame
may put the outside conductor within MVCD under windy conditions due to wind
displacement of conductors and trees. Consumers Energy recommends that Table 3 be
modified to describe the minimum distance in the table is the vertical plane of the outside
conductor to the edge of the active transmission ROW and therefore independent of the
width of the structure construction type. MI and M2 fail to provide examples of acceptable
forms of evidence to prove that a Transmission Owner actively managed vegetation to
prevent encroachment into the MVCD. The Measures should require proof of active ROW
clearing activity in accordance with the transmission vegetation management plan, such as
invoicing or crew field reports or vegetation inspection data from the annual vegetation
inspection R3 avoids defining a minimum clearance specification and is not practical. As
written, this would require each Transmission Owner to define and document the
procedures, processes or specification by individual span for every line owned or operated
by the Transmission Owner. Each span varies in length and profile and a single line may
have several different conductor types with different load ratings. Line loadings will vary
along the line based on substation taps, etc. The dynamics described in the language could
only be done on an individual span basis to be reasonably accurate. This is not practical
from a planning standpoint or from a standpoint of implementing clearing work in the field.
Response: The SDT thanks you for your comments.
1) Based on your comment and others, the SDT has revised the definition of Right of Way to embody the concept of an Active Transmission
Right of Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
2) M1 and M2 do provide samples of acceptable forms of evidence. The examples you have provided in your comment would also be acceptable
forms of evidence. The SDT recognizes that there are many acceptable forms of evidence and only included three specific examples in both
Measures M1 and M2 utilizing the phrase ‘may include’ so that the list is not limited to the samples provided.
R3 specifically states that the TO shall prevent encroachment into the MVCD which is a defined minimum clearance distance, contrary to your
comment. To prevent a Sustained Outage, each TO must recognize that each transmission line is unique and establish a general plan that
encompasses each scenario. In their procedures or processes or specifications, the TO shall establish a maintenance strategy that ensures
vegetation will never violate the MVCD. This strategy should take into consideration the dynamics of vegetation growth and conductor movement as
explained in the Guidelines and Technical Basis section of the Standard (Page 21). This strategy does not necessarily require a span by span
analysis.
Bernard
Pelletier
Hydro-Quebec
TransEnergie
1
Negative
Table 3 is not acceptable for HQTE. In many places, our standard of design allow us a ROW
width much narrower. We think that Table 3 should cover only the lines operated at 200 kV
or higher. Finally, the Table 3 should not be a requirement of the FAC-003-2.
Response: Based on your comment and others, the SDT has revised the definition of Right of Way to embody the concept of an Active Transmission
Right of Way subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
18
Voter
Stan T.
Rzad
Entity
Keys Energy Services
Segment
Vote
Comment
1
Negative
The draft standard requires perfection, which is an unreasonable performance metric The
standard is prone to arguments of whether or not an outage was caused by vegetation
encroachment in the current "guilty until proven innocent" paradigm we are currently in Are
the requirements measurable (e.g., R4 and R5)? Goals of requirements should not be mixed
with the requirement itself. Goals add ambiguity of what is being measured, the
requirement (e.g., "complete the work plan" in R7) or the goal (e.g., "ensure no vegetation
encroachment occurs"). Periodic data submittals as written are really periodic selfcertifications and ought to be named such, or 100% compliance reduced to a more
reasonable target
Response: The SDT thanks you for your comments.
1. The SDT recognizes that the Standard as written is zero tolerance and believes it is compelled to write it that way because FERC staff and
NERC assert that a revised standard cannot result in less reliability than the one it replaces and their belief is the current Standard is zero
tolerance.
2. As explained in M1 and M2, only real time observations confirmed by a qualified person would constitute an encroachment. There may be
some difficulty proving whether or not an outage was caused by vegetation but, if an investigation at any time reveals definitive evidence of a
vegetation contact as determined by the Transmission Owner, this would be the proof.
3. The SDT believes that R4 and R5 are measurable as described in the Draft but would gladly accept suggestions for revision in future
postings. The RBS process essentially is “Who should do what, under what conditions, when, and why?” Thus the Goals are included.
Finally, FERC staff has stated that they would prefer to have early warnings that reliability is at risk rather than wait for that indication when
the next blackout occurs. Thus, periodic data offers that early warning detection.
Periodic data submittal is not only restricted to self-certifications so the SDT has chosen to keep the language the same as currently drafted.
Thomas W.
Richards
Fort Pierce Utilities
Authority
4
Negative
The draft standard requires perfection, which is an unreasonable performance metric. Also,
the standard is prone to arguments of whether or not an outage was caused by vegetation
encroachment in the current "guilty until proven innocent" paradigm we are currently in. I
have the question about the ability to measure compliance with R4 and R5 as written. Goals
of requirements should not be mixed with the requirement itself. Goals add ambiguity of
what is being measured, the requirement (e.g., "complete the work plan" in R7) or the goal
(e.g., "ensure no vegetation encroachment occurs"). Periodic data submittals as written are
really periodic self-certifications and ought to be named such, or 100% compliance reduced
to a more reasonable target
Response: The SDT thanks you for your comments.
1. The SDT recognizes that the Standard as written is zero tolerance and believes it is compelled to write it that way because FERC staff and
NERC assert that a revised standard cannot result in less reliability than the one it replaces and their belief is the current Standard is zero
tolerance.
2. As explained in M1 and M2, only real time observations confirmed by a qualified person would constitute an encroachment. There may be
19
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Comment
some difficulty proving whether or not an outage was caused by vegetation but, if an investigation at any time reveals definitive evidence
of a vegetation contact as determined by the Transmission Owner, this would be the proof.
3. The SDT believes that R4 and R5 are measurable as described in the Draft but would gladly accept suggestions for revision in future
postings. The RBS process essentially is “Who should do what, under what conditions, when, and why?” Thus the Goals are included.
Finally, FERC staff has stated that they would prefer to have early warnings that reliability is at risk rather than wait for that indication
when the next blackout occurs. Thus, periodic data offers that early warning detection.
4. Periodic data submittal is not only restricted to self-certifications so the SDT has chosen to keep the language the same as currently
drafted.
Thomas E
Washburn
Florida Municipal
Power Pool
6
Negative
The draft standard requires perfection, which is an unreasonable performance metric The
standard is prone to arguments of whether or not an outage was caused by vegetation
encroachment in the current "guilty until proven innocent" paradigm we are currently in Are
the requirements measurable (e.g., R4 and R5)? Goals of requirements should not be mixed
with the requirement itself. Goals add ambiguity of what is being measured, the
requirement (e.g., "complete the work plan" in R7) or the goal (e.g., "ensure no vegetation
encroachment occurs"). Periodic data submittals as written are really periodic selfcertifications and ought to be named such, or 100% compliance reduced to a more
reasonable target
Response: The SDT thanks you for your comments.
1. The SDT recognizes that the Standard as written is zero tolerance and believes it is compelled to write it that way because FERC staff and
NERC assert that a revised standard cannot result in less reliability than the one it replaces and their belief is the current Standard is zero
tolerance.
2. As explained in M1 and M2, only real time observations confirmed by a qualified person would constitute an encroachment. There may be
some difficulty proving whether or not an outage was caused by vegetation but, if an investigation at any time reveals definitive evidence
of a vegetation contact as determined by the Transmission Owner, this would be the proof.
3. The SDT believes that R4 and R5 are measurable as described in the Draft but would gladly accept suggestions for revision in future
postings. The RBS process essentially is “Who should do what, under what conditions, when, and why?” Thus the Goals are included.
Finally, FERC staff has stated that they would prefer to have early warnings that reliability is at risk rather than wait for that indication
when the next blackout occurs. Thus, periodic data offers that early warning detection.
4. Periodic data submittal is not only restricted to self-certifications so the SDT has chosen to keep the language the same as currently
drafted.
Laurie
Williams
Public Service
Company of New
Mexico
1
Negative
The draft standard suggests that the expectation for compliance is perfection or zero
encroachments at all times. It would be cost prohibitive to maintain the system under those
rules and should be amended to include a provision to account this issue - particularly for
small utilities that operate over very large geographic region with sparsely distributed
20
Voter
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Comment
transmission assets.
Response: The SDT thanks you for your comments. The SDT recognizes that the Standard as written is zero tolerance and believes it is compelled to
write it that way because FERC staff and NERC assert that a revised standard cannot result in less reliability than the one it replaces and their belief
is the current Standard is zero tolerance.
Matt
Culverhouse
City of Bartow, Florida
3
Negative
The proposed standard requires perfection which we feel is unreasonable.
Response: The SDT thanks you for your comments. The SDT recognizes that the Standard as written is zero tolerance and believes it is compelled to
write it that way because FERC staff and NERC assert that a revised standard cannot result in less reliability than the one it replaces and their belief
is the current Standard is zero tolerance.
Robert D
Smith
Arizona Public Service
Co.
1
Negative
The reasons for APS to vote NO. The standard drafting team went above and beyond
and changed the whole standard and didn’t address all of FERC’s concerns.
(0) The minimum clearances must be sufficient to avoid any sustained vegetation-related
outages for all applicable conditions.
(1) The team eliminated clearance 1 requirement which isn’t addressed in this revision
according to FERC’s request. FERC wanted this requirement to be standardized. Elimination
of clearance 1 doesn’t give utilities leverage when dealing with federal land agencies. They
are making decisions without any education or knowledge on UVM activities which affect
transmission reliability. There needs to be a clearance 1 requirement in the standard. If
utilities are required to follow this standard it gives them leverage with dealing with these
federal land agencies.
(2) They removed ANSI-A300 from the standard. It was a footnote but should be part of the
standard. Utilities should be held to following ANSI A-300 standards and BMP’s for best
management practices. By following these standards there wouldn’t be a need for the FAC003 standard.
(3) Removal of ‘fill in the blank’ components where the Transmission Owner determines the
requirement with no limits or direction. Examples include and “personnel requirements” in
version 1. The SDT removed this requirement from the current version. ? Personnel
qualifications should be a requirement. There are certification programs through the
International Society of Arboriculture that certify a minimum level of competence to manage
a vegetation management program. This also requires ongoing training and education to
keep up with the latest technologies on UVM. ? There are other standards that require
qualifications and training.
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(4) Application of new NERC Drafting Team Guidelines (DTG) to the standard. Examples
include the replacement of the current compliance section with Violation Risk Factors (VRFs)
and Violation Severity Levels (VSLs) as referenced in the Sanction Guidelines. Additionally,
documentation and implementation elements are separated into different requirements in
the proposed standard as required by the DTG.
(5) This requirement in regard to outages from within the ROW was diluted to remove
accountability from maintaining the full width of utilities easement. An outage is an outage
from a grow-in or from a blow in. If a utility has rights to maintain vegetation there
shouldn’t be any outages due to vegetation from blowing into the conductors. The active
ROW should be wide enough to prevent these types of outages.
o Address the applicability and appropriateness of IEEE 516 in determining clearance
distances. ? No issues with the change to Gallet equation. ?
The issue is each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of evidence
may include dated attestations, dated reports containing no Sustained Outages associated
with encroachment types 2 through 4 above, or records confirming no Real-Time
observations of any MVCD encroachments. ?
(6) A real-time observation doesn’t take into account all rated conditions and the time the
recording was made. Conditions change and if load is increased those previous observations
could be potential outages. I would assume our Energy Control people would want to be
confident there wouldn’t be any tree-related issues if load had to be increased. ? There is
technology available with LIDAR to simulate all-rated conditions, contour and tree height to
remove these potential trees hazards before an outage occurs.
o Address applicability of this standard to sub 200kV lines that could place the grid at an
unacceptable risk of instability, separation, or cascading failures. ?
(7)The utilities should be required to inspect all the lines annually. The change isn’t what
FERC requested.
o Address applicability to federal lands. ?
22
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Comment
(8)There should be a footnote that if federal or state agencies fail to approve annual work
plans within 90 days of submittal the utility will not be held accountable for not completing
its annual work plan or taking into account the time it takes to get approval. We have land
agencies that give us approvals within 2 weeks and others that have taken over a year.
Utilities are at their mercy on the approval process. If there is turn-over in the land agency
the approval process changes again and it is impossible to determine the anticipated
timeline by state, tribal and federal agencies. ? The SDT didn’t address the need for FERC
oversight on federal lands as the example listed above. Agencies are not qualified to make
decisions on utility vegetation management and can change utilities TVMP.
(9)Finally the current version FAC-003-1 is performing and there is no need to make the
change.
Response: Thank you for your comments.
(0)If vegetation is maintained as required in this draft of the standard in requirements R1 and R2, then no vegetation related sustained outages,
caused by vegetation from within the ROW, within the control of the TO can occur.
(1) Clearance 1 was a fill-in the blank requirement and did not provide the TO any new easement rights, or land permit rights across any lands
whether those land be privately owned or publicly owned; therefore Clearance 1 remains removed from this draft. Furthermore, the relevance of
Clearance 1 depends on several other factors such as length of maintenance cycles, inspection frequency and growth rates. R3 is now used as a
more comprehensive method to address these concerns in lieu of a Clearance 1 requirement.
(2) In order to meet the SAR FAC-003 is required. ANSI-A300 is not sufficient to meet the SAR requirements and contains many elements that do not
need to be related to transmission system electrical reliability.
(3)The SDT suggests that the submittal of a NERC SAR on the PER standards be considered to address any proposed personnel qualifications,
certifications or training issues.
(4) The SDT is following NERC guidelines as they understand them.
(5) The SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way; subsequently the definition of
Active Transmission Line Right of Way and Table 3 have been removed. Outages arising from vegetation from outside the ROW are not violations of
the standard. The SDT had determined this to be the most appropriate assignment of an area of maintenance responsibility considering the
numerous variations in easements and permit rights across North America.
(6)The Standard requires the maintenance to be performed such that loading to Rating and Rated Conditions, and the dynamics of sag and sway are
are taken into consideration, additionally any real time observations of encroachments into the MVCD are to be reported as violations of the
standard. The SDT does not see the need to be prescriptive as to the technology or tools the TO used to be compliant with the Standard, but is
confident that if the vegetation in maintained such that no encroachments are ever observed, and no outages are ever occur, then the reliability
purpose of the standard will be fully accomplished. Furthermore, the results from a LIDAR survey are temporal in nature. Any program relying on
LIDAR would incur a substantial cost with a long term commitment that may not be justified for many Transmission Owners.
(7) FERC requested a defined period for inspection. The SDT agrees with you that annual inspection is required. Therefore the SDT has made annual
inspections a Requirement of this Standard. As to all lines versus applicable lines, FERC has accepted the 200 kV bright line for this standard. They
did order the SDT to ensure that no sub-200 kV lines that are important to the Bulk Electric System are missing from the Applicability of the standard.
23
Voter
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Segment
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Comment
The SDT has incorporated a FERC accepted test (as found in the referenced Standard) to make sure no such important lines are missing.
(8)The SDT agrees that erroneous obstacles to compliance with the standard should be addressed. However, they cannot be resolved in this forum,
or through language inserted in this standard. This Standard places requirements on the Transmission Owners, not on landowners. There is no
legal mechanism for this Standard to take rights from property owners and assign them to the Transmission Owner.
(9)The SDT is changing the Standard in responds to the SAR. The success of the existing standard will be preserved and enhanced with this
revision.
Paul Shipps
Lakeland Electric
6
Negative
The standard is prone to arguments of whether or not an outage was caused by vegetation
encroachment.
Response: Thank you for your comments.
The Compliance Section of the Standard provides the direction under which the Compliance Monitoring and Enforcement Processes and the TOs
must report compliance to this standard. All possible violations need adequate investigation to determine if a vegetation related outage occurred.
The SDT recognizes that such determination are often very challenging, however more prescriptive language on investigations has been seen as
necessary by the SDT and would not contribute to increased reliability. NERC also requires the TOs to document all outages and their related
causes in the TADS system.
Daniel
Brotzman
Commonwealth Edison
Co.
1
Negative
The term “Centerline of the Circuit” in Table 3 is not defined. Until it is defined, there is no
way to know if the standard is technically reasonable or whether existing circuits would be
in violation of the standard and unable to operate. In addition, it is unclear what types of
construction and span lengths were used to develop the distances for active right-of-way
widths in Table 3. Furthermore, it is not clear whether Table 3 contains requirements
against which compliance will be measured or best practice guidelines. Footnote 2, in the
background section, compounds this ambiguity. In short, the lack of a definition for
“Centerline” combined with Footnote 2 and Table 3 make this draft unclear and
unenforceable. Exelon does not necessarily have easement widths for all transmission lines
that equal those defined in Table 3 of this draft; This may require the acquisition of
additional easements, if even possible.
Response: Thank you for your comments.
In response to your comments and similar comments to yours, the SDT has revised the definition of Right of Way to embody the concept of an
Active Transmission Right of Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
Alan Gale
City of Tallahassee
5
Negative
There is still confusion in R7. If I do not complete the work plan, but do not have any
encroachments, have I violated R7? As worded I would argue no. I do not believe the
ambiguity can remain in the standard. If the goal is to complete the work plan (as modified)
leave out the "to ensure no vegetation encroachments..." If the goal is to have no
encroachments, do not rely on a work plan to exist. Make the standard "Each TO shall
ensure no vegetation encroachments occur." I do agree with the performance based
24
Voter
Entity
Segment
Vote
Comment
approach and format.
Response: Thank you for your comments. The SDT considered your response but feels that when one considers all the text in R7, M7, the Rationale
and the related VSL, along with the text in the Guidelines and Technical Basis, it is sufficiently clear that this requirement is about the completion of
the work plan.
Roger C
Zaklukiewicz
8
Negative
To maintain reliability, the minimum distance from a conductor to tall vegetation should be
measured from the conductor nearest the edge of the cleared ROW to the edge of the ROW
and not from the center line of the transmission structure. The type of transmission line
configuration, horizontal or vertical - monopole versus H-Frame versus lattice-structure
versus a V-Guided structure will influence how effective a transmission circuit's performance
or reliability is when the measurement is made from the centerline of the transmission line.
Table 3 should be modified to reflect this concern to ensure the reliability of the EPS.
Response: In response to your comments and similar comments to yours, the SDT has revised the definition of Right of Way to embody the concept
of an Active Transmission Right of Way; subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
Brian
EvansMongeon
Utility Services, Inc.
8
Negative
Utility Services supports the NPCC position on the fixes to this standard proposal.
Response: Thank you for your comments. Please refer to our response to NPCC.
John K
Loftis
Dominion Virginia
Power
1
Negative
Michael F
Gildea
Dominion Resources
Services
3
Negative
Mike Garton
Dominion Resources,
Inc.
5
Negative
We do not agree with replacing the term “Active Transmission Line Right of Way” with
footnote 2. Our objection is around the distances proposed in Table 3. Minimum Distance
from the Centerline of the Circuit to the edge of the active transmission line ROW may not
be consistent with the centerline distances cleared and maintained by the TO. For example,
a TO maintaining 75’ from centerline for a 500kV circuit would be required to clear and
maintain an additional 12.5’ to meet the proposed standard’s requirement. We suggest
either allowing individual TOs to maintain active ROW widths consistent with their normal
clearing/maintenance practices, going back to Draft 3’s definition of Active Transmission
Line Right-of-Way, or changing the footnote in Draft 4 to read: A strip or corridor of land
25
Voter
Louis S
Slade
Entity
Dominion Resources,
Inc.
Segment
Vote
6
Negative
Comment
that is occupied by active transmission facilities. This corridor does not include the parts of
the Right-of-Way that are unused or intended for other facilities. However, the portion of
the ROW that has been cleared must at least meet design clearance requirements such as
National Electric Safety Code or other design criteria, for the reliable operation of active
facilities.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has revised the definition of Right of Way to
embody the concept of an Active Transmission Right of Way; subsequently the definition of Active Transmission Line Right of Way and Table 3 have
been removed.
Ronald L
Donahey
Tampa Electric Co.
3
Negative
We have concern with the “Minimum Distances” as listed in Table 3. What analytical
methodology, criteria and rationale was utilized to determine each recommended distance?
In addition, we have concerns regarding the change to a pre-determined distance. This
seems to be a major shift from the vegetation to conductor methodology employed
previously and throughout this standard? NERC/FERC must recognize that while protecting
and securing grid reliability, each utility must also balance the environmental, political,
customer and economic issues and impacts which will occur with the implementation of the
Table 3 clearances. We question whether this is the most responsible action to take given
the current state of the economy as well as the environmental and political sensitivity
impacts which will result. Tampa Electric questions whether Table 3 will improve System
reliability. Since the inception of standard FAC-003-1 Tampa Electric has not had a Category
1 or Category 2 outage on our 230kV Transmission System. We don’t believe that the
changes proposed to table 3 will improve overall service reliability. It is Tampa Electric’s
opinion that each utility should define the width of its own Active Transmission line ROW.
However, if such a table is to be utilized, Tampa Electric recommends the following changes
or adjustments to Table 3. 1. Expand the table to account for the various types of
Transmission construction; i.e. vertical versus horizontal conductor configurations. 2. Use a
distance from the outermost conductor, not the centerline. This will account for construction
type and better achieve a consistent clearance from conductors. 3. We recommend reducing
the distances in Table 3 by 12.5 feet for each voltage category. 4. Specify whether the
voltage is based upon the design or operating voltage. 5. Reformat the voltage ranges to
100kV - 200kV, 200kV - 300kV, 300kV - 400kV, etc. as an example; this would create a
more appropriate range of voltages and clearance distances. The reformatted voltage
ranges eliminate confusion. For example, under the current proposal it is unclear in which
category a nominal 230kV line should be since sometimes such a line can operate at up to
232kV during low-load conditions.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has revised the definition of Right of Way to
embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have
been removed.
26
Voter
Joseph
O'Brien
Entity
Northern Indiana
Public Service Co.
Segment
Vote
Comment
6
Negative
While there are some enhancements to the organization and content of the standard such
as the addition of the Guidelines and Technical Basis section, clarification of what
constitutes evidence of compliance, and tailoring of VSL severity levels for the requirements
based on the risk each poses to the likelihood of contributing to a cascade, too many
elements present in FAC-003-1 and which are vital to preventing vegetation caused outages
and maximizing system reliability, have been eliminated from FAC-003-2. Specifically, the
elimination of concrete, declared and audited clearance standards between vegetation and
conductors (the existing Clearance 1 and Clearance 2 (R1.2)) Requirements) in the revised
standard is a major defect that will decrease system reliability. It has been indispensable for
NIPSCO when communicating with stake holders (governments, interest groups, land
owners, the public, etc.) to point to these clearance standards to give credibility and support
to the kind of tree removal and trimming that is necessary to achieve the stated objective of
zero preventable tree caused outages. Without these declared clearance standards in the
NERC standard, utility vegetation managers will constantly be challenged by stake holders
to show them that such work is required rather than an elective choice on the utility's part.
One of the key lessons learned from the 2003 blackout and First Energy's overgrown ROW
tree problem was that individual land owners, local governments, and interest groups will
exert pressure on the utility to only do the minimum amount of vegetation management.
Without external and enforceable Vegetation Clearance Standards and by returning to a
pre-2003 regime where the extent of vegetation clearing is left to the individual discretion
and pressures at each utility, there is no doubt that tree clearance conditions will deteriorate
over time and put system reliability at greater risk of vegetation contact
Response: The SDT thanks you for your comments. At the request of FERC in Order 693, the SDT was asked to eliminate the fill-in-the-blank
clearance requirements that are currently in FAC-003-1. A proven Engineering calculation was utilized to determine when a transmission line could
spark over to vegetation without direct contact. Based on this calculation, each utility must determine what clearance levels need to be maintained
as part of their TVMP. The current version does not preclude a utility from removing or pruning vegetation well beyond the MVCD, it just establishes
a line in the sand that determines when a violation occurs. Individual TOs must establish a program that addresses the many variables that exist
such as growth rates, vegetation management cycles, conductor sag and sway, etc. that could result in an encroachment of the MVCD which would
be a direct violation of the standard. Establishing a specific clearance value to be attained during vegetation management activities is too
prescriptive and is in direct conflict with the Results-Based Standard initiative that the SDT is currently implementing. Each TO must factor in delays
and/or mitigation measures associated with stakeholder concerns but must clearly communicate the challenges with maintaining strict compliance
with this zero-tolerance standard.
27
Voter
Entity
Segment
Vote
Comment
Greg Lange
Public Utility District
No. 2 of Grant County
3
Negative
While this standard as written is a marked improvement to previous versions, to claim R1
and R2 as results based is simply not right. Had this standard revision not been advertised
as the first RBS I probably would have voted yes. Results based by definition should be
attained by something either happening or not and should be based on evidence that
already exists. If you cause an outage and it is vegetation related then you violate. Why all
the words around "managing vegetation encroachment" take care of that in the competency
requirements.
Response: The SDT thanks you for your comments. In a Results Based Standard, there are three different levels of defense to achieve the desired
outcome (performance-based requirements, risk-based requirements and competency based requirements). R1 and R2 are considered PerformanceBased requirements and are one component in the defense-in-depth strategy that is described in the Background Section of the current Draft. The
MVCD is the minimum clearance distance before a spark-over occurs so R1 and R2 were designed to ensure that the TO manages vegetation
appropriately before an outage occurs. If the TO was judged based on outages alone, the defense in depth strategy would fail and, thus, a less
reliable standard would exist.
Gregory L
Pieper
Xcel Energy, Inc.
1
Negative
Michael
Ibold
Xcel Energy, Inc.
3
Negative
Liam
Noailles
Xcel Energy, Inc.
5
Negative
David F.
Lemmons
Xcel Energy, Inc.
6
Negative
Xcel Energy votes Negative for several reasons which are outlined in the comments
submitted to NERC during the comment period that ran concurrently with this ballot. One of
the primary objections is the requirement for an annual vegetation inspection. Xcel Energy
urges the retention of the provision in the existing standard that allows the Transmission
Owner to set the frequency of inspection.
Response: The SDT thanks you for your comments. In FERC Order 693, the SDT was asked to look at setting a specific frequency for vegetation
inspections across North America. This was a difficult task since vegetation characteristics vary across the continent but the team voted to accept
an annual inspection frequency as a minimum and provide utilities the flexibility to include this mandatory vegetation inspection as part of a general
line inspection.
Terry
Harbour
MidAmerican Energy
Co.
1
Affirmative
Thomas C.
Mielnik
MidAmerican Energy
Co.
3
Affirmative
All rationale boxes should have a disclaimer at the top to the effect "For Guidance Only, Not
for Enforcement".
Response: The SDT thanks you for your affirmative votes and comments. A “disclaimer” is addressed by the Standards Committee Process
Subcommittee however its location remains under discussion.
28
Voter
Guy V. Zito
Entity
Northeast Power
Coordinating Council,
Inc.
Segment
Vote
Comment
10
Affirmative
Although NPCC and its members support the results based initiative and this proof of
concept standard and format, there has been some concern with the proposed FAC-003-2.
Some of NPCC's members that have active vegetation management programs have stated
that in the application of Table 3 - specifically, the use of a "Minimum Distance from the
Centerline of the Circuit". Mono-pole and frame construction have significantly different
footprints which don't support a one size fits all approach. The use of Table 3 for 345kV,
mono-pole construction could result in excessive clearing of additional forested edge on
existing ROWs with little if any value added to system reliability and at great cost. There is
an issue with use of the term "easements" in the definition and seek clarification on several
questions-is there a reason the Active ROW only includes easements not fee ownership,
license or some other right to occupy and manage the ROW? Would active ROW include
"danger tree rights" on land? Not all entities that own transmission facilities and have
vegetation management programs agree with these statements however there is cause
enough for concern. In addition, this standard represents a "proof of concept for the
"reliability based standards" initiative NERC is putting forward. NPCC RSC believe this
initiative will result in better standards over time.
Response: The SDT thanks you for your affirmative vote and comments. Based on your comment and others, the SDT has revised the definition of
Right of Way to embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active Transmission Line Right of Way
and Table 3 have been removed.
Jason
Shaver
American
Transmission
Company, LLC
1
Affirmative
ATC raises a concern on including Rationale Boxes plus Guidelines and Technical Basis as
part of the NERC Reliability Standard. ATC recommends that the SDT either remove these
sections or make them separate from the formal standard to eliminate any risk that these
may be construed as requirements. An alternative method is to very clearly identify which
parts of the standard are subject to compliance and considered mandatory and which are
not considered requirements and are only for guidance in meeting the requirements.
Response: The SDT thanks you for your affirmative vote and comments. A “disclaimer” is addressed by the Standards Committee Process
Subcommittee however its location remains under discussion.
Horace
Stephen
Williamson
Southern Company
Services, Inc.
1
Affirmative
Richard J.
Mandes
Alabama Power
Company
3
Affirmative
Anthony L
Wilson
Georgia Power
Company
3
Affirmative
Comments for this ballot are included in the Southern Company submitted comment form Project 2007-07: Transmission Vegetation Management.
29
Voter
Entity
Segment
Vote
Gwen S
Frazier
Gulf Power Company
3
Affirmative
Don Horsley
Mississippi Power
3
Affirmative
Comment
Response: The SDT thanks you for your affirmative votes and comments. Please refer to the SDT responses in the Comment Report.
Ajay Garg
Hydro One Networks,
Inc.
1
Affirmative
Michael D.
Penstone
Hydro One Networks,
Inc.
3
Affirmative
Hydro One would like to submit the following comments for consideration of the SDT. 1. In
the application of Table 3 - specifically, the use of a "Minimum Distance from the Centerline
of the Circuit", Mono-pole and frame construction have significantly different footprints
which don't support a one size fits all approach. The use of Table 3 for 345kV, mono-pole
construction could result in excessive clearing of additional forested edge on existing ROWs
with little if any value added to system reliability and at great cost. 2. The use of the term
"easements" in the definition needs clarification. For example, is there a reason the Active
ROW only includes easements and not ownership, license or some other right to occupy and
manage the ROW? Would active ROW include "danger tree rights" on land?
Response: The SDT thanks you for your affirmative vote and comments. Based on your comment and others, the SDT has revised the definition of
Right of Way to embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active Transmission Line Right of Way
and Table 3 have been removed.
Richard J.
Padilla
Pacific Gas and
Electric Company
5
Affirmative
In principle we agree but we have the following concerns: Removes reference to ANSI A300
as an effective management strategy to comply with the standard. We often point to ANSI
A300 to support our position of "wire zone - border zone" vegetation management practices
in public education and legal disputes. However, Eastern and Southern utilities, who
dominate the VMSDT, feel that ANSI A300 places constraints on their desire to perform bare
ground clearing, which A300 and PG&E does not endorse. Most Western utilities support
retaining reference to A300. Minimum clearance distances have been reduced from the
current IEEE 516 distances to the distances derived from the Gallet equation. Reduced
clearance distances make it more difficult to justify some work with property owners. FERC
and NERC have also stated they are opposed to reduced clearances. The VMSDT spent
much time and effort to construct the standard in a manner where there is violation
gradation within some requirements. NERC and FERC have indicated they disagree with the
latitude to ignore the VSL's as proposed
Response: The SDT thanks you for your affirmative vote and comments. The proposed draft of FAC-003-2 continues to make reference to ANSI A300
as a best practice but short of endorsement into a requirement. This represents the best compromise that the team could achieve.
Use of the Gallet Equation, contrary to your comment, provides for greater distances than IEEE-516-2003 under the same conditions of elevation,
voltage and transient overvoltage factor. Please refer to the Technical Reference Document (posted on NERC webpage) for more information.
The SDT indeed has worked hard to achieve a technically valid set of VSLs for this standard and believe its perspective is correct.
30
Voter
Entity
Segment
Vote
Comment
MEAG is voting yes in support of the improvements and significant effort that went into
modifying FAC-003-2 with the understanding that the vegetation management standard will
continue to develop and evolve. Vegetation management’s increased visibility and
dramatically increased oversight is resulting in increasingly defined and demanding
language contained in the standard’s requirements. Some of the new requirements
overreach but the intent is clear, create and manage a vegetation management program to
prevent outages that potentially create a cascading outage threat. As the application of this
new standard is reviewed over time, improved requirements and measures based on
experience and results should be used to further improve the standard. Additional lines of
lesser voltages will now be included under this standard. The tendency may be to include a
line when in doubt even if there is a remote possibility that it can potentially cause a threat
of a cascading outage. The same philosophy will occur with rights-of-way. The legal rightof-way will be cleared even if it was secured for a future line of greater voltage. We need to
continue to review FAC-003-2 for future improvements to achieve reasonableness in
protecting against cascading outages without heaping unnecessary costs on electric
consumers.
Steven
Grego
MEAG Power
3
Affirmative
Steven M.
Jackson
Municipal Electric
Authority of Georgia
3
Affirmative
Response: The SDT thanks you for your affirmative vote and comments. The SDT agrees with your comments.
Michael T.
Quinn
Oncor Electric Delivery
1
Affirmative
Oncor believes that the proposed standard is a significant improvement over the current
standard. We strongly support the suggested VSL’s as proposed by the VMSDT. However,
we also take the position that adoption of a virtual binary VSL to describe an encroachment
without an outage, as a high VSL doesn’t adequately address the different levels of
encroachment and any potential impact that could lead to Cascading. Oncor is not aware of
any vegetation fall-ins or blow-ins that have caused or have lead to Cascading.
Response: The SDT thanks you for your affirmative vote and comments. The SDT has worked hard to achieve a technically valid set of VSLs for this
standard and believe its perspective is correct.
Chifong L.
Thomas
Pacific Gas and
Electric Company
1
Affirmative
PG&E believes this version is an improvement over the last draft. However, PG&E is
concerned with the removal of the reference to ANSI A300 as an effective management
strategy to comply with the standard. ANSI A300 provides clarity on the "wire zone - border
zone" vegetation management practices. PG&E is also concerned that the minimum
clearance distances have been reduced from the current IEEE 516 distances to the
distances derived from the Gallet equation. Reduced clearance distances make it more
difficult to implement certain types of work needed to support reliability.
Response: The SDT thanks you for your affirmative vote and comments. The proposed draft of FAC-003-2 continues to make reference to ANSI A300
as a best practice but short of endorsement into a requirement. This represents the best compromise that the team could achieve.
31
Voter
Scott M.
Helyer
Entity
Tenaska, Inc.
Segment
Vote
5
Affirmative
Comment
Please note that further changes may be needed to this standard to address issues related
to generation interconnection facilities per other standards development efforts.
Response: The SDT thanks you for your affirmative vote and comments. The SDT is aware that a separate Project 2010-07 Transmission
Requirements at the Generator Interface is underway to address the issue you raise.
Brandy A
Dunn
Western Area Power
Administration
1
Affirmative
Please see comments provided on Official Comment Form
Response: The SDT thanks you for your affirmative vote and comments. Please refer to the responses in the Comment Report.
Donald S.
Watkins
Bonneville Power
Administration
1
Affirmative
Rebecca
Berdahl
Bonneville Power
Administration
3
Affirmative
Francis J.
Halpin
Bonneville Power
Administration
5
Affirmative
Brenda S.
Anderson
Bonneville Power
Administration
6
Affirmative
Regarding footnote number 2, and the description of an "Active Transmission Line Right of
Way", BPA has the following comments: The distance is reasonable in the table, but due to
widely varying designs of structures it does not give a relationship of the outside wire to
edge of ROW. It should be noted as outside wire, phase or conductor to edge of ROW. In
addition, the effective date should allow transmission owners time to achieve this distance,
perhaps one cycle. Other Comments: The basis of managing vegetation to MVCD in Table 2
( essentially withstand distances) will likely prove problematic. BPA believes NERC should
develop an additional table that calls out minimum "buffers" based on attributes such as line
voltage, line rating etc. This table should be a companion to Table 2. It is NERC's
responsibility to regulate and we believe that they should do so. In this case, the loss of
flexibility for the owners is not necessarily a bad thing.
Response: The SDT thanks you for your affirmative votes and comments. Based on your comment and others, the SDT has revised the definition of
Right of Way to embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active Transmission Line Right of Way
and Table 3 have been removed.
Tim Kelley
Sacramento Municipal
Utility District
1
Affirmative
James
LeighKendall
Sacramento Municipal
Utility District
3
Affirmative
Mike
Ramirez
Sacramento Municipal
Utility District
4
Affirmative
Bethany
Wright
Sacramento Municipal
Utility District
5
Affirmative
SMUD appreciates the efforts of the Drafting Team. However, use of the phrase “intentional
time delay” in R4 no clear definitive time frame for “intentional time delay” this leads to
difficulty in its definition. SMUD respectively offers the recommendation for the DT to use a
term along the lines of “expeditious.”
Response: The SDT thanks you for your affirmative votes and comments. The SDT struggled with the selection of language in R4 and considered
your term among many others. The team ended up with the drafted version as the best compromise.
32
Voter
Marjorie S.
Parsons
Entity
Tennessee Valley
Authority
Segment
Vote
Comment
6
Affirmative
Suggest a clarifying change to the language in footnote 2 and or Table 3 to address those
lines that have ROW width variations from the prevailing width due to factors unrelated to
the needs for vegetation maintenance for the subject line. Add the following sentence to
footnote 2 “The widths and distances in Table 3 shall be that prevailing width of the ROW
exclusive of any variations in the prevailing width due to factors unrelated to the needs for
vegetation maintenance for the subject line.” TVA asserts that the new language in R1, R2,
M1, and M2 in concert with new language in R3 and M3 are fully adequate and superior to
any of the proposed alternative A-F. TVA asserts that the VSLs as proposed by the SDT are
appropriate since they reflect in various degrees the typical types of right of way
maintenance failure. For example vegetation removal from under the conductors should be
the highest priority work, followed by vegetation removal in the side-growth/blow-out areas,
and lastly of all fall-in risks should be removed. TVA suggests that another sentence be
added to the end of Section 4.4 Other, as follows: Nothing is this Standard is shall be used
to require the Transmission Owner to acquire additional easement rights beyond those
currently owned, or to perform any maintenance outside the limits of its legal rights.
Response: The SDT thanks you for your affirmative vote and comments. Please see drafting team responses to your same comments in the
Comment Report.
Paul B.
Johnson
American Electric
Power
1
Affirmative
Edward P.
Cox
AEP Marketing
6
Affirmative
The VSL chart states that it is a Lower Violation if the TO has an encroachment into the
MVCD observed in real time, absent a sustained outage. While the Moderate and High
categories specifically note that the reference is to inside the right-of-way, the Lower level
does not. Should the Lower category read: " The Transmission Owner has an encroachment
into the MVCD from inside the right-of-way in real time, absent a Sustained Outage"?
Response: The SDT thanks you for your affirmative votes and comments. The suggested edit has been considered and the SDT determined that no
change to the VSL would be made.
Robert
Smith
Duke Energy
5
Affirmative
This Version 2 of FAC-003 takes a big step forward to clarify expectations and compliance
with the standard. The results-based format is a big improvement.
Response: The SDT thanks you for your affirmative vote and comment.
33
Voter
George T.
Ballew
Entity
Tennessee Valley
Authority
Segment
Vote
5
Affirmative
Comment
TVA suggests a clarifying change to the language in footnote 2 and or Table 3 to address
those lines that have ROW width variations from the prevailing width due to factors
unrelated to the needs for vegetation maintenance for the subject line. Add the following
sentence to footnote 2 “The widths and distances in Table 3 shall be used as the prevailing
width of the ROW regardless of any variations in width due to factors unrelated to the
needs for vegetation maintenance for the subject line.” TVA asserts that the VSLs as
proposed by the SDT are appropriate since they reflect in various degrees the typical types
of right of way maintenance failure. For example vegetation removal from under the
conductors should be the highest priority work, followed by vegetation removal in the sidegrowth/blow-out areas, and lastly of all fall-in risks should be removed. TVA suggests that
another sentence be added to the end of Section 4.4 Other, as follows: Nothing in this
Standard shall be used to require the Transmission Owner to acquire additional easement
rights beyond those currently owned, or to perform any maintenance outside the limits of
its legal rights.
Response: The SDT thanks you for your affirmative votes and comments. Based on your comment and others, the SDT has revised the definition of
Right of Way to embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active Transmission Line Right of Way
and Table 3 have been removed.
The SDT agrees with your comment on the VSLs, and the SDT points out that the following sentence at the end of Section 4.4 is comparable to your
suggestion, “Nothing in this section should be construed to limit the Transmission Owner’s right to exercise its full legal rights on the ROW.”
Spencer
Tacke
Modesto Irrigation
District
4
Affirmative
We approve of the proposed revised standard as written. However, we have a concern
about the Minimum Vegetation Clearance Distance (MVCD) of 2.97 feet shown in Table 2 for
230kV lines, as being too small. We will continue to maintain a much larger clearance than
specified in Table 2, and in this case, no less than 10 feet of clearance for 230kV lines,
taking into consideration the maximum sag designed for a given line. Thank you.
Response: The SDT thanks you for your affirmative vote and comments. The MVCD was set up to be a “minimum” distance to never violate.
Certainly, each TO must maintain larger clearances in order to account for growth, movement of conductor and other factors that influence the
distance between the conductor and vegetation. Use of the Gallet Equation provides for greater distances than IEEE-516-2003 under the same
conditions of elevation, voltage and transient overvoltage factor. Please refer to the Technical Reference Document (posted on NERC webpage) for
more information.
James L.
Jones
Southwest
Transmission
Cooperative, Inc.
1
Abstain
Entities have a problem with other Government Agencies in tha they are not real receptive
for Vegetation Management. Burea of Land Management will usually take 2 years to get
permission to trim vegetation in BLM ROW. State Land Department will usually not let you
cut any cactuses in ROW on State land. ROW crossing on a Sovereign Indian Reservation is
just as bad. If this is such a big issue for FERC/NERC, then they need to get other
governmental agencies on board with them.
34
Voter
Entity
Segment
Vote
Comment
Response: The SDT thanks you for your comments. Jurisdictional issues need to be addressed in other appropriate arenas. The Utility Arborist
Association among other groups have sought to coordinate cooperation between agencies in the past.
35
Consideration of Comments on Draft 5 of
FAC-003-2
Project 2007-07 Vegetation Management — September 30, 2011
Background
The Transmission Vegetation Management Drafting Team thanks all commenters who submitted
comments on the 5th Draft of FAC-003-2 Transmission Vegetation Management standards. These
standards were posted for a 30-day public comment period from January 27, 2011 through February
28, 2011. The stakeholders were asked to provide feedback on the standards through a special
Electronic Comment Form. There were 41 sets of comments, including comments from more than
106 different people from approximately 63 companies representing 9 of the 10 Industry Segments
as shown in the table on the following pages.
Summary of Changes
In order to be consistent with the latest version of NERC’s Results Based Standards template, the
heading “Objective” was replaced with “Purpose,” and the numbering, headings, and sections were
reformatted as necessary.
One repeated concern was whether or not “danger trees” rights outside the Right-of-Way (ROW)
should be an extension of the ROW. The SDT has limited the definition of Right-of-Way to a corridor
of land with a defined width to operate a transmission line, which does not include danger tree
rights.
Another repeated concern was reference to the term “blowout standard” and commenters were
asking for more clarification and/or a specific definition of that term. To this line of comments the
SDT responded, “the definition includes a series of options that give the Transmission Owner latitude
in establishing ROW width. It does not require selecting a single method for its system. The term
blowout standard is not capitalized and is not a defined term, and is intended to represent whatever
conductor “blow out” (as opposed to vegetation “blow in”) design criteria were used when the line
was constructed. This phrase in the definition allows a Transmission Owner to use its internal
engineering standards or the general engineering standards that were in effect when the line was
constructed to determine the ROW width.”
A request was made to include the definition of MVCD within the definition section of the standard.
The SDT agreed with the commenter’s request and used the appropriate portion of the existing
language in the rationale text box associated with R1 for the MVCD definition. The SDT understands
that this term will be added to the NERC glossary coincident with this standard becoming effective.
This is not a substantive change to the standard, it is merely procedural.
The SDT made minor changes to the footnotes in response to several requests.
There was some concern expressed regarding the relationships between the VSLs and language in
the requirements. The SDT revised the language in the Rationale box to explain the program
performance relationships between types of encroachments, faults and outages, and various types of
failed maintenance, and how the various types of failed maintenance have historically been
associated with known vegetation related events.
One commenter requested that “of applicable lines” be added to the requirements and VSL verbiage
to clearly denote applicability within the requirements and VSL verbiage. The SDT made those
changes as requested to the requirements, measures and VSLs.
Two commenters requested an example be added to the Guidelines and Technical Basis similar to
the examples in R6 to clarify that the % calculations should be based on the Annual Plan as modified;
the SDT added the example as requested.
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to
give every comment serious consideration in this process! If you feel there has been an error or
omission, you can contact the Vice President and Director of Standards, Herb Schrayshuen, at
404-446-2563 or via email at [email protected]. In addition, there is a NERC Reliability
Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on Draft 5 of FAC-003-2
2
Index to Questions, Comments, and Responses
1.
The SDT proposes a revised NERC Glossary definition for Right-of-Way (ROW). This revised
definition will be used in lieu of the Active Transmission Line ROW. Do you agree? If
answer is no, please explain. ................................................................................................ 10
2.
In R1 and R2 and their associated VSLs, the SDT added the phrase “in order of increasing
severity” and added the sentence “The types of encroachments are listed in order of
increasing degrees of severity in non-compliant performance as it relates to a failure of a
TO’s vegetation maintenance program.” to the Rationale boxes for R1/R2. Do you agree? If
answer is no, please explain. ................................................................................................ 28
3.
In response to comments received regarding the term “investigation” in M1/M2, the SDT
substituted “confirmation…by the Transmission Owner..” in its place, among other minor
edits to these measures. Do you agree? If answer is no, please explain. ............................ 38
4.
In response to comments received that requirement R3 is unclear with respect to intent,
the SDT added “maintenance strategies”. Do you agree this clarifies the intent? If answer is
no, please offer alternative language. .................................................................................. 46
5.
The SDT added clarifying language in M7 to explain how the annual work plan percentage
complete calculation is to be performed. Is this adequate? If no, please provide improved
examples. .............................................................................................................................. 53
Additional Comments from NERC:................................................................................................ 67
Consideration of Comments on Draft 5 of FAC-003-2
3
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
SERC Vegetation Management subcommittee
Joe Spencer
Additional Organization
Fatima Ahmed
SEPA
SERC
2.
Gerry Beckerie
Ameren
SERC
3.
Todd Bennett
AECI
SERC
4.
Brent Davis
Entergy
SERC
5.
Richard Dearman
TVA
SERC
6.
Jack Gardner
Progress Energy
SERC
7.
Jeff Hackman (chair) Ameren
SERC
8.
Ralph Hale
Entergy
SERC
9.
Jerry Lindler
SCANA
SERC
10. Larry Rodriguez
Entegra Power
SERC
11. Joe Spencer
SERC Reliability
SERC
12. John Troha
SERC Reliability
SERC
13. Marc Tunstall
Fayetteville Public Works Com SERC
14. Terry Wilson
Power South
Group
Sasa Maljukan
3
4
5
6
7
8
9
10
X
Region Segment Selection
1.
2.
2
SERC
Hydro One Networks
Consideration of Comments on Draft 5 of FAC-003-2
X
4
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. David Kiguel
Hydro One Networks Inc NPCC
2. Jonathan Marriott
Hydro One Networks Inc.
3.
Group
Additional Member
Guy Zito
Additional Organization
1
1
Northeast Power Coordinating Council
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC
10
2.
Gregory Campoli
New York Independent System Operator
NPCC
2
3.
Kurtis Chong
Independent Electricity System Operator
NPCC
2
4.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
5.
Bohdan M. Dackow
US Power Generating Company (USPG)
NPCC
NA
6.
Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC
1
7.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
8.
Brian Evans-Mongeon Utility Services
NPCC
8
9.
Mike Garton
Dominion Resources Services, Inc.
NPCC
5
10. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC
5
11. Kathleen Goodman
ISO - New England
NPCC
2
12. David Kiguel
Hydro One Networks Inc.
NPCC
1
13. Michael R. Lombardi
Northeast Utilities
NPCC
1
14. Randy MacDonald
New Brunswick Power Transmission
NPCC
1
15. Bruce Metruck
New York Power Authority
NPCC
6
16. Chantel Haswell
FPL Group, Inc.
NPCC
5
17. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
10
18. Robert Pellegrini
The United Illuminating Company
NPCC
1
19. Saurabh Saksena
National Grid
NPCC
1
20. Michael Schiavone
National Grid
NPCC
1
21. Wayne Sipperly
New York Power Authority
NPCC
5
22. Donald Weaver
New Brunswick System Operator
NPCC
2
23. Ben Wu
Orange and Rockland Utilities
NPCC
1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC
3
4.
Group
Deborah Schaneman
Additional Member Additional Organization
X
Platte River Power Authority Substation
Maintenance Group
Region
Consideration of Comments on Draft 5 of FAC-003-2
X
X
X
X
Segment
5
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
Selection
1.
Scott Rowley
Platte River Power Authority WECC
1, 3, 5, 6
2.
Gary Whittenberg
Platte River Power Authority WECC
1, 3, 5, 6
3.
Aaron Johnson
Platte River Power Authority WECC
1, 3, 5, 6
5.
Group
Denise Koehn
Additional Member
Bonneville Power Administration
Additional Organization
BPA, Transmission Field Services
WECC 1
2. Steven Narolski
BPA, Transmission Field Services
WECC 1
3. Frank Weintraub
BPA, Transmission Lign Design
WECC 1
4. Jennifer Bailey
BPA, Transmission, Construction Mgmt and Inspect WECC 1
5. Don Swanson
BPA, Transmission TLM Technical Services
WECC 1
6. Steve Bottemiller
BPA, Transmission, Real Property Support Svcs
WECC 1
7. Vince Ierulli
BPA, Transmission Lign Design
WECC 1
8. Mike Staats
BPA, Transmission Engineering
WECC 1
9. Jenifur Rancourt
BPA, FERC Compliance
WECC 1, 3, 5, 6
6.
Group
Doug Keegan
NERC Staff
7.
Group
David Thorne
Pepco Holdings Inc and Affiliates
Dana Small
RFC
1
2.
Lisa E Pfeifer
RFC
1
3.
Pat J Byrne
RFC
8.
X
X
X
X
X
X
X
X
Segment
Selection
1.
Group
X
Region Segment Selection
1. Charles Sheppard
Additional Member Additional Organization Region
X
1
Sam Ciccone
FirstEnergy
X
Additional Member Additional Organization Region Segment Selection
1. Rebecca Spach
FE
RFC
1
2. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
3. Dave Folk
FE
RFC
1, 3, 4, 5, 6
Consideration of Comments on Draft 5 of FAC-003-2
6
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4. Mike Ferncez
FE
RFC
1
5. Shawn Standish
FE
RFC
1
6. Katrina Schnobrich FE
RFC
Group
9.
Additional Member
Mike Garton
Additional Organization
Dominion Electric Market Policy
2
3
X
X
4
5
6
X
X
Dominion Resources Services, Inc. NPCC 5
2. Louis Slade
Dominion Resources Services, Inc. SERC
5
3. Connie Lowe
Dominion Resources Services, Inc. RFC
6
4. Michael Crowley
Dominion Virginia Power
1, 3
SERC
Individual
JT Wood
Southern Company Transmission
X
X
Individual
Janet Smith, Regulatory
Affairs Supervisor
Arizona Public Service Company
X
X
X
X
12.
Individual
Cynthia Oder
Salt River Project
X
X
X
X
13.
Individual
Luke Diruzza
Tampa Electric Company
X
X
X
X
14.
Individual
Silvia Parada Mitchell
NextEra Energy
X
X
X
X
15.
Individual
Jennifer Wright
SDG&E
X
X
X
16.
Individual
JAMES SMITH
ASSET MANAGEMENET
X
17.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie (NCR07112)
X
18.
Individual
Michael Gammon
Kansas City Power & Light
X
X
X
19.
Individual
Joe Petaski
Manitoba Hydro
X
11.
8
9
10
Region Segment Selection
1. Michael Gildea
10.
7
Consideration of Comments on Draft 5 of FAC-003-2
X
7
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
Individual
Weston Davis
Central Maine Power Company IberdrolaUSA
X
21.
Individual
Gordon Rawlings
BC Hydro
X
22.
Individual
Andrew Pusztai
American Transmission Company, LLC
X
23.
Individual
Thad Ness
American Electric Power
X
24.
Individual
William Rees
Baltimore Gas and Electric Co.
X
25.
Individual
Jason Regg
TVA
X
Individual
Michael Schiavone
Niagara Mohawk Power Corporation (dba
National Grid)
27.
Individual
Michael Pakeltis
CenterPoint Energy
X
28.
Individual
Greg Rowland
Duke Energy
X
29.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
30.
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
X
31.
Individual
Kirit Shah
Ameren
X
32.
Individual
Amy Kupferberg
Individual
NA
Individual
George Czerniewski
Consolidated Edison Company of New York,
Inc. - Transmission Line Maintenance
X
20.
26.
33.
Consideration of Comments on Draft 5 of FAC-003-2
2
X
3
4
5
6
X
X
X
X
X
X
X
X
X
X
X
X
X
X
7
8
9
10
X
8
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
34.
Individual
andres lopez
USACE
35.
Individual
CJ Ingersoll
CECD
36.
Individual
Edward J Davis
Entergy Services, Inc
X
X
37.
Individual
David Burke
Orange and Rockland Utilities, Inc.
X
X
38.
Individual
Saurabh Saksena
National Grid
X
X
39.
Individual
Steve Rueckert
Western Electricity Coordinating Council
40.
Individual
Jody Nelson
Georgia Transmission Corp.
X
41.
Individual
T. Wiley
Northern Indiana Public Service Company
X
Consideration of Comments on Draft 5 of FAC-003-2
4
5
6
X
7
8
9
10
X
X
X
X
X
X
9
1.
The SDT proposes a revised NERC Glossary definition for Right-of-Way (ROW). This revised definition will be used in lieu of the
Active Transmission Line ROW. Do you agree? If answer is no, please explain.
Summary Consideration: There are 40 comments; 29 of those comments were in agreement with the definition, and 11 were in
disagreement.
One repeated concern in the disagreements was whether or not “danger trees” rights outside the Right-of-Way (ROW) should be an
extension of the ROW. The SDT responded “The SDT has limited the definition of Right-of-Way to a corridor of land with a defined
width to operate a transmission line. This does not include danger tree rights.”
Another repeated concern in the disagreements was reference to the term “blowout standard” and commenters were asking for
more clarification and/or a definition of that term. To this line of comment the SDT responded “The definition includes a series of
options that gives the Transmission Owner latitude in establishing ROW width. It does not require selecting a single method for its
system. The term blowout standard is not capitalized and is not a defined term, and is intended to represent whatever conductor
“blow out” (as opposed to vegetation “blow in”) design criteria were used when the line was constructed. This phrase in the
definition allows a Transmission Owner to use its internal engineering standards or the general engineering standards that were in
effect when the line was constructed to determine the ROW width.”
A request was made to include the definition of MVCD within the definition section of the standard. The SDT agreed with the
commenter’s request and used the appropriate portion of the existing language in the rationale text box associated with R1 for the
MVCD definition. The SDT understands that this term will be added to the NERC glossary coincident with this standard becoming
effective. This is not a substantive change to the standard, it is merely procedural.
A request was made to remove the existing and future definition of ROW from the glossary. The SDT understands that this is not
consistent with the NERC intent for each repeated acronym used in multiple requirements to be available in the glossary for ready
reference.
A request was made to change the definition of ROW to include special permissions given by some property owners. To this the SDT
responded “The SDT has limited the definition of Right-of-Way to a corridor of land with a defined width to operate a transmission
line. The SDT does not propose to change the definition because of the numerous and varied special property owner permissions
that may exist, and which are not always legally binding.”
Consideration of Comments on Draft 5 of FAC-003-2
10
A concern within one disagreement was related to possible misuse of the “pre-2007 vegetation maintenance records.” The SDT
explained that this term was placed in the definition as a method to cover situations where the other alternatives are not viable. The
SDT will address this issue in the Technical Reference Document.
Organization
SERC Vegetation Management
sub-committee
Yes or No
Question 1 Comment
No
We agree with the proposed definition as a replacement for active transmission ROW, however, in
a review of NERC standards, the term ROW is not used except in FAC-003. It is therefore
recommended that the term be removed from the NERC glossary. r
Response: The SDT thanks you for your comments. The SDT considered your request but cannot implement it because it is not consistent with the
NERC Standards Development Process for defining the use of a term solely within a standard itself. All defined terms must be included in the
glossary.
Hydro One Networks
No
The revised definition of ROW is unclear in regards to the application of standards and/or historic
records as a means of determining ROW width; is it necessary for a TO to select one method to
apply in all cases, or can each span be treated in the manner deemed most appropriate by the TO?
Additionally “blowout Standard” has not been defined in the document or in the technical paper,
and therefore it is not clear exactly how this method would be applied, and subsequently defended
under scrutiny.
Response: The SDT thanks you for your comments. The definition includes a series of options that give the Transmission Owner latitude in
establishing ROW width. It does not require selecting a single method for its system. The term blowout standard is not capitalized and is not a
defined term, and is intended to represent whatever conductor “blow out” (as opposed to vegetation “blow in”) design criteria were used when
the line was constructed. This phrase in the definition allows a Transmission Owner to use its internal engineering standards or the general
engineering standards that were in effect when the line was constructed to determine the ROW width.
Northeast Power Coordinating
Council
No
There was no definition of ROW listed in FAC-003-1. The revised definition of ROW in FAC-003-2 is
unclear regarding the application of standards and/or historic records as a means of determining
Consideration of Comments on Draft 5 of FAC-003-2
11
Organization
Yes or No
Question 1 Comment
ROW width. Is it necessary for a TO to select one method to apply in all cases, or can each span be
treated in the manner deemed most appropriate by the TO? “Blowout standard” has not been
defined in the document, technical paper, or NERC Glossary and it is not clear what this method is,
and exactly how it would be applied. It could not be defended under scrutiny. It is still unclear
whether Danger Tree rights are included in this definition.In the NERC Glossary of Terms, Right-ofWay (ROW) is defined as “A corridor of land on which electric lines may be located. The
Transmission Owner may own the land in fee, own an easement, or have certain franchise,
prescription, or license rights to construct and maintain lines.” Propose keeping this definition.Is
encroachment into the MVCD, or (MVCD plus additional distance as defined by the TO)? MVCD, as
specified within the body of FAC-003-2 "is a calculated minimum distance stated in feet (meters) to
prevent flashover between conductors and vegetation, for various altitudes and operating
voltages." MVCD should be “formally” defined in this document, and the NERC Glossary. Can a
list/database be established in 2011 that lists the widths for the pre-2007 vegetation management
records?
Response: The SDT thanks you for your comments. The existing ROW definition in the glossary was created by and for the FAC-003-1 and was
moved there when that standard was adopted. The definition includes a series of options that give the Transmission Owner latitude in establishing
ROW width. It does not require selecting a single method for its system. The term blowout standard is not capitalized and is not a defined term,
and is intended to represent whatever conductor “blow out” (as opposed to vegetation “blow in”) design criteria were used when the line was
constructed. This phrase in the definition allows a Transmission Owner to use its internal engineering standards or the general engineering
standards that were in effect when the line was constructed to determine the ROW width. The SDT has limited the definition of Right-of-Way to a
corridor of land with a defined width to operate a transmission line. This does not include danger tree rights.
The definition of the MVCD is now added to this Standard. While use of the pre-2007 records is a compliance issue and is not in the purview of the
SDT, it is the intent of the language in the definition that you could use this information.
Platte River Power Authority
Substation Maintenance
Group
No
We agree that the ROW width in no case exceeds the TO’s legal rights but may be less. We do not
agree that the revised NERC Glossary definition for Right-of-Way addresses paragraph 734 of FERC
Order 693 “that rights-of-way be defined to encompass the required clearance areas instead of the
Consideration of Comments on Draft 5 of FAC-003-2
12
Organization
Yes or No
Question 1 Comment
corresponding legal rights, and that the standards should not require clearing the entire right-ofway when the required clearance for an existing line does not take up the entire right-of-way”. The
engineering or construction standards for establishing the width of the corridor outlined in the
definition are in most cases not useful. We will continue to rely on our easements and legal rights
with this definition. We believe the Active Transmission Line ROW definition in the previous version
more clearly addressed paragraph 734 of FERC Order 693.
Response: The SDT thanks you for your comments. The standard covers lines that have been built over many years where records could be lost.
The ROW definition provides three alternatives to determine the width of the corridor to be maintained.
NERC Staff
No
NERC supports a revised definition and prefers the definition in Draft 5 over the Active
Transmission Line ROW definition used in Draft 4. NERC believes the use of the term “pre-2007
vegetation maintenance records” in the proposed definition is ambiguous and will likely be
interpreted differently throughout the industry. Therefore, NERC supports this change subject to
removing the aforementioned term.
Response: The SDT thanks you for your comments. The phrase “…pre-2007 vegetation maintenance records…” was placed in the definition as a
method to cover situations where the other alternatives are not viable. The SDT has addressed this issue in detail in the Technical Reference
Document.
FirstEnergy
No
Although for the most part we agree with the changes to the definition of ROW, we suggest the
following changes.
1. The last sentence of the definition states "The ROW width in no case exceeds the Transmission
Owner's legal rights but may be less based on the aforementioned criteria." We do not agree with
the phrase "in no case exceeds the Transmission Owner's legal rights" because there could be
instances where special permission has been granted by landowners to the TO. We suggest revising
this statement to "The ROW width may be less than the Transmission Owner’s granted rights based
on the aforementioned criteria."
Consideration of Comments on Draft 5 of FAC-003-2
13
Organization
Yes or No
Question 1 Comment
2. Regarding the phrase "blowout standard" used in the definition, we are assuming this is in
reference to the company specific calculations for sag and sway on not on any one specific industry
standard. We suggest clarification such as "Transmission Owner's specific blowout or sag and sway
analysis in effect when the line was built".
Response: The SDT thanks you for your comments. The SDT has limited the definition of Right-of-Way to a corridor of land with a defined width to
operate a transmission line. The SDT does not propose to change the definition because of the numerous and varied special property owner
permissions that may exist, and which are not always legally binding.
The term blowout standard is not capitalized and is not a defined term, and is intended to represent whatever conductor “blow out” (as opposed
to vegetation “blow in”) design criteria were used when the line was constructed. This phrase in the definition allows a Transmission Owner to use
its internal engineering standards or the general engineering standards that were in effect when the line was constructed to determine the ROW
width.
Central Maine Power
Company - IberdrolaUSA
No
The definition does not define transmission owner responsibility for areas covered by “danger tree”
rights. This area is outside the maintained width but for economic and social reasons the
transmission owner can not remove all danger trees. Utilities have procedures in place to remove
the hazard trees but it is not practical to remove all danger trees that have the potential to violate
the MVCD should they fail. This area of the definition requires clarification.
Response: The SDT thanks you for your comments. The SDT has limited the definition of Right-of-Way to a corridor of land with a defined width to
operate a transmission line. This does not include danger tree rights.
TVA
No
I suggest that "arboricultural activities or horticultural or agricultural activities be removed and
changed to installation, removal or digging of vegetation.
Response: The SDT thanks you for your comments. The changes have been made in the footnotes.
Niagara Mohawk Power
Corporation (dba National
No
It is still unclear whether Danger Tree rights are included in this definition. Additional question:
Can we establish a list/database in 2011 stating the widths for the pre-2007 vegetation
Consideration of Comments on Draft 5 of FAC-003-2
14
Organization
Yes or No
Grid)
Question 1 Comment
management records? There is no definition of ROW listed in FAC-003-1, however in the NERC
Glossary of Terms, Right-of-Way (ROW) is defined as “A corridor of land on which electric lines may
be located. The Transmission Owner may own the land in fee, own an easement, or have certain
franchise, prescription, or license rights to construct and maintain lines.” We propose keeping this
definition.
Response: The SDT thanks you for your comments. The SDT has limited the definition of Right-of-Way to a corridor of land with a defined width to
operate a transmission line. This does not include danger tree rights. While use of the pre-2007 records is a compliance issue and is not in the
purview of the SDT, it is the intent of the language in the definition that you could use this information.
CenterPoint Energy
No
CenterPoint Energy agrees with the removal of “Active Transmission Line ROW” as a defined term.
The change in the NERC Glossary definition for Right-of-Way (ROW) alone, however, does not
address all of the remaining interpretation issues within the Standard that still exist.
The following issues still require resolution:
1. The “force majeure” was moved from the Applicability section to a footnote, and is no longer an
encompassing exception for each Requirement. Therefore, the “force majeure” footnote needs to
be applied not only to R1, R2, R6, and R7 but also R4 and R5. For R4, notification to the control
center would likely be restricted during a natural disaster. For R5, correction action by the control
center may not be possible during a natural disaster.
2. The exception for applicability beyond the “Rating and all Rated Electrical Operating Conditions”
should be included not only in R1, R2, and R3, but also R5 and R7. For R5 and R7, the
encroachment into the MVCD should consider whether the line is operating within its design limits.
3. The use of the term “Fault” in M1 and M2 should be revised to “Sustained Outage”. A “Fault”
can be associated with a Momentary Outage or a Sustained Outage. The scope of R1 and R2 is
specific to Sustained Outages only. The Periodic Data Submittal is specific to Sustained Outages
only as well. If a later confirmation of a “Fault” by the Transmission Owner indicates that a
vegetation encroachment into the MVCD was due to a fall-in from inside the ROW, yet caused only
Consideration of Comments on Draft 5 of FAC-003-2
15
Organization
Yes or No
Question 1 Comment
a Momentary Outage, the Transmission Owner would be in violation of R1 because M1 considers it
to be the equivalent of a Real-time observation. The current scope of the Standard is not intended
to include Momentary Outages. If it was, the Periodic Data Submittal would capture this type of
outage, which it does not.
4. In the Introduction Section 5 - Background, fall-ins are characterized as “statistically
intermittent” and “these types of events are highly unlikely to cause large-scale grid failures”.
CenterPoint Energy agrees and therefore recommends that fall-ins be excluded from the
Requirements R1, R2, and Periodic Data Submittal of outages. This would negate the need for
determining the limits of the ROW, thus simplifying the Standard to a great margin while not
sacrificing the emphasis of the Standard. The Draft 5 Background Information states the criteria for
developing a results-based reliability standard such that “each requirement should identify a clear
and measurable expected outcome.” When the determination of the limits of the ROW goes
beyond the interpretation of the legal limits of the ROW, it adds a level of complexity that may be
unclear and not deterministically measurable.
5. For R6, CenterPoint Energy believes the detailed rationale and studies used for the
determination of the required one year inspection cycle should be included in the Guidelines and
Technical Basis. The explanation provided in the Rationale that it is “based upon average growth
rates across North America and on common utility practice” are unfounded and arbitrary without a
specific reference to a North American study.
6. R7 contains the phrase, “provided they do not put the transmission system at risk of a vegetation
encroachment”. CenterPoint Energy recommends this phrase be replaced with the more specific
terminology used in the Rationale for R7 and R3: “provided they do not allow encroachment of
vegetation into the MVCD.”
7. CenterPoint Energy believes the Periodic Data Submittal should be clarified as to the specific
conditions under which Sustained Outages are reported. There is a reference to footnote 2
regarding the exclusion for the “force majeure”; however, the exclusion for lines operating outside
their design limits as mentioned in R1, R2, and R3 is missing. CenterPoint Energy believes the
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
wording should be changed to include all applicable exclusions for added clarity and recommends
the following wording: “The Transmission Owner will submit a quarterly report to its Regional
Entity, or Regional Entity’s designee, identifying all Sustained Outages of applicable transmission
lines operating within their Facility Rating and all Rated Electrical Operating Conditions as
determined by the Transmission Owner to have been caused by vegetation, except as excluded in
footnote 2, which includes as a minimum, the following:”
8. The Guidelines and Technical Basis and the Technical Reference with the Gallet Equation should
be combined into one document as a supplement to the Standard to avoid duplication in wording
and misinterpretation of context.
9. The Guideline and Technical Basis under Requirement R6 refers to the “percentage of the
required ROW inspections completed” and should be revised to match the wording of R6 and the
VSL for R6 as the “percentage of applicable transmission line inspections completed.”
10. CenterPoint Energy agrees that the Rationale test boxes should be deleted from the Standard
and applicable explanatory text be included within the Guidelines and Technical Basis.
11. The Guidelines and Technical Basis should contain specific examples for determining if a fall-in
is considered inside or outside the ROW.
12. CenterPoint Energy recommends modifying the Technical Reference section regarding
“Selecting a Maintenance Approach” to delete the sentences beginning with, “If constraints cannot
be overcome and if design clearances are sufficient...” and continuing through to, “identified early
for rectification.” This example may lead the public to inappropriately ask the utilities for
exceptions to allow vegetation beneath the transmission lines, and it also does not address the
dynamics of future modifications to the transmission lines (e.g. higher operating temperatures or
new conductors) that may necessitate reduced clearances to ground, thus requiring removal of
now mature vegetation. The example should not be included in a Standard intended to reduce
vegetation risks to the transmission system. It is also in conflict with later statements in the
Technical Reference regarding Set Objectives which emphasize maintaining access and clear lines of
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
sight.
13. In general, CenterPoint Energy strongly believes the proposed FAC-003-2 has gone far beyond
what was contemplated by the Commission in FERC Order 693. The Commission's determination
dealt with the following areas: (1) applicability; (2) inspection cycles; and (3) minimum clearances
on National Forest Service lands. For instance, in Paragraph 729, the Commission states, “As
proposed in the NOPR, the Commission approves Reliability Standard FAC-003-1 with no proposed
modification on the issue of clearances. The Commission reaffirms its interpretation that FAC-003-1
requires sufficient clearances to prevent outages due to vegetation management practices under
all applicable conditions....” Rewriting the minimum clearances introduces a new set of confusing
definitions, and further burdens the Transmission Owners with new documentation requirements
while providing little, if any, benefit when compared to the Clearance 2 concept in the existing
Standard.A preferred approach would be to incorporate the following few items into the existing
Standard FAC-003-1: (1) the RC versus the RRO; (2) the designation of a specific inspection
frequency; (3) the Gallet equation; and (4) the applicability to National Forest Service lands.
Response: The SDT thanks you for your comments: For clarity the SDT separated various items in your comments and repeated them below with
the numbered responses:
CenterPoint Energy agrees with the removal of “Active Transmission Line ROW” as a defined term. The change in the NERC Glossary definition for
Right-of-Way (ROW) alone, however, does not address all of the remaining interpretation issues within the Standard that still exist. The following
issues still require resolution:
1. The “force majeure” was moved from the Applicability section to a footnote, and is no longer an encompassing exception for each Requirement.
Therefore, the “force majeure” footnote needs to be applied not only to R1, R2, R6, and R7 but also R4 and R5. For R4, notification to the control
center would likely be restricted during a natural disaster. For R5, correction action by the control center may not be possible during a natural
disaster.
Response: Thank you for your comment. The SDT considers the term “without intentional delay” to be adequate coverage for force majeure issues
in R4. R5 requires that if you cannot perform work regardless of the reason you must come up with a plan to ensure that you prevent
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
encroachments, therefore a force majeure exemption is not applicable.
2. The exception for applicability beyond the “Rating and all Rated Electrical Operating Conditions” should be included not only in R1, R2, and R3, but
also R5 and R7. For R5 and R7, the encroachment into the MVCD should consider whether the line is operating within its design limits.
Response: The SDT thanks you for your comments. The SDT made the suggested changes to remove references to arboricultural, horticultural or
agricultural activities from the footnote 2, but did not adopt the suggestion for the new footnote 6 which replaces the footnote 4 to which you
refer” because that footnote 4 is concerned with completing the annual work plan, The SDT does not envision that actions by property owners such
as installation, or removal or digging of vegetation as a valid impediment to completion of the annual work plan. However this term is relevant in R1
and R2 and as such is within foot note 2 because such actions do occur from time to time without the transmission Owner’s knowledge and do then
result in conditions that could lead to encroachments and outages before the Transmission Owner has the opportunity to rectify the condition.
3. The use of the term “Fault” in M1 and M2 should be revised to “Sustained Outage”. A “Fault” can be associated with a Momentary Outage or a
Sustained Outage. The scope of R1 and R2 is specific to Sustained Outages only. The Periodic Data Submittal is specific to Sustained Outages only as
well. If a later confirmation of a “Fault” by the Transmission Owner indicates that a vegetation encroachment into the MVCD was due to a fall-in
from inside the ROW, yet caused only a Momentary Outage, the Transmission Owner would be in violation of R1 because M1 considers it to be the
equivalent of a Real-time observation. The current scope of the Standard is not intended to include Momentary Outages. If it was, the Periodic Data
Submittal would capture this type of outage, which it does not.
Response: Thank you for your comment. The reporting of Sustained Outages is simply to fulfill routine data submission. The SDT does not intend to
create a system that requires a root cause analysis of all Faults which are not Sustained Outages. The SDT did intend for those Faults as referenced in
M1 and M2 to be considered the equivalent of an encroachment observed in real time. The SDT also notes that the term Fault is an existing defined
term and momentary interruption is not.
4. In the Introduction Section 5 - Background, fall-ins are characterized as “statistically intermittent” and “these types of events are highly unlikely
to cause large-scale grid failures”. CenterPoint Energy agrees and therefore recommends that fall-ins be excluded from the Requirements R1, R2,
and Periodic Data Submittal of outages. This would negate the need for determining the limits of the ROW, thus simplifying the Standard to a great
margin while not sacrificing the emphasis of the Standard. The Draft 5 Background Information states the criteria for developing a results-based
reliability standard such that “each requirement should identify a clear and measurable expected outcome.” When the determination of the limits
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
of the ROW goes beyond the interpretation of the legal limits of the ROW, it adds a level of complexity that may be unclear and not deterministically
measurable.
Response: Thank you for your comment. Fall-ins from inside the ROW are indicators of a poor performing vegetation management program. The
definition of Right-of-Way identifies methods to define the width of the corridor establishing whether vegetation was located within the ROW and
subject to the Transmission Owner’s legal rights.
5. For R6, CenterPoint Energy believes the detailed rationale and studies used for the determination of the required one year inspection cycle should
be included in the Guidelines and Technical Basis. The explanation provided in the Rationale that it is “based upon average growth rates across
North America and on common utility practice” are unfounded and arbitrary without a specific reference to a North American study.
Response: Thank you for your comment. The SDT established an inspection cycle at least once per calendar year and with no more than 18 months
between inspections on the same ROW. This cycle was based on industry comments submitted to Draft 1 of this standard ending on 11-25-2008
6. R7 contains the phrase, “provided they do not put the transmission system at risk of a vegetation encroachment”. CenterPoint Energy
recommends this phrase be replaced with the more specific terminology used in the Rationale for R7 and R3: “provided they do not allow
encroachment of vegetation into the MVCD.”
Response: Thank you for your comment. The SDT agrees and has made the requested change to the draft standard.
7. CenterPoint Energy believes the Periodic Data Submittal should be clarified as to the specific conditions under which Sustained Outages are
reported. There is a reference to footnote 2 regarding the exclusion for the “force majeure”; however, the exclusion for lines operating outside their
design limits as mentioned in R1, R2, and R3 is missing. CenterPoint Energy believes the wording should be changed to include all applicable
exclusions for added clarity and recommends the following wording: “The Transmission Owner will submit a quarterly report to its Regional Entity,
or Regional Entity’s designee, identifying all Sustained Outages of applicable transmission lines operating within their Facility Rating and all Rated
Electrical Operating Conditions as determined by the Transmission Owner to have been caused by vegetation, except as excluded in footnote 2,
which includes as a minimum, the following:”
Response: Thank you for your comment. The SDT added your recommended language on “within its Rating and all Rated Electrical Operating
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
Conditions”.
8. The Guidelines and Technical Basis and the Technical Reference with the Gallet Equation should be combined into one document as a
supplement to the Standard to avoid duplication in wording and misinterpretation of context.
Response: Thank you for your comment. The Guideline and Technical section is part of the NERC Results Based Standard format. The Technical
Reference is a supplemental document that explains the VMSDT thought process in developing the requirements and applies to this version of the
standard.
9. The Guideline and Technical Basis under Requirement R6 refers to the “percentage of the required ROW inspections completed” and should be
revised to match the wording of R6 and the VSL for R6 as the “percentage of applicable transmission line inspections completed.”
Response: Thank you for your comment. VSL’s for R6 has been changed to align with the NERC Standard Development guidelines to “a Transmission
Owner failed to inspect”.
10. CenterPoint Energy agrees that the Rationale test boxes should be deleted from the Standard and applicable explanatory text be included within
the Guidelines and Technical Basis.
Response: Thank you for your comment.
11. The Guidelines and Technical Basis should contain specific examples for determining if a fall-in is considered inside or outside the ROW.
Response: Thank you for your comment. The SDT established the definition of a ROW and a fall-in resulting from vegetation would be determined
through investigation of the sustained outage.
12. CenterPoint Energy recommends modifying the Technical Reference section regarding “Selecting a Maintenance Approach” to delete the
sentences beginning with, “If constraints cannot be overcome and if design clearances are sufficient...” and continuing through to, “identified early
for rectification.” This example may lead the public to inappropriately ask the utilities for exceptions to allow vegetation beneath the transmission
lines, and it also does not address the dynamics of future modifications to the transmission lines (e.g. higher operating temperatures or new
conductors) that may necessitate reduced clearances to ground, thus requiring removal of now mature vegetation. The example should not be
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
included in a Standard intended to reduce vegetation risks to the transmission system. It is also in conflict with later statements in the Technical
Reference regarding Set Objectives which emphasize maintaining access and clear lines of sight.
Response: Thank you for your comment. This verbiage is part of an example describing a combination of strategies which may be utilized by a
Transmission Owner.
13. In general, CenterPoint Energy strongly believes the proposed FAC-003-2 has gone far beyond what was contemplated by the Commission in
FERC Order 693. The Commission's determination dealt with the following areas: (1) applicability; (2) inspection cycles; and (3) minimum clearances
on National Forest Service lands. For instance, in Paragraph 729, the Commission states, “As proposed in the NOPR, the Commission approves
Reliability Standard FAC-003-1 with no proposed modification on the issue of clearances. The Commission reaffirms its interpretation that FAC-003-1
requires sufficient clearances to prevent outages due to vegetation management practices under all applicable conditions....” Rewriting the
minimum clearances introduces a new set of confusing definitions, and further burdens the Transmission Owners with new documentation
requirements while providing little, if any, benefit when compared to the Clearance 2 concept in the existing Standard.A preferred approach would
be to incorporate the following few items into the existing Standard FAC-003-1: (1) the RC versus the RRO; (2) the designation of a specific inspection
frequency; (3) the Gallet equation; and (4) the applicability to National Forest Service lands.
Response: Thank you for your comment. The SDT believes the FAC 003-2 is an improvement over Version 1 and followed the SAR establishing that
the SDT should revise the standard.
Duke Energy
Yes
South Carolina Electric and
Gas
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Individual
Yes or No
Question 1 Comment
My Comments do not relate to the question asked, however, I saw no other place to add my
comment.
I would like to thank NERC for allowing the public to participate in the process of improving the
reliability standard FAC-003-1. I became interested in Vegetation Management requirements for
Transmission Lines, after Con Edison clear cut the ROW behind my home. I appreciate the
importance of safe and reliable electrical service, and recognize how an effective TVMP
contributes to this goal.
In this whole process, what has dispirited me the most, is the inaccurate information being
conveyed about why the clear cutting was necessary and, the causes of the August 14th, 2003
blackout. The narrative goes something like..”a tree falling onto transmission lines caused the
black out of 2003.” I find it harmful because it misdirects the focus from the grid’s short fallings,
and impedes upgrading the system to improve reliability.
I found this same philosophy in the initial pages of CN Utility’s document, UTILITY VEGETATION
MANAGEMENT FINAL REPORT MARCH 2004. It suggests that had the trees been adequately
maintained, the blackout would have most “likely” not happened. Now I am aware of the
qualification of the word “likely,” but the document is heavily weighted on the contribution of tree
contact to the blackout. We know that de-regulation and the physical nature of A.C. current had
more to do with the causes of the blackout, than tree contact. The timeline shows a range of
cascading system failures that created the catastrophic event. The trouble began at 1:58 p.m.
when First Energy generating plant in Eastlake, Ohio, shuts down. At 3:06 p.m. a First Energy 345kV transmission line fails. As a result, at 3:17 p.m voltage dips temporarily on the Ohio portion of
the grid. Controllers take no action, but power shifted onto another power line, overloading it and,
causing it to sag into a tree and go offline at 3:32 p.m. Mid West ISO and First Energy controllers
fail to inform system controllers in nearby states. At 3:41 and 3:46 p.m., two breakers connecting
First Energyʼs grid with American Electric Power are tripped. 4:05 p.m., a sustained power surge
on some Ohio lines signals more trouble building. At 4:09:02 p.m., voltage sags deeply, as Ohio
draws 2 GW of power from Michigan. 4:10:34 p.m., many transmission lines trip out, beginning in
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
Michigan and then in Ohio, blocking the eastward flow of power. Generators go down, creating a
huge power deficit, in seconds, power surges out of the East, tripping East coast generators, and
the rest is history.
The U.S.-Canada Power System Outage Task Force: Final Report on Implementation of
Recommendations, September 2006, states that “Inadequate reactive supply was a factor in most
of the events.” and “the assumed contribution of dynamic reactive output of system generators
was greater than the generators actually produced, resulting in more significant voltage problems.”
The backup generators were not adequate to handle the amperage load or voltage needed. A lack
of coordination of System Protection Programs(relays tripping), inadequate communication
between Utilities/TOs, and lack of "training of operating personnel in dealing with severe system
disturbances" are all the causes for the blackout.
With respect to vegetation management, the findings from The U.S.-Canada Power System Outage
Task Force: Final Report on Implementation of Recommendations, September 2006, clearly did not
intend for transmission owners to develop a one-size-fits-all standard.
The Energy Policy Act of 2005, initiated NERC to draft and adopt the standard FAC-003-1. When I
read through the standard, it all seems very reasonable. I can understand the stiff penalties for
noncompliance because it seems, like an easy fix, compared to the necessary, major changes in
infrastructure. The principles further outlined in ANSI A300 VII, and “Best Practices” IVM, seem
very reasonable too. There is mention of the environment, property owners, even proper pruning
techniques. The wire zone clearance of 10 feet and, allowing low growing compatible vegetation in
the boarder zone, seems to retain more vegetation, than remove.
However, in practice, the TOs are simply clear cutting the ROW, with no regard for the enviroment,
the trees that they are cutting, or the abutting properties. It took Con Edison 2 1/2 half days to
clear 450 tress form behind our home. We are now forced to see and hear 93,000 cars a day from
the Sprain Parkway. Following the clearing, our real estate broker dropped the asking price by
30%. The house remains empty and unsold. Apparently, no one is interested in spending 32,000K
a year in property taxes to look at transmission towers/lines and live on a highway. This has been
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
devastating to our family, and thousands of others in Westchester County. They removed a buffer
of trees that were 150 feet away from wires and towers, on a downward slope. These trees would
have never made contact with conductors.
Con Edison’s defense is that they did it because it was in their right to. Moreover, they use the
NERC fine structure to defend their behavior.I went through the Notice of Penalties that NERC has
issued from 6/2/08-2/01/11. Out of 646 Notice of Penalties, 1700 violations were sited, 36 out of
1700 penalties were issued for violations to the FAC- 003-1 standard. Some NOPs had multiple
violations-18 R1 violations were cited and 29 penalties were issued for R2 violations. Out of the 29
R2 penalties, 20 involved tree contact. Some outages were caused by sagging wires, some were
caused by arcing electricity looking for a ground fault, but none were caused by a tree falling onto
the transmissions wires. The numbers should put into perspective how immaterial the problem of
tree contact really is.
Think about it... 20 out of 1700 involved tree contact, and none of then resulted in a sustained
outage. That means 1680 violations were issued due to other system failures. To use these
penalties as an excuse is a complete over exaggeration. What is missing from the standard and the
fine structure, are penalties for over cutting and violations to other stipulations, such as proper
communication, training, and aftercare of the affected areas. The problems that have arisen from
current TVMP activities being executed nationally on our ROWs, is not a public perception
problem. Rather, TOs are not complying with standards that are meant protect the environment
and they are not respecting the property rights of the neighboring homeowners.
I appreciate the opportunity to share my views, and would take any opportunity to further
participate in protecting the rights of property owners, and the environment, while working to
secure safe and reliable electrical service. Most respectfully, Amy M Kupferberg - Utility Whisperer
Response: The SDT thanks you for your comments. You raise a host of issues regarding the operations of electric transmission systems as well as
recounting the blackout of 2003. We agree there seems to be wide public opinion of what actually was the cause of the blackout. Relative to your
recommendations for our team, we note that appropriate NERC standards contain requirements regarding training and communications among
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
other things. For example, requirement R4 of this standard contains language which requires communication when certain vegetation conditions
are discovered. As you know training and communications were just two of the many issues addressed in the blackout report.
In response to your comment “What is missing from the standard and the fine structure, are penalties for over cutting and violations to other
stipulations, such as proper communication, training, and aftercare of the affected areas,” this Standard is meant to define what needs to be
accomplished to achieve reliability; it is up to the Transmission Owner to perform the vegetation maintenance in a manner to accomplish that goal
consistent with applicable environmental concerns and local regulations.
Consolidated Edison Company
of New York, Inc. Transmission Line
Maintenance
Yes
USACE
Yes
CECD
Yes
Entergy Services, Inc
Yes
The revised Glossary definition of ROW helps to clarify the intent of what is expected and/or
considered ROW stipulations. This is a beneficial addition/clarification.
Response: The SDT thanks you for your comments.
Orange and Rockland Utilities,
Inc.
Yes
National Grid
No
The revised ROW definition emphasizes the ROW width needed to operate the transmission line(s).
It is National Grid’s interpretation that the width established when the line was constructed is the
width to be maintained. This width is documented in engineering drawings, per-2007 vegetation
records or blow-out standards. This definition does not imply that danger tree rights beyond the
constructed and maintained width are incorporated in the definition; therefore fallins - from
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
outside the ROW but within within an area with danger tree rights would not be considered fallinins from within the ROW. National Grid would like the SDT to comment on this interpretation in its
response to these comments.
Response: The SDT thanks you for your comments. Your interpretation is consistent with the intent of the definition that the SDT provided.
However the definition includes a series of options that give the Transmission Owner latitude in establishing ROW width. It does not require
selecting a single method for its system. This phrase in the definition allows a TO to use its internal engineering standards or the general
engineering standards that were in effect when the line was constructed to determine the ROW width. The SDT has limited the definition of Rightof-Way to a corridor of land with a defined width to operate a transmission line. This does not include danger tree rights.
Western Electricity
Coordinating Council
Yes
Georgia Transmission Corp.
Yes
Northern Indiana Public
Service Company
Yes
Consideration of Comments on Draft 5 of FAC-003-2
27
2.
In R1 and R2 and their associated VSLs, the SDT added the phrase “in order of increasing severity” and added the sentence
“The types of encroachments are listed in order of increasing degrees of severity in non-compliant performance as it relates to
a failure of a TO’s vegetation maintenance program.” to the Rationale boxes for R1/R2. Do you agree? If answer is no, please
explain.
Summary Consideration: 32 of the 38 responses agreed with the changes. The SDT made changes to the footnotes in response to
4 requests. Three of the “yes” response comments included positive references to the improved clarity, alignment with results based
standards, reinstatement of Category 3 outages and the importance of investigations which will be necessary to categorize violations
across the various VSLs.
The disagreements included concerns over the relationships between the VSLs and language in requirements. The SDT revised the
language in the Rationale box to explain the program performance relationships between types of encroachments, faults and
outages, and various types of failed maintenance, and how the various types of failed maintenance have historically been associated
with known vegetation related events.
In response to a request to exchange the order of severity levels of the failure to maintain vegetation to prevent encroachments
from blowing together versus fall-ins, the SDT explained that the blowing together is considered a higher severity level of failed
maintenance since the sway of the conductor is in most cases more determinable and less variable than the more complex geometry
associated and numerous variables associated with fall-ins.
In response to a comment that there was no need for R1 and R2, the SDT explained that removal of R1 and R2 could be viewed as
lessening the reliability of the standard.
One comment recommended that the standard include language to allow any encroachment found and removed, absent a Fault or
Sustained Outage, to not be considered a violation. The SDT noted that the MVCD is a component that must be considered in the
“building block” approach inherent in the standard, and as such, any encroachment inside the MVCD indicates a significant failure in
overall vegetation program approach.
One comment requested a return to the Clearance 1 in the existing standard to support work that is resisted by property owners
and other parties that do not want vegetation to be adequately maintained. The SDT referenced the problem associated with a fillin-the-blank requirement, and explained how this standard does not preclude a utility from removing or pruning vegetation well
beyond the MVCD, but primarily focuses on determining when a violation occurs. The SDT asserts that vegetation maintenance must
Consideration of Comments on Draft 5 of FAC-003-2
28
address the many variables that exist such as growth rates, vegetation maintenance cycles, conductor sag and sway, etc. that could
result in an encroachment of the MVCD which would be a direct violation of the standard. The vegetation program must factor in
delays and/or mitigation measures associated with stakeholder concerns, but must clearly communicate the need for maintenance
to ensure strict compliance with this zero-tolerance standard.
Organization
Yes or No
SERC Vegetation Management
sub-committee
Yes
Hydro One Networks
Yes
Northeast Power Coordinating
Council
Yes
Platte River Power Authority
Substation Maintenance
Group
Yes
Bonneville Power
Administration
Yes
Question 2 Comment
BPA prefers the stratified levels of violation severity presented in the table for R1 and R2.Foot note
#2 on page 8 needs to be clarified with respect to arboricultural activities or horticultural or
agricultural activities. What specifically does this phrase refer to?Foot note #4 on page 12 needs to
be clarified with respect to arboricultural activities or horticultural or agricultural activities. What
specifically does this phrase refer to?
Response: The SDT thanks you for your comments.
The SDT has changed footnote 2 to read as follows:
This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to this reliability standard,
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 2 Comment
including natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by
the Transmission Owner or an applicable regulatory body, ice storms, and floods; human or animal activity such as logging, animal severing tree,
vehicle contact with tree, or installation, removal, or digging of vegetation. Nothing in this footnote should be construed to limit the Transmission
Owner’s right to exercise its full legal rights on the ROW.
The SDT has changed footnote 4 (now footnote 6 in the revised standard) to read as follows:
Circumstances that are beyond the control of a Transmission Owner include but are not limited to natural disasters such as earthquakes, fires,
tornados, hurricanes, landslides, ice storms, floods, or major storms as defined either by the TO or an applicable regulatory body.
NERC Staff
No
The sentence was added to the rationale but the phrase “in order of increasing severity” is not in
the requirement or their associated VSLs. NERC staff does not support the language in the rationale
box which differentiates the VSL based on skill level of maintenance personnel rather than the
impact to reliability of the encroachment. The VSL should be based on whether or not the owner
managed the vegetation to prevent encroachment and therefore be binary. See additional
comments submitted separately regarding combining R1 and R2.
Response: The SDT thanks you for your comments. VSLs should not be assigned based on the impact to reliability, as is proposed by the
commenter. NERC’s VSL Guidelines state the following regarding VSLs: “This is not the same as saying that the requirement is really important and
any noncompliance would have an adverse reliability impact – the impact to reliability should be addressed through the VRF, not the VSL.”
However, the SDT has made changes to reword the rationale in R1 and R2 to further explain how program performance must successfully account
for the relationships between types of encroachments, faults and outages, various types of failed maintenance, and how the various types of failed
maintenance have historically been associated with known vegetation related events.
Pepco Holdings Inc and
Affiliates
Yes
FirstEnergy
No
For the Requirement R1 and R2 VSLs, we suggest that the proposed Moderate (fall-ins) and High
(blowing together) VSL be interchanged. We believe that fall-ins are more severe encroachments
than blowing together and the categories listed in the compliance section support this point.
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 2 Comment
Category 1 (grow-ins) is most severe, followed by Category 2 & 3 (fall-ins) and Category 4 (blowing
together).
Response: The SDT thanks you for your comments. The choice of the VSL for the fall-ins versus the blowing together was made by the SDT using
logic in the language in the rationale text box for R1: “The types of failure to manage vegetation are listed in order of increasing degrees of severity
in non-compliant performance as it relates to a failure of a TO’s vegetation maintenance program, since the encroachments listed require different
and increasing levels of skills and knowledge and thus constitute a logical progression of how well, or poorly, a TO manages vegetation relative to
this Requirement.”
Dominion Electric Market
Policy
Yes
Southern Company
Transmission
Yes
Arizona Public Service
Company
No
This is a reliability standard and the TO should know what its clearance needs are at all rated
conditions, especially considering today’s technology. If the TO manages to this standard there is
no need for R1 and R2.
Response: The SDT thanks you for your comments. Elimination of R1 and R2 would be considered as a lessening of the standard.
Salt River Project
Yes
Tampa Electric Company
Yes
Adds clarity to the VSL from an audit perspective, this is an improved description to the Standard.
Response: The SDT thanks you for your comments.
NextEra Energy
Yes
Although NextEra Energy Inc. (NextEra), including Florida Power & Light Company, agrees with the
changes referenced for R1 and R2, NextEra is concerned that the exemptions identified in footnote
Consideration of Comments on Draft 5 of FAC-003-2
31
Organization
Yes or No
Question 2 Comment
2 for “...arboricultural activities or horticultural or agricultural activities...,” and similar language in
footnote 4, are too broad. For example, this language appears to include an exemption for a
landowner, who, during arboricultural activities or horticultural or agricultural activities, causes a
vegetation contact with a transmission line (e.g., cutting or lifting a tree into a transmission line).
This places the Transmission Owner in the difficult position of a landowner arguing it is exempt
from a controllable risk. Thus, the “...arboricultural activities or horticultural or agricultural
activities...” references should be removed from footnote 2, and the similar language in footnote 4
Response: The SDT thanks you for your comments. The SDT made the suggested changes.
SDG&E
Yes
ASSET MANAGEMENET
Yes
Hydro-Quebec TransEnergie
(NCR07112)
Yes
Kansas City Power & Light
No
These proposed Requirements, Measures and Violation Severity Levels as written do not give credit
to the Transmission Owners for effectively monitoring their systems and taking appropriate actions
in regard to vegetation clearing. Why does it make sense to punish and penalize a Transmission
Owner for discovering an encroachment when they take the appropriate actions to remedy the
condition before any facility outage occurs that results in compromising the reliability of the Bulk
Electric System? These Requirements, Measures and VSL’s should recognize the good practices of
effective response to a vegetation condition and penalize ineffective response. Recommend the
SDT consider including appropriate language to recognize effective remedial actions by
Transmission Owners and by doing so, recognize effective efforts instead of punishing them. In
addition, proving encroachments have not occurred will pose audit challenges in determining that
encroachments have not occurred for the Auditors as well as Registered Entities. If no
encroachments occur, then there is nothing to report or record. This is a weak platform to stand
Consideration of Comments on Draft 5 of FAC-003-2
32
Organization
Yes or No
Question 2 Comment
compliance on. Facility interruption events caused by vegetation contacts is definitively
measurable and recordable. Recommend the SDT reconsider the concept of compliance with FAC003 on the basis of sustained outages and remove the references regarding encroachments only.
Recommend the SDT remove the LOWER VSL language from Requirements R1 and R2 and revise
the Requirements and Measures to reflect the same.
Response: The SDT thanks you for your comments. The MVCD was established as a beginning of a series of “building blocks” for a good program.
R3 requires that a TO add to MVCD distances with further considerations for the variables of conductor movement and the variables associated
with vegetation growth when designing the TO’s overall vegetation management approach(s). The net result of this “building block” approach is
the management of vegetation at clearance distances much greater than the MVCD distances. Other related requirements of this “Defense in
Depth” Standard serve to address any number of scenarios which may arise or hinder the TO’s ability to always strictly adhere to the management
approach(s) established within R3. Thus the other requirements of this Standard provide the latitude for “appropriate actions to remedy the
condition” without penalty. Further, it is obvious that trees which have encroached inside of the MVCD are clear evidence of a failed vegetation
management program.
Manitoba Hydro
Yes
Central Maine Power
Company - IberdrolaUSA
Yes
BC Hydro
Yes
American Transmission
Company, LLC
Yes
American Electric Power
No
American Electric Power believes that the phrase "arboricultural activities or horticultural or
agricultural activities" was mistakenly introduced into Footnotes 2 and 4, and should be deleted
from both footnotes. If the phrase remains in the Standard, it may empower orchard growers,
landowners and others to plant trees on the right of way and challenge Transmission Owners'
Consideration of Comments on Draft 5 of FAC-003-2
33
Organization
Yes or No
Question 2 Comment
rights to perform maintenance on the presumption that the standard will exempt the TO from
violating the outage or encroachment requirements.
Response: The SDT thanks you for your comments. The SDT made the suggested changes.
Baltimore Gas and Electric Co.
Yes
TVA
Yes
Niagara Mohawk Power
Corporation (dba National
Grid)
Yes
CenterPoint Energy
Yes
Duke Energy
Yes
We agree with the drafting team’s approach, and also agree with reinstating reporting of Category
3 (Fall-ins from outside the ROW) in the Additional Compliance Information section. The SDT
responded to comments submitted with the last ballot that:”Zero tolerance for vegetation caused
outages is a stated goal of FERC and NERC as it relates to this standard. This policy is part of FAC003-1 and in concept did not change with the proposed version. The SDT recognizes this concern
and has developed gradation taking into account line criticality in VRF’s and type of outage not
contained in the current version FAC-003-1. Finally, it is also important to note that each and every
incident or potential violation is investigated and addressed based on the specific circumstances
surrounding the particular event. These investigations should necessarily take into consideration
and recognize the utility's individual efforts in responding to an encroachment situation.” In
addition, we believe that clarifying changes need to be made to footnotes 2 and 4. Clarify footnote
2 by removing the phrase “arboricultural activities or horticultural or agricultural activities” and
replacing it with the phrase “installation of”. Similarly, clarify footnote 4 by removing the phrase
“arboricultural, horticultural or agricultural activities”, and replacing it with the phrase “or human
Consideration of Comments on Draft 5 of FAC-003-2
34
Organization
Yes or No
Question 2 Comment
activities such as installation, or removal or digging of vegetation.”
Response: The SDT thanks you for your comments. The SDT made the suggested changes to remove references to arboricultural, horticultural or
agricultural activities from the footnote 2, but did not adopt the suggestion for the new footnote 6 which replaces the footnote 4 to which you
refer” because that footnote 4 is concerned with completing the annual work plan, The SDT does not envision that actions by property owners
such as installation, or removal or digging of vegetation as a valid impediment to completion of the annual work plan. However this term is
relevant in R1 and R2 and as such is within foot note 2 because such actions do occur from time to time without the transmission Owner’s
knowledge and do then result in conditions that could lead to encroachments and outages before the Transmission Owner has the opportunity to
rectify the condition.
South Carolina Electric and
Gas
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
This is more in alignment with a results-based reliability standard.
Response: The SDT thanks you for your comments.
Individual
Consolidated Edison Company
of New York, Inc. Transmission Line
Maintenance
Yes
USACE
Yes
Consideration of Comments on Draft 5 of FAC-003-2
35
Organization
Yes or No
CECD
Yes
Entergy Services, Inc
Yes
Orange and Rockland Utilities,
Inc.
Yes
National Grid
Yes
Western Electricity
Coordinating Council
Yes
Georgia Transmission Corp.
Yes
Northern Indiana Public
Service Company
No
Question 2 Comment
While there are some enhancements to the organization and content of the standard such as the
addition of the Guidelines and Technical Basis section, clarification of what constitutes evidence of
compliance, and tailoring of VSL severity levels for the requirements based on the risk each poses
to the likelihood of contributing to a cascade, too many elements present in FAC-003-1 and which
are vital to preventing vegetation caused outages and maximizing system reliability, have been
eliminated from FAC-003-2. Specifically, the elimination of concrete, declared and audited
clearance standards between vegetation and conductors (the existing Clearance 1 and Clearance 2
(R1.2)) Requirements) in the revised standard is a major defect that will decrease system reliability.
It has been indispensable for NIPSCO when communicating with stake holders (governments,
interest groups, land owners, the public, etc.) to point to these clearance standards to give
credibility and support to the kind of tree removal and trimming that is necessary to achieve the
stated objective of zero preventable tree caused outages. Without these declared clearance
standards in the NERC standard, utility vegetation managers will constantly be challenged by stake
holders to show them that such work is required rather than an elective choice on the utility's part.
One of the key lessons learned from the 2003 blackout and First Energy's overgrown ROW tree
Consideration of Comments on Draft 5 of FAC-003-2
36
Organization
Yes or No
Question 2 Comment
problem was that individual land owners, local governments, and interest groups will exert
pressure on the utility to only do the minimum amount of vegetation management. Without
external and enforceable Vegetation Clearance Standards and by returning to a pre-2003 regime
where the extent of vegetation clearing is left to the individual discretion and pressures at each
utility, there is no doubt that tree clearance conditions will deteriorate over time and put system
reliability at greater risk of vegetation contact.
Response: The SDT thanks you for your comments. At the request of FERC in Order 693, the SDT was asked to eliminate the fill-in-the-blank
clearance requirements that are currently in FAC-003-1. A proven Engineering calculation was utilized to determine when a transmission line could
spark over to vegetation without direct contact. Based on this calculation, each utility must determine what clearance levels need to be maintained
as part of their TVMP. The current version does not preclude a utility from removing or pruning vegetation well beyond the MVCD, it just
establishes a line in the sand that determines when a violation occurs. Individual TOs must establish a program that addresses the many variables
that exist such as growth rates, vegetation management cycles, conductor sag and sway, etc. that could result in an encroachment of the MVCD
which would be a direct violation of the standard. Establishing a specific clearance value to be attained during vegetation management activities is
too prescriptive and is in direct conflict with the Results-Based Standard initiative that the SDT is currently implementing. Each TO must factor in
delays and/or mitigation measures associated with stakeholder concerns but must clearly communicate the challenges with maintaining strict
compliance with this zero-tolerance standard.
Consideration of Comments on Draft 5 of FAC-003-2
37
3.
In response to comments received regarding the term “investigation” in M1/M2, the SDT substituted “confirmation…by the
Transmission Owner..” in its place, among other minor edits to these measures. Do you agree? If answer is no, please explain.
Summary Consideration: 34 of the 40 comments agreed with the change. One of the affirmative comments noted the need to make
a minor change in the Guidelines and Technical Basis to assure conformance with the standard language; that change was made.
One commenter questioned what would compel an entity to document and report outages. The SDT feels that this issue is
addressed by the NERC Sanctions guidelines.
It was noted that the last two paragraphs in M1 and M2 were not really measures and should be addressed in the requirements. The
requirements now include this language in footnote 3.
Two commenters wished to include language to exempt brief encroachments into the MVCD due to falling trees. The SDT chose not
to make that change due to concerns raised by regulatory observers.
One commenter felt that a violation should occur for any calculated potential for an MVCD encroachment. The SDT noted that the
MVCD is a beginning of a series of “building blocks” for a program to ensure reliability within the line’s rating and all rated electrical
operating conditions. R3 requires that a TO add to MVCD distances with further considerations for the variables of conductor
movement and the variables associated with vegetation growth when designing the TO’s overall vegetation management
approach(s). Additionally there is a “Defense in Depth” in this Standard to address any number of scenarios which may arise or
hinder the TO’s ability to always strictly adhere to the management approach(s) established within R3. Thus the other requirements
of this Standard provide the latitude for appropriate actions to remedy the condition without penalty.
One comment replied that there was no value to the measure due to the lack of reference to a violation for any calculated potential
MVCD encroachment. The SDT pointed again to requirement R3 which requires this to be addressed in the maintenance strategies
in R3.
One commenter suggested to delete the reference to measures in the evidence retention section; the SDT chose to retain the
existing language.
Organization
Yes or No
Consideration of Comments on Draft 5 of FAC-003-2
Question 3 Comment
38
Organization
Yes or No
SERC Vegetation Management
sub-committee
Yes
Hydro One Networks
Yes
Northeast Power Coordinating
Council
Yes
Platte River Power Authority
Substation Maintenance
Group
Yes
Bonneville Power
Administration
Yes
NERC Staff
No
Question 3 Comment
Concur with restating as mentioned above. Other issues remain regarding data reports indicating
no sustained outages or real-time observations. These measures appear to indicate that if the
outages or real-time observations are not documented then an encroachment didn’t occur. What
will compel an entity to document these occurrences? In addition, the last two paragraphs of the
Measure are not really measures. They would be better served as part of the Requirement.
Response: The SDT thanks you for your comments. The issue of how does one prove that an event did not occur is problematic. A TO must
document the inspections it completes. If an inspection does not note an encroachment then none was observed. The NERC Sanction Guidelines
provide adequate sanctions for the dishonest. The SDT agrees that the last two paragraphs are not measures and would belong in the requirement.
The SDT has moved them to the requirement as footnotes.
Pepco Holdings Inc and
Affiliates
Yes
Consideration of Comments on Draft 5 of FAC-003-2
39
Organization
Yes or No
FirstEnergy
Yes
Dominion Electric Market
Policy
Yes
Southern Company
Transmission
No
Question 3 Comment
We would recommend the middle paragraph of M1 and M2 be revised as follows: “If a later
confirmation of a Fault by the TO shows that vegetation encroachment within the MVCD has
occurred from vegetation growing into or blowing into the conductor within the ROW, this shall be
considered the equivalent of a Real-time observation. Brief encroachments caused by a falling tree
going through the MVCD is not considered an encroachment.”
Response: The SDT thanks you for your comments. The SDT is sympathetic to your concern. In fact, the SDT had originally crafted language similar
to that which you suggested. However, due to concerns expressed by regulators and others, the exemption for encroachment violations due to
falling vegetation from inside the right of way was removed.
Arizona Public Service
Company
No
The TO should be managing for reliability. The system is not static, like vegetation it moves and
changes over time and that fluctuation should be taken into account to maintain reliability at all
rated conditions.
Response: The SDT thanks you for your comments. The SDT agrees with your statement, and in that vein, the MVCD was established as a
beginning of a series of “building blocks” for a program to ensure reliability within its rating and all rated electrical operating conditions. R3
requires that a TO add to MVCD distances with further considerations for the variables of conductor movement and the variables associated with
vegetation growth when designing the TO’s overall vegetation management approach(s). The net result of this “building block” approach is the
management of vegetation at clearance distances much greater than the MVCD distances. Other related requirements of this “Defense in Depth”
Standard serve to address any number of scenarios which may arise or hinder the TO’s ability to always strictly adhere to the management
approach(s) established within R3. Thus, the other requirements of this Standard provide the latitude for appropriate actions to remedy the
condition without penalty. Further, trees which have encroached inside the MVCD are evidence of a deficiency in vegetation maintenance.
Consideration of Comments on Draft 5 of FAC-003-2
40
Organization
Yes or No
Salt River Project
Yes
Tampa Electric Company
Yes
Question 3 Comment
Confirmation allows for the potential of a greater number of “action items” than just investigation.
Response: The SDT thanks you for your comments. We agree that confirmation is necessary before an event is determined to be vegetation
related.
NextEra Energy
Yes
SDG&E
Yes
ASSET MANAGEMENET
Yes
Hydro-Quebec TransEnergie
(NCR07112)
Yes
Kansas City Power & Light
Yes
Manitoba Hydro
Yes
Central Maine Power
Company - IberdrolaUSA
Yes
BC Hydro
Yes
American Transmission
Company, LLC
Yes
American Electric Power
No
For increased clarity, AEP offers the following change to the second paragraph of M1, as well as the
Consideration of Comments on Draft 5 of FAC-003-2
41
Organization
Yes or No
Question 3 Comment
second paragraph of M2. The original text “If a later confirmation of a Fault by the Transmission
Owner shows that a vegetation encroachment within the MVCD has occurred from vegetation
within the ROW, this shall be considered the equivalent of a Real-time observation” should be
replaced with ““If a later confirmation of a Fault by the Transmission Owner shows that a
vegetation encroachment within the MVCD has occurred from vegetation growing into or blowing
together with the conductor within the ROW, this shall be considered the equivalent of a Real-time
observation. A brief encroachment caused by falling vegetation passing through the MVCD is not
considered an encroachment in this requirement”.
Response: The SDT thanks you for your comments. The SDT is sympathetic to your concern. In fact, the SDT had originally crafted language similar
to that which you suggested. However, due to concerns expressed by regulators and others, the exemption for encroachment violations due to
falling vegetation from inside the right of way was removed.
Baltimore Gas and Electric Co.
No
M1 & M2 bullet: “Real-time observation of any MVCD encroachments.” implies that real-time
observation of vegetation encroachment ensures reliable operation the Bulk Electric System. The
reliability standard objective states;”To improve the reliability of the electric Transmission system
by preventing those vegetation related outages that could lead to Cascading.”However, real time
observation of current operating conditions provides no assurance that vegetation will not lead to
outages since it doesn’t take into consideration the full conductor range of motion including
maximum sag. BGE recommends removing the language. If an inspector finds vegetation
encroaching into the MVCD during a visual inspection he / she should immediately initiate an
Immediate Threat Notification. Therefore, this measure has no value.
Response: The SDT thanks you for your comments. The SDT agrees with your statement and in that vein, the MVCD was established as a beginning
of a series of “building blocks” for a program to ensure reliability within its rating and all rated electrical operating conditions. R3 requires that a
TO add to MVCD distances with further considerations for the variables of conductor movement and the variables associated with vegetation
growth when designing the TO’s overall vegetation management approach(s). The net result of this “building block” approach is the management
of vegetation at clearance distances much greater than the MVCD distances. Other related requirements of this “Defense in Depth” Standard
serve to address any number of scenarios which may arise or hinder the TO’s ability to always strictly adhere to the management approach(s)
Consideration of Comments on Draft 5 of FAC-003-2
42
Organization
Yes or No
Question 3 Comment
established within R3. Thus the other requirements of this Standard provide the latitude for appropriate actions to remedy the condition without
penalty. Further, trees which have encroached inside the MVCD are evidence of a deficiency in vegetation maintenance.
TVA
Yes
Niagara Mohawk Power
Corporation (dba National
Grid)
Yes
CenterPoint Energy
Yes
Duke Energy
Yes
However, this change was not completely made in paragraph five of the Guideline and Technical
Basis document. There the phrase “an investigation” should be replaced by the phrase “a later
confirmation”
Response: The SDT thanks you for your comments. The SDT made the suggested change.
South Carolina Electric and
Gas
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
Individual
Consolidated Edison Company
of New York, Inc. Transmission Line
Yes
Consideration of Comments on Draft 5 of FAC-003-2
43
Organization
Yes or No
Question 3 Comment
Maintenance
USACE
Yes
CECD
No
Suggested Modification to the Measure - "If an after-the-fact analysis of a Fault by the Transmission
Owner determines that a vegetation encroachment within the MVCD has occurred from vegetation
within the ROW, this shall be considered the equivalent of observing an encroachment in RealTime."
CECD would also like to comment on the Evidence Retention section, as it relates to Measures. The
Evidence Retention section states that the Transmission Owner retains data or evidence to show
compliance with Requirement R1, R2, R3, R5, and R7, Measures M1, M2, M3, M5, M6 and M7 for
three calendar years...." Measures provide examples of evidence that a Transmission Owner can
produce to show compliance with the associated Requirement but are not separate Requirements
to be managed so reference to Measures should be deleted from the Evidence Retention section of
the standard.
Response: The SDT thanks you for your comments. The SDT prefers to keep the existing language, which has been widely accepted by industry,
since it is substantially the same as you suggest. With respect to the Evidence Retention section: The NERC evidence retention guidelines provided
to SDTs recommend including a reference to the associated requirements and measures.
Entergy Services, Inc
Yes
Orange and Rockland Utilities,
Inc.
Yes
National Grid
Yes
Western Electricity
Yes
Consideration of Comments on Draft 5 of FAC-003-2
44
Organization
Yes or No
Question 3 Comment
Coordinating Council
Georgia Transmission Corp.
Yes
Northern Indiana Public
Service Company
Yes
Consideration of Comments on Draft 5 of FAC-003-2
45
4.
In response to comments received that requirement R3 is unclear with respect to intent, the SDT added “maintenance
strategies”. Do you agree this clarifies the intent? If answer is no, please offer alternative language.
Summary Consideration: 36 responses were in agreement, 2 disagreed with no comments and 2 disagreements included
comments.
A concern was raised with regard to using the MVCD as a distance “to manage a vegetation program” and asked the SDT to provide
a buffer distance. The SDT explained that the MVCD was established as a beginning of a series of “building blocks” for a program to
ensure reliability within its rating and all rated electrical operating conditions. R3 requires that a TO add to MVCD distances with
further considerations for the variables of conductor movement and the variables associated with vegetation growth when
designing the TO’s overall vegetation management approach(s). The net result of this “building block” approach is the management
of vegetation at clearance distances much greater than the MVCD distances. Other related requirements of this “Defense in Depth”
Standard serve to address any number of scenarios which may arise or hinder the TO’s ability to always strictly adhere to the
management approach(s) established within R3. Thus the other requirements of this Standard provide the latitude for appropriate
actions to remedy the condition without penalty. Further, trees which have encroached inside the MVCD are evidence of a
deficiency in vegetation maintenance. A performance based standard is not prescriptive in nature but gives guidance to a TO on
“what” to accomplish rather than “how” to accomplish it.
Another agreeable response requested R5 and R7 to include a relationship between the document that is developed for
maintenance strategies and the annual work plan. The SDT explained that the references to the work plan in R5 and R7 are
sufficient. The SDT considers maintenance strategies and work plans to be separate functions. Avoiding the reference to the work
plans in R3 minimizes confusing the two functions.
One disagreement stated that the term “maintenance strategies” was not helpful and recommends the following: “Each
Transmission Owner shall have a documented vegetation management plan that includes maintenance strategies, procedures,
processes, and specifications it uses to prevent the encroachment of vegetation into the MVCD of its applicable lines that include(s)
the following:” The SDT notes that Requirement 3 is a results-based competency requirement and that having a TVMP as required
in version 1 is simply a matter of having documentation, but there was no stipulation or concern for the quality of the TVMP as
called for by version 1. In R3 of the revised Standard, the aspect of quality is introduced. The Transmission Owner must show that it
has maintenance strategies in place that will logically keep vegetation from encroaching into the MVCD.
Consideration of Comments on Draft 5 of FAC-003-2
46
Another disagreement stated that the TVMP shall demonstrate the TO’s ability to manage the system at all rated conditions to
maintain reliability. The SDT agrees that this is the purpose of R3 and referenced the language in the rationale text for R3 clarifies “... documentation provides a basis for evaluating the competency of the Transmission Owner’s vegetation program. There may be
many acceptable approaches to maintain clearances. Any approach must demonstrate that the Transmission Owner avoids
vegetation-to-wire conflicts under all Ratings and all Rated Electrical Operating Conditions. See Figure 1 for an illustration of possible
conductor locations.” A TVMP is one example of an approach to which this refers.
Organization
Yes or No
SERC Vegetation Management
sub-committee
Yes
Hydro One Networks
Yes
Northeast Power Coordinating
Council
Yes
Platte River Power Authority
Substation Maintenance
Group
Yes
Bonneville Power
Administration
Yes
Question 4 Comment
The TO procedures / policies and specifications shall demonstrate the TO’s ability to manage the
system at all rated conditions to maintain reliability.BPA believes that the intent is clear, but the
fundamental approach of using the MVCD (table 2) to manage a vegetation program is still
problematic. These values are flashover distances and are way too close. This is acknowledged in a
footnote to table 2 but no identification of allowable buffers/distances between energized phase
conductors at rated temperatures and vegetation is discussed (this is left up the transmission
owners). Clarity is needed on this topic. Setting a finite distance limit based on recognized
standards, good science and risk avoidance should be done for the industry. BPA previously made
this comment during the drafting of the standard. It was not addressed then, nor has it been
Consideration of Comments on Draft 5 of FAC-003-2
47
Organization
Yes or No
Question 4 Comment
addressed now.
Response: The SDT thanks you for your comments. The SDT agrees with your statement, and in that vein, the MVCD was established as a beginning
of a series of “building blocks” for a program to ensure reliability within its rating and all rated electrical operating conditions. R3 requires that a
TO add to MVCD distances with further considerations for the variables of conductor movement and the variables associated with vegetation
growth when designing the TO’s overall vegetation management approach(s). The net result of this “building block” approach is the management
of vegetation at clearance distances much greater than the MVCD distances. Other related requirements of this “Defense in Depth” Standard
serve to address any number of scenarios which may arise or hinder the TO’s ability to always strictly adhere to the management approach(s)
established within R3. Thus the other requirements of this Standard provide the latitude for appropriate actions to remedy the condition without
penalty. Further, trees which have encroached inside the MVCD are evidence of a deficiency in vegetation maintenance. A performance based
standard is not prescriptive in nature but gives guidance to a TO on “what” to accomplish rather than “how” to accomplish it.
NERC Staff
No
Adding the term “maintenance strategies” is not helpful in the requirement. NERC staff
recommends the following: “Each Transmission Owner shall have a documented vegetation
management plan that includes maintenance strategies, procedures, processes, and specifications
it uses to prevent the encroachment of vegetation into the MVCD of its applicable lines that
include(s) the following:”
Response: The SDT thanks you for your comments. Requirement R3 is a results-based competency requirement. Having a TVMP as required in
version 1 is simply a matter of having documentation. There was no stipulation or concern for the quality of the TVMP as called for by version 1.
In R3 of the revised Standard, the aspect of quality is introduced. The Transmission Owner must show that it has maintenance strategies in place
that will logically keep vegetation from encroaching into the MVCD.
Pepco Holdings Inc and
Affiliates
Yes
FirstEnergy
Yes
Dominion Electric Market
Yes
Consideration of Comments on Draft 5 of FAC-003-2
48
Organization
Yes or No
Question 4 Comment
Policy
Southern Company
Transmission
Yes
Arizona Public Service
Company
No
The TVMP shall demonstrate the TO’s ability to manage the system at all rated conditions to
maintain reliability.
Response: The SDT thanks you for your comments. We agree that this is the purpose of R3. Please note the language in the rationale text for R3
clarifies - “... documentation provides a basis for evaluating the competency of the Transmission Owner’s vegetation program. There may be many
acceptable approaches to maintain clearances. Any approach must demonstrate that the Transmission Owner avoids vegetation-to-wire conflicts
under all Ratings and all Rated Electrical Operating Conditions. See Figure 1 for an illustration of possible conductor locations.” A TVMP is one
example of an approach to which this refers.
Salt River Project
Yes
Tampa Electric Company
Yes
Good addition, adds clarity and improves overall understanding of the requirement.
Response: The SDT thanks you for your comments.
NextEra Energy
Yes
SDG&E
Yes
ASSET MANAGEMENET
Yes
Hydro-Quebec TransEnergie
(NCR07112)
Yes
Consideration of Comments on Draft 5 of FAC-003-2
49
Organization
Yes or No
Kansas City Power & Light
Yes
Manitoba Hydro
Yes
Central Maine Power
Company - IberdrolaUSA
Yes
BC Hydro
Yes
Question 4 Comment
You could also include the term “maintenance standards”.
Response: The SDT thanks you for your comments. Either word could work – however since most commenters agreed with the use of the word,
‘strategies’ the SDT did not adopt the suggestion to use the word, ‘standards’.
American Transmission
Company, LLC
Yes
American Electric Power
Yes
Baltimore Gas and Electric Co.
Yes
TVA
Yes
Niagara Mohawk Power
Corporation (dba National
Grid)
Yes
CenterPoint Energy
Yes
Duke Energy
Yes
Consideration of Comments on Draft 5 of FAC-003-2
50
Organization
Yes or No
South Carolina Electric and
Gas
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
Question 4 Comment
This clearly defines “intent”.
Response: The SDT thanks you for your comments.
Individual
Consolidated Edison Company
of New York, Inc. Transmission Line
Maintenance
Yes
USACE
No
CECD
Yes
Because Requirement 5 and 7 use the phrase annual work plan, and there is not a Requirement to
develop a work plan, this Requirement should include a relationship between the document that is
developed for maintenance strategies and the annual work plan.
Response: The SDT thanks you for your comments. The SDT considers the references to the work plan in R5 and R7 sufficient. The SDT considers
maintenance strategies and work plans to be separate functions. Avoiding the reference to the work plans in R3 minimizes confusing the two
functions.
Entergy Services, Inc
Yes
Consideration of Comments on Draft 5 of FAC-003-2
51
Organization
Yes or No
Orange and Rockland Utilities,
Inc.
Yes
National Grid
Yes
Western Electricity
Coordinating Council
Yes
Georgia Transmission Corp.
Yes
Northern Indiana Public
Service Company
No
Consideration of Comments on Draft 5 of FAC-003-2
Question 4 Comment
52
5.
The SDT added clarifying language in M7 to explain how the annual work plan percentage complete calculation is to be
performed. Is this adequate? If no, please provide improved examples.
Summary Consideration: There were 31 agreements and 8 disagreements. Seven comments noted that the question should have
referenced R7 not M7. The SDT acknowledged that observation and agreed that the reference should have been R7. The SDT added
the term “of applicable lines” to M7 and to the VSL’s for R4, R5 and R6. The SDT also made minor changes to VSLs for R7 to conform
to verbiage in R6.
One commenter agreed with R7 changes and noted “there is no requirement....that a plan is....developed.” The SDT sees no reason
to add such a requirement for documentation, since a fundamental precept of results-based standards is that having a requirement
to complete any particularly activity also presupposes that the elements required to complete the activity are included in the
requirement, even if unstated.
One affirmative comment requested that exceptions for crew performance and availability be noted explicitly: the SDT noted that
while the requested condition could be listed, the list is not meant to be exhaustive, and that any modification to the work plan can
be made provided it does not allow encroachment into the MVCD. The same commenter wished to include language related to
derating the line to indicate that the purpose of such action would be to “ensure continued...reliability.” The SDT saw problems
associated with proving that a reliability contribution by a derating was in fact accomplished and chose to retain the existing
language. The same commenter wished to remove Category 3 outage reporting, but the SDT sees great value in the investigation of
each vegetation related outage and feels that this reporting is justified to ensure that all outages are sufficiently investigated. The
same commenter requested removing the reference to “defense-in-depth” in the Background section; the SDT chose to leave this
reference as is. Lastly that same commenter suggested that “promptly” could be substituted for “without intentional time delay” in
R4, the SDT saw no difference in the two terms and chose to keep the existing verbiage.
A commenter suggested in lieu of the annual inspection requirement that a time interval based on growth rates be used instead. The
SDT chose to retain the existing annual interval based on industry’s consensus support for the one year interval in a previous posting
of the Standard.
A commenter requested that “of applicable lines” be added to the requirements and VSL verbiage to clearly denote applicability
within the requirements and VSL verbiage. The SDT made those changes as requested to the requirements, measures and VSLs.
That same commenter requested that Category 3 outages be reported by type A & B similar to other categories. The SDT saw no
value to this change since Category 3 serves its purpose without that distinction being made. The same commenter requested
Consideration of Comments on Draft 5 of FAC-003-2
53
changes to the ROW definition; the SDT chose to retain the existing language since it has been vetted with significant industry
consensus.
Another comment suggested adding reference to financial reports in the examples for reasons for modifications to the annual plan,
the SDT feels that such a reference to financial conditions was inappropriate. The same commenter noted the need for clarity in the
structure of the VSLs ; the SDT made those changes. The same commenter requested clarity on use of Table 2 when an entity has a
voltage category not in the table - the team added language to clarify that where the TO has transmission lines operated at nominal
levels not listed in Table 2, the TO should use the clearance distances based on the maximum system voltage (i.e. for a nominal
system voltage of 287 kV the appropriate distances would be for a maximum system voltage of 362 kV). Two commenters requested
an example be added to the Guidelines and Technical Basis section for R7, similar to the examples in R6, to clarify that the %
calculations should be based on the Annual Plan as modified; the SDT added the example as requested.
Another commenter questioned the 48-hour reporting in the 12/17/2008 NERC Public Notice - NERC Compliance Process #2008-001.
The SDT discussed the issue with NERC staff and did not receive any direction that it would be necessary to add this as a
Requirement within the Standard
Additional comments were offered by NERC staff as a separate attachment to comments submitted with the comment form, and
those responses are covered following this question.
Organization
Yes or No
SERC Vegetation Management
sub-committee
Yes
Hydro One Networks
Yes
Northeast Power Coordinating
Council
No
Question 5 Comment
There is no percentage language in M7. Is it R7 that is being referred to?
Response: The SDT thanks you for your comment. The SDT meant to refer to R7.
Consideration of Comments on Draft 5 of FAC-003-2
54
Organization
Yes or No
Platte River Power Authority
Substation Maintenance
Group
Yes
Bonneville Power
Administration
Yes
NERC Staff
Yes
Question 5 Comment
Actually, R7 contains the clarifying language. It should be noted that although R7 indicates the TO
shall complete 100% of the VM work plan, there is no requirement in this draft that a plan is
actually developed.
Response: The SDT thanks you for your comments. The SDT meant to refer to R7, not to M7. As to the seeming lack of an actual requirement for a
work plan, the SDT asserts that a fundamental precept of results-based standards is that having a requirement to complete any particularly activity
also presupposes that the elements required to complete the activity are included in the requirement, even if unstated.
Pepco Holdings Inc and
Affiliates
Yes
FirstEnergy
Yes
Although we generally agree with Requirements R7 and its measure M7, we suggest adding
clarifying wording to bullet 4 which states "Crew or contractor availability/ Mutual assistance
agreements". In addition to availability, contractor performance may be another issue that requires
modification to the work plan. We suggest adding another bullet that reads "Crew or contractor
performance". The rationale behind this addition is to address poor safety, productivity and/or
quality issues with a crew or contractor assigned to perform vegetation management.FirstEnergy
provides the following additional comments and suggestions not related to the specific questions
asked in this posting:
1. Requirement R5 - We appreciate this requirement which recognizes that the TO may face
situations in which it is constrained from performing its vegetation management and are permitted
Consideration of Comments on Draft 5 of FAC-003-2
55
Organization
Yes or No
Question 5 Comment
to seek alternative methods. However, there may be instances where the TO has exhausted all
course of action to perform vegetation and must utilize other means to prevent vegetation
encroachment into the MVCD. Therefore, in these instances, "continued vegetation management"
as stated in the requirement is not possible, but other methods such as line deratings and
deenergizing of lines may have to be used. We ask that the phrase "to ensure continued vegetation
management to prevent encroachments" be changed to read “to ensure continued reliability of the
BES”.
2. Compliance Section - Category 3 - We suggest removing this category from the standard. Since
fall-ins from outside the ROW are not considered a violation of this standard per Requirements R1
and R2, the entity should not have to report these fall-ins.
3. Objectives - We do not believe that is necessary for the Objectives statement to include the
"defense-in-depth" concept which is actually an overarching goal of results-based standards in
general and not specific to FAC-003-2. We suggest removing this phrase.
4. Background Section 5 - Similar to our comment above regarding defense-in-depth in the
objectives statement, this is an overarching goal of results based standard and not specific to FAC003-2. Therefore, we suggest removing the explanation of defense-in-depth from the background
section.
5. Vegetation Inspection Definition - We suggest replacing the word "hazard" with "risk".
6. Requirement R4 - We do not agree with the phrase "without any intentional time delay" and
suggest it be removed. This phrase is not measurable. Also, other drafting teams have attempted to
incorporate this statement but industry comments have persuaded them to remove it; for
example, the Reliability Coordination drafting team (Project 2006-06) initially proposed the same
phrase but later removed it in their development of the COM/IRO standards. At the very least
standards development should be consistent throughout the NERC standards drafting teams. We
suggest the following as wording for Requirement R7: "Each Transmission Owner shall ensure the
control center holding switching authority for the applicable transmission line is promptly notified
Consideration of Comments on Draft 5 of FAC-003-2
56
Organization
Yes or No
Question 5 Comment
when the Transmission Owner has confirmed the existence of a vegetation condition that can
potentially cause a Fault."
Response: The SDT thanks you for your comments. The SDT considered your request to add to the acceptable reasons for modifications the bullet,
“Crew or contractor performance,” and observes that since R7 states “Modifications to the work plan in response to changing conditions or to
findings from vegetation inspections may be made (provided they do not allow encroachment of vegetation into the MVCD)...” the bullet could be
added, but the SDT did not intend the list of examples to be exhaustive and decided not to add the new bullet.
In reference to the comment 1) that the phrase "to ensure continued vegetation management to prevent encroachments" be changed to read “to
ensure continued reliability of the BES,” the SDT agrees that the corrective actions of de-ratings and de-energization as you suggest must be
considered when vegetation cannot be maintained to prevent encroachment into the MVCD, and those examples are explicitly listed in M5. If a
de-rating is used, it must be sufficient to prevent the encroachment into the MVCD. The de-rating or de-energization of the line removes the
threat of an energized line and adjacent vegetation having less separation that the MVCD (i.e. less Fault probability), but the realized reliability
value of those actions will depend on the events that occur while the condition persists. For these reasons the SDT retains the R5 language without
changes.
In reference to the comment 2) “Compliance Section - Category 3 -...suggest removing this category from the standard,” an investigation of the
location of the tree with respect to the edge of the ROW for fall-ins must be made to determine whether the event represents a self-report of a
violation or not. A record of those findings when the tree is found to be outside the ROW is valuable for both the Compliance Monitoring and
Enforcement and the TO, should any questions later arise; therefore the SDT chose to retain the Category 3 reporting.
Regarding your comment 3) “Objectives - We do not believe that is necessary for the Objectives statement to include the "defense-in-depth"
concept which is actually an overarching goal of results-based standards in general and not specific to FAC-003-2. We suggest removing this
phrase.” The SDT notes that the Purpose language is a general statement, and could be expanded or contracted without impacting the
requirements. However, since the current language has undergone extensive debate, comment and revision the SDT sees no compelling reason to
request industry to review another change at this time.
Regarding your comment 4) “Background Section 5 -.... suggest removing the explanation of defense-in-depth from the background section” The
SDT notes again that the background section language is a general statement and could be expanded or contracted without impacting the
requirements. However, since the defense-in-depth drove many of the changes in the standard the SDT thinks this section is relevant and should
be retained.
Consideration of Comments on Draft 5 of FAC-003-2
57
Organization
Yes or No
Question 5 Comment
Regarding your comment 5) “suggest ...for Requirement R7(actually R4): "Each Transmission Owner shall ensure the control center holding
switching authority for the applicable transmission line is promptly notified when the Transmission Owner has confirmed the existence of a
vegetation condition that can potentially cause a Fault." The SDT has searched for but not found a time limit more suitable than “without
intentional time delay.” An extensive list of event scenarios between the time that a condition is observed and the time it is reported can be
studied. In the final analysis the intent is for the notification to be made to allow time for the control center to take steps to maintain reliability if
possible before conditions deteriorate further. “Without intentional time delay” is as sufficient and as measurable as “promptly”.
Dominion Electric Market
Policy
No
The red-line revision does not indicated changes to M7; therefore, Dominion is unable to evaluate
the clarifying language identified in this question. If the SDT meant to reference R7, we agree that
the clarification is adequate.
Response: The SDT thanks you for your comments. The SDT means to reference R7.
Southern Company
Transmission
Yes
Arizona Public Service
Company
Yes
Salt River Project
Yes
Tampa Electric Company
Yes
This allows flexibility for the T.O. to determine the type of “unit” used in calculating the percentage
complete.
Response: The SDT thanks you for your comments.
NextEra Energy
Yes
SDG&E
Yes
Consideration of Comments on Draft 5 of FAC-003-2
58
Organization
Yes or No
ASSET MANAGEMENET
Yes
Hydro-Quebec TransEnergie
(NCR07112)
No
Question 5 Comment
The minimum frequency of Vegetation Inspection should be based upon an average growth rates of
smaller regions than all North America. Example, above the latitude of about 50 degrees North, the
vegetation growth rates is limited. We think that Vegetation Inspection frequency should be
relaxed to 3 years for those areas in Canada. As indicator of the minimum frequency requested in
R6, we suggest to use a global vegetation index like the Normalized Difference Vegetation Index
(NDVI). The NDVI has been in use for many years to measure the vigor of vegetation growth among
other things. http://earthobservatory.nasa.gov/Features/MeasuringVegetation/
Response: The SDT thanks you for your comments. In FERC Order 693, para. 721, FERC stated, “The Commission continues to be concerned with
leaving complete discretion to the transmission owners in determining inspection cycles, which limits the effectiveness of the Reliability Standard.”
The SDT established an inspection cycle at least once per calendar year and with no more than 18 months between inspections on the same ROW.
There was a survey of the industry in a previous request for comments to this standard. The response to that survey is the basis for the use of the
1-year period. While there was a range of growth rates across the continent, the SDT had sufficient feedback to recommend the 1-year cycle. The
inspection also would cover inspecting for fall-in threats. Please note that vegetation inspections can also be combined with other line inspections.
Kansas City Power & Light
No
1) R7 states “Each Transmission Owner shall complete 100% of its annual vegetation work plan...”.
We suggest to be consistent with all other sections of the rule that it should read, “Each
Transmission Owner shall complete 100% of its annual vegetation work plan for all applicable
lines...”. Otherwise, leaves room for interpretation to include all lines including those not defined
as applicable. Also require these same revisions to row R7 of the table “Time Horizons, Violation
Risk Factors, and Violation Severity Levels”.
2) In the “Additional Compliance Information” section Categories 1, 2, and 4 are each defined to
have an A & B component to recognize the severity level difference for “applicable transmission
lines” identified versus not identified “as an element of an IROL or Major WECC Transfer Path”.
However, Category 3 does not separate these two scenarios however it appears that the same
Consideration of Comments on Draft 5 of FAC-003-2
59
Organization
Yes or No
Question 5 Comment
distinction should apply.
Additional comments:Vegetation Inspection Definition Recommend the SDT consider removing the
conditional language, “that are likely to pose a hazard to the line(s) prior to the next”. Vegetation
inspections are not dependent on a predisposed condition of vegetation. Suggest the SDT remove
that phrase and consider the following definition:The systematic examination of vegetation
conditions on a maintained transmission line Right-of-Way under the Transmission Owner’s control
under a planned maintenance or inspection which may be combined with a general line inspection.
Response: The SDT thanks you for your comments. 1) The team has made the appropriate modifications, adding the reference to ‘applicable lines’
where necessary. 2) Since the Category 3 outages do not have any violations associated with their occurrences, the SDT did not see the value in
reporting by type A or type B lines. 3) The SDT chooses to keep the current language because it addresses the core need to find conditions that will
need correcting before the next planned maintenance or next planned inspection is performed.
Manitoba Hydro
Yes
Central Maine Power
Company - IberdrolaUSA
Yes
BC Hydro
Yes
You could also include other documentation such as monthly financial and program variance
reports.
Additional Comments
Table 1: R6 definitions could be clearer. Suggested clarification:
VSL Lower - Greater than 95% of annual inspections complete but less than 100% complete.
VSL Moderate - Greater than 90 % of annual inspections complete but less than 95% complete
VSL High - Greater than 85% of annual inspections complete but less than 90% complete
VSL Severe - Less than 85% of annual inspections completed
Consideration of Comments on Draft 5 of FAC-003-2
60
Organization
Yes or No
Question 5 Comment
Table 1 R7 definitions could be clearer. Suggested clarification:
VSL Lower - Greater than 95% of annual work plan complete but less than 100% complete.
VSL Moderate - Greater than 90 % of annual work plan complete but less than 95% complete
VSL High - Greater than 85% of annual work plan complete but less than 90% complete
VSL Severe - Less than 85% of annual work plan completed
Table 2: This table includes a number of common nominal system voltages vs MVCD distances by
altitude. However, some utilities have other non-standard voltages, in our case 287 kV, which
forms a significant part of their system. It may be worthwhile for the standard to state what a
utility should follow when a standard voltage class is not present - i.e. go to the next higher voltage
MVCD if a particular voltage isn’t in the table, or direct the utility to do its own Gallett Equation
calcuations for their unique voltage class. Otherwise, different utilities may create a non-standard
solution that wouldn’t address the risk.
Response: The SDT thanks you for your comments. The SDT did not intend for the list of examples to be exhaustive. To the extent that financial or
variance reports include evidence of the work units completed they may be useful as supportive evidence. inappropriate.
The SDT used the NERC VSL Guidelines to develop the VSLs; therefore the SDT feels that the VSL's for R7 are adequate as listed. The proposed VSLs
would leave some ‘gaps’ – for example the proposed VSLs aren’t clear on what VSLs is assigned when an entity has completed exactly 95% of its
inspections.
Table 2 in the Standard lists both the nominal system voltages and the corresponding maximum system voltages. The clearance distances listed
for each nominal system voltage were calculated using the maximum system voltage values. Therefore, where the TO has transmission lines
operated at nominal levels not listed in Table 2, the TO should use the clearance distances based on the maximum system voltage (i.e. for a
nominal system voltage of 287 kV the appropriate distances would be for a maximum system voltage of 362 kV). The SDT has added language to
the guidelines and technical basis section to clarify this point.
American Transmission
Yes
Consideration of Comments on Draft 5 of FAC-003-2
61
Organization
Yes or No
Question 5 Comment
Company, LLC
American Electric Power
Yes
Baltimore Gas and Electric Co.
Yes
TVA
No
I suggest that footnote 4 be changed by removing the reference to arbicultural, horticultural or
agricultural activities.
Response: The SDT thanks you for your comments. The recommended changes have been made to footnote 4.
Niagara Mohawk Power
Corporation (dba National
Grid)
No
There is currently no percentage language in M7. If they are referring to R7, then YES it is
adequate.
Response: The SDT thanks you for your comments. The question should have referred to R7.
CenterPoint Energy
No
CenterPoint Energy could not find any reference to an example percentage complete calculation
for the annual work plan in the Standard for M7, in the Guideline and Technical Basis for M7, nor in
the Technical Reference for M7. There was such an example for M6 which was helpful. CenterPoint
Energy recommends such an example be included for M7.
Response: The SDT thanks you for your comments. The percentage complete should be based on the annual plan as modified.
The SDT has changed the language in the standard to reflect more clearly that the percentage complete should be based on the plan as modified,
and the following example has been added to the Guideline and Technical Basis:
For example, when a Transmission Owner identifies 1,000 miles of 230 kV transmission lines to be completed in the TO’s annual plan, the
Transmission Owner will be responsible completing those identified miles. If a TO makes a modification to the annual plan that does not put the
transmission system at risk of an encroachment the annual plan may be modified. If 100 miles of the annual plan is deferred until next year the
calculation to determine what percentage the TO completed for the current year would be: 1000 – 100 (deferred miles) = 900 modified annual
Consideration of Comments on Draft 5 of FAC-003-2
62
Organization
Yes or No
Question 5 Comment
plan, or 900 / 900 = 100% completed annual miles. If a TO only completed 875 of the total 1000 miles with no acceptable documentation for
modification of the annual plan the calculation for failure to complete the annual plan would be: 1000 – 875 = 125 miles failed to complete then,
125 miles (not completed) / 1000 total annual plan miles = 12% failed to complete.
Duke Energy
Yes
South Carolina Electric and
Gas
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
This is directed toward R7 rather than M7.
Response: The SDT thanks you for your comments.
Individual
Consolidated Edison Company
of New York, Inc. Transmission Line
Maintenance
Yes
The added language for the annual work plan percentage complete calculation is shown in R7 not
M7 as stated in the question. In the Guideline and Technical Basis Section for Requirement R6,
there is a sample calculation shown for the amount of lines the TO failed to inspect. An example
should also be included for Requirement R7 since there is some confusion regarding how
modifications to the work plan affect the calculation. In the Lower VSL column for R7, it states that
the TO failed to complete up to 5% of its annual vegetation work plan (including modifications if
any). If a TO operates 100 lines and submits a justified modification that affects 10 miles of lines,
the total number of units in the final amended plan is 90 miles. When you read the VSL, it is
somewhat confusing since the information in parenthesis says that the calculation 'includes' the
modifications. Should it state 'excludes modifications if any' or the VSLs can simply be re-written to
state that ..The TO failed to complete up to x% of the final amended plan.' Also, the VSLs in R6 and
Consideration of Comments on Draft 5 of FAC-003-2
63
Organization
Yes or No
Question 5 Comment
R7 should be consistent with each other: R6 says '...TO failed to inspect 5% or less.....' and R7 says
'...TO failed to complete up to 5%....' They both should use the same verbiage in each VSL whether
it is 'x% or less' or 'up to and including x%.'
Response: The SDT thanks you for your comments. The percentage should be based on the plan as modified. The SDT has changed the language in
the standard to reflect this more clearly.
USACE
Yes
CECD
Yes
Entergy Services, Inc
Yes
The actual clarifying language seems to have been added to R7 instead of M7 (as stated above).
The clarifying language provides benefit as added to R7, and should remain in R7.Additionally, we
feel that, in an effort to promote consistency with the other 6 Requirements, the term "on
applicable Transmission lines" should be added at the end of the first sentence of R7, as it is listed
in all other R's. The first sentence of R7 currently reads: "Each Transmission Owner shall complete
100% of its annual vegetation work plan to ensure no vegetation encroachments occur within the
MVCD". We feel the first sentence should read "Each Transmission Owner shall complete 100% of
its annual vegetation work plan to ensure no vegetation encroachments occur within the MVCD on
applicable transmission lines".
Response: The SDT thanks you for your comments. The first sentence does now contain the term “applicable lines”.
Orange and Rockland Utilities,
Inc.
Yes
National Grid
No
There is currently no percentage language in M7. If they are referring to R7, then YES it is
adequate.
Consideration of Comments on Draft 5 of FAC-003-2
64
Organization
Yes or No
Question 5 Comment
Response: The SDT thanks you for your comments. The SDT was referring to R7.
Western Electricity
Coordinating Council
Yes
We support the clarifying languae in M7However, since there is no generic "Any other Comments"
section associated with this on-line comment form, we raise a question here. On December 24,
2008, NERC issued an e-mail to all Transmission Owners in which it referenced its December 17,
2008 Public Notice - NERC Compliance Process #2008-001, Vegetation-related Transmission Outage
Reporting. The notice stated that: "Due to the potential severity of transmission outages caused by
vegetation associated with Standard FAC-003-1, NERC is encouraging each Transmission Owner to
self-report all Category 1 and Category 2 transmission outages related to vegetation to the Regional
Entity within 48 hours utilizing the 48-hour vegetation reporting notice form provided by your
appropriate Regional Entity."We do not see any reference to a 48-hour reporting notice in lthis
version of the standard. Is this still a requirement? The only reference to reporting is in the
Additional Compliance Information section and references quarterly reporting only.
Response: The SDT thanks you for your comments. The SDT is aware of the 48 hour, voluntary self-report request from NERC for outages where
vegetation may be involved. The SDT also agrees with the general philosophy proposed by WECC that all requirements associated with a Standard
are best served in the Standard. Also, the SDT did examine the general concept of an "investigation" type requirement. However, the SDT did not
pursue this because it did not satisfy the basic rule for requirements as embedded in the Standards Process Manual, “What functional entity shall
do what under what conditions to achieve what reliability objective.” After the fact investigation and reporting, while important to the Compliance
and Enforcement (CMEP) aspect of mandatory and enforceable Standards, does not achieve a reliability objective such that the failure to comply
with the Requirement would jeopardize reliability. The SDT also notes that any useful (other than CMEP) information related to an outage that is
subsequently reported under the NERC voluntary request would generally be available for industry use through TADS. Finally, the SDT did discuss
the issue with NERC staff and did not receive direction that it was necessary, or desirable, to include one or more elements of the voluntary
request in this Standard.
Georgia Transmission Corp.
Yes
Northern Indiana Public
Yes
Consideration of Comments on Draft 5 of FAC-003-2
65
Organization
Yes or No
Question 5 Comment
Service Company
Consideration of Comments on Draft 5 of FAC-003-2
66
Additional Comments from NERC:
In addition to the comments NERC submitted to the five questions on the official comment form, NERC staff has numerous other
comments to make with regard to this Draft 5. Before that, NERC staff first wants to acknowledge the significant effort and talent
that the industry brought to attempt to improve upon Reliability Standard FAC-003-1 – Vegetation Management. This Draft 5 of
FAC-003-2 – Vegetation Management entailed significant industry work towards understanding the issue, compromising on
proposals and attempting to reach consensus utilizing the NERC Standards Development Process. While NERC staff believes this
draft represents some improvements to the existing standard, it does not believe the draft in its totality represents an improvement
to the existing standard. FERC Order 693 approved the existing Vegetation Management Standard and it provided a number of
directives for NERC with regard to further developing the Standard in order to improve it. Such directives and NERC comments
regarding how the directives were addressed included:
•
FERC Directive - Develop compliance audit procedures, using relevant industry experts, which would identify appropriate
inspection cycles based on local factors. The Commission is dissuaded from requiring the ERO to create a backstop
inspection cycle at this time.
NERC Comment – Compliance audit procedures are outside the scope of the SDT and this Draft 5. Although not required by
the Commission, the SDT added an annual inspection cycle to the Standard, with a maximum of 18 months between
inspections. NERC believes this requirement represents an improvement to the existing Standard and does not believe it is
overly burdensome on utilities.
Response: The SDT thanks you for your comments.
•
FERC Directive - Remove the general limitation on lines 200kV and above to include lines that have an impact on reliability.
o Do not reduce facilities included
o Develop an acceptable definition for the applicability of this Reliability Standard that covers facilities that impact
reliability while not unreasonably increasing the burden on transmission owners.
o Evaluate the suggestions proposed by LPPC, APPA and Avista that regional entities should determine which facilities
this standard applies to
NERC Comment – NERC believes Draft 5 partially addresses this issue by increasing applicable facilities to IROL lines under
200kV. NERC staff is also concerned about
Consideration of Comments on Draft 5 of FAC-003-2
67
o The possibility that this very addition could limit a regional entity’s desire to include additional lines.
o The exclusion of facilities inside the fenced area of switching stations, stations and substations. These excluded areas
still pose a vegetation related outage risk and the rationale for excluding them is not compelling enough.
o The separation of IROL (any voltage level) and non-IROL (200 kV and above) Transmission Lines into separate
requirements with different VRFs. NERC believes all Transmission Lines subject to this standard should be under the
same requirement and associated VRFs. IROL lines are relatively few and do not warrant their own requirement. By
having lower VRFs for non-IROL lines, this version of the standard is weaker than the existing standard. These two
requirements should be a single requirement with high VRFs
Response: The SDT thanks you for your comments. In the guidelines provided by NERC to the drafting team, the SDT is dissuaded from writing ‘fill
in the blank’ requirements. In version one, the team directed the RO to designate which critical lines below 200kV should fall under the standard
without defining what critical meant. This is a ‘fill-in-the- blank.’ There is no assurance that this applicability would be applied consistency across
North America. The SDT followed FERCs suggestion to take into account “…the suggestions by Progress Energy, SERC and MISO to limit applicability
to lower voltage lines associated with IROL…” The team went further by including WECC transfer paths. The SDT asserts that the inclusion of both
IROL lines and WECC Transfer paths addresses the comments by LPPC, APPA and Avista along with Progress Energy, SERC and MISO. The NERC Staff
needs to consider that the comments all contend that each inclusion of a below 200kV line is an added burden to the rate payers. Not to give some
direction to the Planning Coordinator would allow a planner to include ALL transmission lines, which would be an unreasonable burden to the rate
payer. We added this language for clarity at the request of stakeholder concerns.
Neither the standard nor its original SAR were intended to cover fenced or discrete locations such as substations, which entail entirely different
issues compared to linear corridors. Often substations are owned by either DPs or GOs, therefore, the TO may not have rights inside the fenced
facility. The requirements in this standard would not be sufficient to include stations and switch yards. Should there be a compelling need for a
vegetation standard for fenced facilities, a new SAR should be introduced.
The SDT asserts that different VRF’s for IROL and non-IROL lines strengthens the reliability of the standard. Vegetation managers that do not know
which lines are IROL or WECC Transfer Paths may be inappropriately limiting resources allocated to vegetation management for an IROL line or a
WECC Transfer Path. A vegetation manager must ensure that the IROL lines and WECC transfer paths are absolutely clear. By correctly identifying
the risk associated with an IROL line and/or a WECC Transfer Path, the standard helps to assure that appropriate resources are applied.
VRF guidelines require an analysis of impact to BES. We did that by considering the relative risk levels to the interconnected transmission system of
an interruption of a non-IROL/non-Transfer Path line versus the interruption of IROL/Transfer Path lines. The fact that the PENALTY might be higher
or lower DOES NOT AFFECT the strength or weakness of the Standard, since even the Medium Risk Factor value in the Base Penalty Matrix in the
Consideration of Comments on Draft 5 of FAC-003-2
68
sanctions guidelines is $350,000 per violation per day. In both R1 and R2 of Version 2 there is zero-tolerance for encroachments, and Version 2
increases the scope to include observed encroachments without Faults, and confirmed vegetation Faults without Sustained Outages which were
not clearly included in Version 1. The 1) distinction by separation of VRFs and 2) inclusion of clear language to inspect for, investigate, correct, and
report to all known reliability threats will strengthen the standard.
•
FERC Directive - Develop a Reliability Standard that defines the minimum clearance needed as an improvement to IEEE 516
which FERC does not believe is appropriately used for purposes of reliability and/or safety.
NERC Comment – Draft 5 makes a change from IEEE 516 and utilizes Gallet equations for industry clearances. While NERC
believes these equations are technically accurate, NERC is concerned about the usefulness of the clearances determined
under this methodology as put forth in this draft. NERC is not aware of any utility which would maintain clearances as
specified in this draft as it has no built in safety factor. NERC is further concerned that utilities could be mandated by courts
of law to reduce existing maintained clearances to values much closer to those determined by the methodology in this draft.
Response: The SDT thanks you for your comments. As with a Transmission Owner's determination of its Clearance 1 distances under version 1 of
the Standard, Requirement 3 of the revised Standard begins with the MVCD distances (just as Clearance 1 began with IEEE-516 distances) and then
requires additional consideration for conductor movement, vegetation growth variables, and the utility's maintenance approach. These are
essentially the same considerations required by version 1 of the existing Standard when developing Clearance 1 distances. Therefore, nothing has
been "lost" in the revised Standard. In fact, the proposed Standard is better from an auditing perspective because the overall logic and rationale
used by the TO in complying with the new Requirement 3 is now subject to an overall test of adequacy, competency and reasonableness. Also,
informal polls conducted by the SDT show that many Transmission Owners are unsuccessful in utilizing Clearance 1 as a tool, because it is easily
challenged by landowners as being an arbitrary fill-in-the-blank value set by the Transmission Owner. Further, if the Transmission Owner would cut
only to Clearance 1 instead of to the full extent of its legal rights, courts could rule against the Transmission Owner for failing to exercise its full
legal rights. Thus, in the revised Standard, the Transmission Owner has neither gained nor lost any tool or advantage in dealing with landowners,
but the SDT asserts that the bar has been raised with regard to the adequacy of the Transmission Owner’s overall vegetation management
program.
Consideration of Comments on Draft 5 of FAC-003-2
69
•
FERC Directive - Define rights-of-way to encompass the required clearance areas instead of the corresponding legal rights,
and the standards should not require clearing the entire right-of-way when the required clearance for an existing line does
not take up the entire right-of-way.
NERC Comment – NERC staff believes this directive was met and is addressed in question 1 of the comment form.
Response: The SDT thanks you for your comments.
•
FERC Directive – NERC should address the proposed modifications through its Reliability Standards development process.
NERC Comment – NERC staff believes this directive was met in preparing this draft standard.
Response: The SDT thanks you for your comments.
•
FERC Directive - Collect outage data for transmission outages, analyze it, and use the results of this analysis and information
in the development of the Reliability Standard.
NERC Comment – NERC staff believes more work needs to be done in this area. NERC staff believes the drafting team should
consider modifying the Periodic Data Submittal to include if outages occur on Federal land.
Response: The SDT thanks you for your comments. After discussion with NERC staff, NERC has agreed to address this issue outside the work of the
SDT. The SDT recommends that NERC staff consider adding a field to the TADS data to capture vegetation outages on applicable lines on federal
lands.
Other Draft 5 Issues
•
Removal of a formal transmission vegetation management program, of Clearance 1 and of a documented vegetation
management plan.
Consideration of Comments on Draft 5 of FAC-003-2
70
NERC Comment – NERC does not support the removal of these items. NERC does not believe these changes represent an
improvement to the standard and does not believe this existing requirement is overly burdensome to utilities. NERC does
not understand why industry would not be willing to be held accountable to their vegetation management plans. NERC is
concerned that the removal of these items could make it difficult for utilities to obtain permissions needed to maintain
clearances between inspection cycles which are prudent for reliability and safety due to intervener or landowners exercising
their rights and then pointing to this new standard as a the basis for smaller clearances. . Requirement 3 in this draft needs
to include a documented plan and to clearly identify the specifics to be included in the plan and provide clarity of
expectations. The SDT may not support such specifics as not being consistent with results-based standards development but
NERC staff believes otherwise.
Response: The SDT thanks you for your comments. The existing series of items in Requirement R3 along with R3.2 are collectively with the balance
of the standard equivalent to the term TVMP. These combined items in R3 are the defense in depth approach that require the TO to maintain
vegetation so that it does not enter into the MVCD before the next planned vegetation work, thus accomplishing the equivalent of a C1 without a
fill-in-the-blank issue.
•
Objectives: A qualifier in the standard Objective that it should apply to preventing the risk of vegetation related outages that
could lead to cascading outages.
NERC Comment – This qualifier limits the purpose of the standard, which should be to prevent vegetation related outages,
not cascading outages. The more outages there are, the less the overall system reliability. An outage does not necessarily
have to lead to a cascading outage to be significant and represent a reasonable risk to the BES. References to cascading
outages should be removed.
Consideration of Comments on Draft 5 of FAC-003-2
71
Response: The SDT thanks you for your comments. The SDT has thoughtfully considered every aspect of this version of the Standard to ensure that
the pieces are consistent, aligned, and support each other. The SDT added the phrase “with Cascading” not to limit the Standard, but rather to
recognize that the 200 kV bright-line for applicability (which is not in question) is founded on the very notion that the 200 kV serves as a proxy for
"The Big Three": Cascading, Separation, and Instability. The SDT considered adding all of these conditions to the Purpose statement. However,
given the focus of this Standard is on vegetation, and vegetation was deemed to be related to Cascading (i.e. 2003 Blackout report), rather than the
other two undesirable system conditions, it seemed more logical and consistent to include the likely outcome of an unmanaged vegetation
condition on a Transmission Owner's system. If NERC Staff has evidence that other two are likely related to vegetation, it has not yet been provided
to the SDT.
Unlike other types of outages on lines (such as those caused by failed insulators, broken cross-arms, rotten poles and lightning flashover),
vegetation outages uniquely affect lines when they are heavily loaded and thus susceptible to a cascading event.
•
Background: This section excludes vegetations fall-ins and blow-ins from outside the ROW on the basis that they are not
preventable.
NERC Comment – Many fall-ins and blow-ins from outside the ROW are preventable. Trees outside the ROW must be
managed adequately to prevent outages on the BES. The work to remove and/or prune trees outside the ROW may be more
difficult and costly than such work inside the ROW, but that is not sufficient reason to exclude this work. In addition, utilities
wishing to perform such work might be prevented from doing so by regulatory bodies based upon the lack of a specific
requirement in this standard.
Response: The SDT thanks you for your comments and has reworded the Background by removing the term non-preventable.
•
Requirement 1 & 2: These requirements discuss preventing encroachments into the MVCD of an applicable line that is
operating within its Rating.
NERC Comments –NERC staff would like confirmation that “Rating” is intended to include all published ratings issued by the
facility owner, such as Normal, Emergency, etc.
Consideration of Comments on Draft 5 of FAC-003-2
72
Response: The SDT thanks you for your response. The glossary term “Rating” is adequate to address the issues you raise.
•
Requirement 4: R4 states that “Each Transmission Owner, without any intentional time delay, shall notify…”
NERC Comments: The previous version of the standard included a time limit of 15 minutes once communications became
available. This should be reinstated.
Response: The SDT thanks you for your response. The SDT is not aware any posting with a 15 minute rule included.
•
Requirement 7: R7 sets the requirement for each Transmission Owner to complete 100 percent of its annual vegetation work
plan.
NERC Comments – NERC is concerned that the draft doesn’t have a requirement for a Transmission Owner to have a
documented annual plan making Requirement 7 unenforceable. In addition, Requirement 7 has a number of other qualifiers
that would seem to allow manipulation of the annual plan to ensure compliance.
Response: The SDT thanks you for your comments. The SDT asserts that a fundamental precept of results-based standards is that having a
requirement to complete any particularly activity also presupposes that the elements required to complete the activity are included in the
requirement, even if unstated.
•
Draft 5 document quality
NERC Comments – this draft has some typographical errors which need to be fixed. For example, on page 28, reference to
use of Table 5 versus Table 7 based on knowledge of maximum transient over-voltage factor is reversed. These edits could
probably be handled through a recirculation ballet.
Response: The SDT thanks you for your comments. We agree with the typo you found and we have changed the language in the draft standard.
Consideration of Comments on Draft 5 of FAC-003-2
73
•
Previously raised NERC issues
NERC Comments – NERC staff posted several comments on the Draft 4 version of this standard in July 2010. NERC believes
most of the concerns it raised in those comments are not addressed in Draft 5 and continue to be a concern for NERC.
Response: The SDT thanks you for your comments; however there are not enough specifics for the SDT to respond.
•
General compliance and audit issues
NERC Comments –
o The whole “sustained outage” concept in R1 (for fall ins and blow ins) is unworkable from an enforcement
perspective.
o The difference between a violation and a non-violation in Draft 5 is whether the registered entity was fortunate with
regard to an encroachment. This part should be rewritten to say that any tree contact is a violation. VRFs and VSLs
could then be used to address whether the violation was minor or serious.
o There could be a lot of litigation over whether “circumstances” were really “beyond the control” of the TO. NERC had
previously objected to the implementation of a force majeure clause in the standard. If an entity failed to carry out
its annual plan, that should be treated as a violation, and any excuses for failing to do so or for changing the plan midyear all go to whether the penalty should be $0 or substantial.
o For the evidence retention period, the entity really should retain evidence of compliance until the next compliance
audit. Since some TOs may be on a 6 year audit schedule, the 3 year retention period is not sufficient.
Response: The SDT thanks you for your comments.
•
The SDT does not understand your comment. The violations under the existing standards are largely due to sustained outages.
•
Version 2 has a violation for every known and confirmed encroachment. The Penalty for those encroachments that do no cause Faults is up
to $30,000 per violation per day
•
The SDT thanks you for your comments. The SDT believes this language is appropriate for this standard due to the many factors related to
vegetation that are truly outside the TO’s control. Unlike the vast majority of other NERC standards, implementation of FAC-003 is not under
Consideration of Comments on Draft 5 of FAC-003-2
74
the absolute control of the utilities. These influences range from landowner and agency obstacles to weather events, and as such the SDT
believes the force majeure provisions should be applicable. The recognition of this provision is also supported by 90% of the industry. An
attempt at similar language is contained in version 1 but it is ambiguous and lacks clarity. This language adds clarity and reduces the
opportunity for misapplication. Further, TO’s must have supporting evidence for claims that situations are “beyond their control”.
•
The SDT thanks you for your comments, and will use the NERC approved retention times.
End of Report
Consideration of Comments on Draft 5 of FAC-003-2
75
Non-binding Poll of VRFs and VSLs for FAC-003-2 (February
18-28, 2011) Consideration of Comments Report
Project 2007-07 Vegetation Management — September 30, 2011
Summary Consideration:
Some entities expressed concern regarding the use of the MVCD. The SDT explained that the MVCD was established as a
beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line within its rating and all rated
electrical operating conditions, and that R3 requires that a Transmission Owner to consider the MVCD distances, as well as
variables of conductor movement and the variables associated with vegetation growth, when designing the Transmission Owner’s
overall vegetation management approach. The net result of this “building block” approach is that when entities implement R7,
their efforts will result in vegetation management at clearance distances greater than the MVCD.
Other entities questioned if the intent of the standard is to “manage vegetation” or to “prevent outages. The STD responded that
In Order 693, FERC was very specific that “…FAC-003-1 is designed to minimize transmission outages from vegetation located on
or near transmission rights-of-way by maintaining safe clearances between transmission lines and vegetation” (emphasis
added).
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment
serious consideration in this process. If you feel there has been an error or omission, you can contact the Vice President and
Director of Standards, Herb Schrayshuen, at 404-446-2563 or via email at [email protected]. In addition, there is a
NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedure: http://www.nerc.com/files/RSDP_V6_1_12Mar07.pdf.
Voter
Gregory S
Miller
Entity
Baltimore Gas
& Electric
Company
Segment
1
Vote
Comment
Affirmative
VRFs and VSLs seem reasonable.
Negative
(See comments for 2007-07.)
Response: The SDT thanks you for your comments.
Joseph S.
Stonecipher
Beaches
Energy
Services
1
Response: The SDT responded in the Successive Ballot Consideration of Comments document.
Donald S.
Watkins
Bonneville
Power
Administration
1
Affirmative
In R1 and R2 and their associated VSLs, the SDT added the
phrase “in order of increasing severity” and added the
sentence, “The types of encroachments are listed in order
of increasing degrees of severity in non-compliant
performance as it relates to a failure of a TO’s vegetation
maintenance program.” to the Rationale boxes for R1/R2.
Do you agree? If answer is no, please explain.
BPA prefers the stratified levels of violation severity
presented in the table for R1 and R2. Foot note # 2 on page
8 needs to be clarified with respect to arboricultural
activities or horticultural or agricultural activities.
Foot note # 4 on page 12 needs to be clarified with respect
to arboricultural activities or horticultural or agricultural
activities.
In response to comments received that requirement R3 is
unclear with respect to intent, the SDT added
“maintenance strategies.” Do you agree this clarifies the
intent? If answer is no, please offer alternative language.
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
2
Voter
Entity
Segment
Vote
Comment
The TO procedures / policies and specifications shall
demonstrate the TO’s ability to manage the system at all
rated conditions to maintain reliability. BPA believes that
the intent is clear, but the fundamental approach of using
the MVCD (table 2) to manage a vegetation program is still
problematic. These values are flashover distances and are
way too close. This is acknowledged in a footnote to table 2
but no identification of allowable buffers/distances
between energized phase conductors at rated
temperatures and vegetation is discussed (this is left up the
transmission owners). Clarity is needed on this topic.
Setting a finite distance limit based on recognized
standards, good science and risk avoidance should be done
for the industry. BPA has previously made this comment
during the drafting of the standard. It was not addressed
then, nor has it been addressed now.
Response: The SDT thanks you for your comments. The footnotes were changed to conform with your suggestions.
With respect to comments about the MVCD, R3 does not suggest the MVCD be used as a distance to manage vegetation. The
MVCD was established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line
within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD.
In a performance based standard, requirements are focused on “what” needs to be accomplished to achieve desired results
and avoids prescriptive requirements of “how” to achieve that result. TO’s are in the best position to determine the
appropriate management approach suited for their system, rather than a “one size fits all” or “fill in the blank” requirement
that could suppress best practices for vegetation management.
Randall
McCamish
City of Vero
Beach
1
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
Vero Beach's concern is that entities may not be able prove
compliance with the standard. R1 and R2 say that: "Each
3
Voter
Entity
Segment
Vote
Comment
Transmission Owner shall manage vegetation to prevent
encroachments ...". If the requirements were interpreted
such that "manage" is the operative word, then, we are OK
because we can provide evidence of managing a program,
such as a vegetation management plan and evidence of
executing that plan (which does not align with the
Measures). However, that 1) would cause the standard to
not be performance based, and 2) it would be duplicative of
the other requirements of the standard. If the
requirements were interpreted with "prevent
encroachment" as the operative phrase (which would be an
incorrect interpretation from the construct of the sentence)
there is no way to provide sufficient evidence that
encroachment was prevented during the audit-period. The
suggested Measures are not sufficient evidence to prove
compliance with that interpretation of the requirement. For
instance, most encroachments do not result in outages;
hence, lack of outages cannot prove that there were no
encroachments, and real time observations are insufficient
because it is a spot-check that does not cover the audit
period. There are other weaknesses in the standard, such
as R4 being un-measurable therefore unenforceable.
However, in the guilty until proven innocent paradigm we
live in, FMPA's primary concern is that industry could be
put into a no-win situation of not being able to prove
compliance with the standard if R1 and R2 are interpreted
as "prevent encroachment", and if R1 and R2 are
interpreted as "manage" then it is not a performance based
standard as advertised.
Vero Beach suggests one of two approaches: 1.
Performance based focused on preventing vegetation
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
4
Voter
Entity
Segment
Vote
Comment
related outages. For instance: "Each Transmission Owner
shall prevent vegetation related outages (except as noted
in Footnote 2) of any of its applicable line(s) ..." Evidence of
outages is practical to gather and provide, evidence of
encroachment is not. 2. Modify the standard to be similar
to the currently mandatory non-results based standard and
focus on the word "manage". This would essentially mean
eliminating R1 and R2 since the rest of the standard focuses
on having a plan and managing to that plan..
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Christopher
L de
Graffenried
Consolidated
Edison Co. of
New York
1
Affirmative
The VSLs in R6 and R7 should be consistent with each
other: R6 says '...TO failed to inspect 5% or less.....' and R7
says '...TO failed to complete up to 5%....' They both should
use the same verbiage in each VSL whether it is 'x% or less'
or 'up to and including x%.'
Response: The SDT thanks you for your comments. The SDT has changed the verbiage in the VSLs in R6 and R7 such that it
addresses you suggestion.
Michael
Gammon
Kansas City
Power & Light
Co.
1
Negative
The VSL for Requirement 7 should be clear and specifically
state this specifically addresses only "all applicable lines".
Response: The SDT thanks you for your comments. The team has added the phrase, “applicable lines” as proposed to all the
VSLs for R7.
Stan T.
Keys Energy
1
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
Concern is that entities may not be able prove compliance
with the standard. R1 and R2 say that: "Each Transmission
5
Voter
Rzad
Entity
Segment
Services
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Vote
Comment
Owner shall manage vegetation to prevent encroachments
...". If the requirements were interpreted such that
"manage" is the operative word, then, we are OK because
we can provide evidence of managing a program, such as a
vegetation management plan and evidence of executing
that plan (which does not align with the Measures).
However, that 1) would cause the standard to not be
performance based, and 2) it would be duplicative of the
other requirements of the standard. If the requirements
were interpreted with "prevent encroachment" as the
operative phrase (which would be an incorrect
interpretation from the construct of the sentence) there is
no way to provide sufficient evidence that encroachment
was prevented during the audit-period. The suggested
Measures are not sufficient evidence to prove compliance
with that interpretation of the requirement. For instance,
most encroachments do not result in outages; hence, lack
of outages cannot prove that there were no
encroachments, and real time observations are insufficient
because it is a spot-check that does not cover the audit
period. There are other weaknesses in the standard, such
as R4 being un-measurable therefore unenforceable.
However, in the guilty until proven innocent paradigm we
live in, FMPA's primary concern is that industry could be
put into a no-win situation of not being able to prove
compliance with the standard if R1 and R2 are interpreted
as "prevent encroachment", and if R1 and R2 are
interpreted as "manage" then it is not a performance based
standard as advertised. one of two approaches are
suggested: Performance based focused on preventing
vegetation related outages. For instance: "Each
Transmission Owner shall prevent vegetation related
6
Voter
Entity
Segment
Vote
Comment
outages (except as noted in Footnote 2) of any of its
applicable line(s) ..." Evidence of outages is practical to
gather and provide, evidence of encroachment is not.
Modify the standard to be similar to the currently
mandatory non-results based standard and focus on the
word "manage". This would essentially mean eliminating R1
and R2 since the rest of the standard focuses on having a
plan and managing to that plan..
Response: The SDT thanks you for your comments. In Order 693 FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Walt Gill
Lake Worth
Utilities
1
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
concern is that entities may not be able prove compliance
with the standard. R1 and R2 say that: "Each Transmission
Owner shall manage vegetation to prevent encroachments
...". If the requirements were interpreted such that
"manage" is the operative word, then, we are OK because
we can provide evidence of managing a program, such as a
vegetation management plan and evidence of executing
that plan (which does not align with the Measures).
However, that 1) would cause the standard to not be
performance based, and 2) it would be duplicative of the
other requirements of the standard. If the requirements
were interpreted with "prevent encroachment" as the
operative phrase (which would be an incorrect
interpretation from the construct of the sentence) there is
no way to provide sufficient evidence that encroachment
was prevented during the audit-period. The suggested
Measures are not sufficient evidence to prove compliance
7
Voter
Entity
Segment
Vote
Comment
with that interpretation of the requirement. For instance,
most encroachments do not result in outages; hence, lack
of outages cannot prove that there were no
encroachments, and real time observations are insufficient
because it is a spot-check that does not cover the audit
period. There are other weaknesses in the standard, such
as R4 being un-measurable therefore unenforceable.
However, in the guilty until proven innocent paradigm we
live in, FMPA's primary concern is that industry could be
put into a no-win situation of not being able to prove
compliance with the standard if R1 and R2 are interpreted
as "prevent encroachment", and if R1 and R2 are
interpreted as "manage" then it is not a performance based
standard as advertised. suggest one of two approaches: 1.
Performance based focused on preventing vegetation
related outages. For instance: "Each Transmission Owner
shall prevent vegetation related outages (except as noted
in Footnote 2) of any of its applicable line(s) ..." Evidence of
outages is practical to gather and provide, evidence of
encroachment is not. 2. Modify the standard to be similar
to the currently mandatory non-results based standard and
focus on the word "manage". This would essentially mean
eliminating R1 and R2 since the rest of the standard focuses
on having a plan and managing to that plan..
Response: The SDT thanks you for your comments. In Order 693 FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
8
Voter
Entity
Marvin E
VanBebber
Oklahoma Gas
and Electric
Co.
Segment
1
Vote
Negative
Comment
R3 VSL leaves a lot open to interpetation in the analysis
area. This is one where the auditor could be heavy handed
if he desired.
Response: The SDT thanks you for your comments. The Requirement 3 VSL does in fact give TO significant latitude with respect
to maintaining appropriate clearances. As noted in the Rationale, “The documentation provides a basis for evaluating the
competency of the Transmission Owner’s vegetation program. There may be many acceptable approaches to maintain
clearances.” In a performance based standard, requirements (and associated VSLs) are focused on “what” needs to be
accomplished to achieve desired results and avoids prescriptive requirements of “how” to achieve that result. TO’s are in the
best position to determine the appropriate management approach suited for their system rather than a “one-size-fits-all”
requirement that could suppress best practices for vegetation management. With this in mind, if the TO is audited, and it has a
well crafted vegetation management program and has properly documented procedures and results, it should be in a good
position.
Keith V
Carman
Tri-State G & T
Association,
Inc.
1
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “ installation of”.
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Mark B
Thompson
Alberta
Electric
System
Operator
2
Abstain
VRFs and VSLs are set by Provincial authorities in Alberta.
Response: The SDT thanks you for your comments.
David A.
Lapinski
Consumers
Energy
3
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
Comments on FAC-003-2 February 25, 2011 Consumers
Energy submits the following comments on FAC-003-2: In
general we are please with FAC-003-2 and the many
clarifications that the STD has made in this version of the
standard. However, we do have one major disagreement
with the STD and cannot support this standard as drafted.
9
Voter
Entity
Segment
Vote
Comment
We disagree with the use of the Minimum Vegetation
Clearance Distance (MVCD) developed by the drafting team
for Requirements R1 and R2. These distances are not the
design distances used for designing and constructing
transmission facilities as stated in the document for
minimum distances between conductors and grounded
objects. The proposed Table 2 provides a distance of 3.12
feet as the acceptable distance for an alternate current
345kV line at sea level. This distance is considerably less
than the distance used for line design to separate the
grounded tower structure from the energized conductor. If
the distance in Table 2 is acceptable to prevent energized
portions of a transmission line from grounding to a tree
why then is this distance not the design criteria used for
tower design to prevent flashover from conductor to
tower? The STD needs to explain why a ground tree should
have a different standard that a grounded steel tower or
wood pole structure. The STD erroneously viewed the
possibility of transient over voltage as only occurring during
re-energizing and not from natural events such as a
lightning strike that can occur and does occur to energized
operating lines. Secondly, the proposed distances in Table 2
are considerably less than the distances specified in OSHA
requirements for air gap clearance required by tree
workers to safely remove trees or limbs from conductors
energized at the voltages specified. A transmission
owner/operator could let a tree grow to within 3.5 feet of a
345 kV line and not be in violation of this proposed
standard. To remove the tree, the line would have to be deenergized, tagged, tested de-energized, and grounded.
Working clearance would have to be established by the
operating entity and then the tree crew could remove the
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
10
Voter
Entity
Segment
Vote
Comment
tree. The net result is the loss of the capacity of the line
because an outage was forced on the line in order to
remove the tree that did not trigger a violation of FAC-0032. This situation, in our opinion, is a violation of the intent
of the standard, which is to ensure the continued operation
of the line. Therefore, the minimum distance any tree
should be able to approach a conductor is more than the
minimum requirement for air gap distance between the
tree and conductor as required by OSHA worker standards.
The STD did not like referring to another standard to
provide the distance requirements for R1 and R2. This can
be alleviated by putting in a table with the IEEE 516
distances but not reference it as the IEEE 516 standard. The
distances provided in the current draft do not adequately
provide or ensure the continued safe operation of the
transmission facilities in the United States and the
reasoning for the distances provided is unfounded and not
based on current design practices.
Response: The SDT thanks you for your comments. You are correct that these distances do not represent complete design
specifications for towers, nor define and describe safe worker approach distances. These practices are correctly specified in the
other standards you referenced. The SDT feels the standard is clear in that regard. The footnote associated with the Table 2
distances clearly states that these are only distances to prevent flashover under appropriate conditions. The SDT would also
like to point out that the transient overvoltage factors used to derive these distances are the maximums normally seen with a
transmission line in steady state service. Thus, a tower design would have to account for the larger overvoltage factors that are
possible while taking lines out of service.
As has been stated before, these distances were derived using a known set of line design equations and only represent
distances that will prevent spark-over from the transmission line to a grounded object. These are not distances to be managed
to – they have been established as a beginning of a series of “building blocks” for a program to ensure reliability of a
Transmission line within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner’ consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
11
Voter
Entity
Segment
Vote
Comment
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD.
These distances are smaller than safety standard distances that have many other factors involved in the determination, such as
inadvertent human movement and larger safety factors. In regard to the over-voltages caused by lightning, even the maximum
overvoltage factors contained in the IEEE-516 tables do not account for these.
Russell A
Noble
Cowlitz
County PUD
3
Negative
Referring back to Cowlitz’ negative vote made on the 7/919/2010 ballot, Cowlitz tried to convey the problem that
the statement in R4 “without intentional time delay” will
require subjective judgment on the part of the auditor. In
other words, maintaining equal auditing standard
throughout the interconnection will be impossible with this
verbiage in a requirement. Cowlitz agrees with the SDT that
establishing an equitable time frame is very difficult (it may
be impossible!); however leaving it to the judgment of the
auditor to determine whether an intentional delay was
made is most disagreeable. Cowlitz respectfully points out
that the SDT did not adequately address the subjective
nature the auditor is forced into with this requirement. If
establishing “[t]he time required by the to report an issue is
subject to many variables...” and “[f]or this reason it is
difficult to establish a time period which would fairly apply
to all TO’s,” how does leaving this to the auditor to decide
going to make it any better?
Response: The SDT thanks you for your comments. The SDT believes that it was not prudent to suggest a quantitative time
element for notification in R4. The technical reference offers examples of acceptable unintentional delays for your review. The
SDT notes that this language is already embodied in at least one other FERC-approved, in-force Standard.
Charles
Locke
Kansas City
Power & Light
Co.
3
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
The VSL for Requirement 7 should be clear and specifically
state this specifically addresses only "all applicable lines".
12
Voter
Entity
Segment
Vote
Comment
Response: The SDT thanks you for your comments. The team has added the phrase, “applicable lines” as proposed to all the
VSLs for R7.
Mace
Hunter
Lakeland
Electric
3
Affirmative
R1. Each Transmission Owner shall manage vegetation to
prevent encroachments of the types shown below, --------------- and all Rated Electrical Operating Conditions.2 1. An
encroachment into the MVCD as shown in FAC-003-Table 2,
observed in Real-time, absent a Sustained Outage, that is
not corrected within 5 working days of discovery, Make the
same change to R2 Type 1 encroachment and reflect the
changes in Table 1. Rational: This condition would enable a
entity to discover an encroachment and clear it without
having to self report a possible violation as long as the
conditions was corrected within 5 working days. The
change should encourage extra inspections for problem
areas more often than annually as required in R6. There
should be no negative consequences for diligent inspection
of lines as long as the problem is clear with a defined time
such as 5 or 10 working days.
Response: The SDT thanks you for your comment. As a general rule, a revised standards should not be less stringent than the
existing standard it replaces. In the existing standard, a violation occurs when the encroachment occurs. A ‘find and fix’ of five
days would be viewed as a lowering the level of performance required by the current standard.
Rick Syring
Cowlitz
County PUD
4
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
Referring back to Cowlitz’ negative vote made on the 7/919/2010 ballot, Cowlitz tried to convey the problem that
the statement in R4 “without intentional time delay” will
require subjective judgment on the part of the auditor. In
other words, maintaining equal auditing standard
throughout the interconnection will be impossible with this
verbiage in a requirement. Cowlitz agrees with the SDT that
establishing an equitable time frame is very difficult (it may
be impossible!); however leaving it to the judgment of the
13
Voter
Entity
Segment
Vote
Comment
auditor to determine whether an intentional delay was
made is most disagreeable. Cowlitz respectfully points out
that the SDT did not adequately address the subjective
nature the auditor is forced into with this requirement. If
“[t]he time required by the entity to report an issue is
subject to many variables...” and “[f]or this reason it is
difficult to establish a time period which would fairly apply
to all TO’s,” how does leaving this to the auditor to decide
going to make it any better? You will be forcing the audited
entity to "prove the negative."
Response: The SDT thanks you for your comments. The SDT believes that it was not prudent to suggest a quantitative time
element for notification in R4. The technical reference offers examples of acceptable unintentional delays for your review. The
SDT notes that this language is already embodied in at least one other FERC-approved, in-force Standard.
Frank
Gaffney
Florida
Municipal
Power Agency
4
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
R1 and R2 requirement reads: "Each Transmission Owner
shall manage to prevent encroachment ....". The results of
manage would be invoices of tree trimming actually
performed, documentation of a vegetation management
program that would be managed to, etc. However, the
Measures proposed are all actual outages which are neither
evidence of management nor evidence of encroachment
since there can be encroachment without an outage, and in
fact, many if not most encroachments do not result in
outages. Hence, the Measures are inconsistent with the
requirements. Further, there is ambiguity of the action
required in requirements R1 and R2 - e.g., do entities need
evidence that they: 1) "manage", or 2) "prevent
encroachment"; or 3) as implied by the Measures, prevent
vegetation related outages?. In other words, what needs to
be proven through evidence? Certainly the third, prevent
vegetation related outages, is not in the Requirement; yet,
that us what is proposed for the Measures, highlighting the
14
Voter
Entity
Segment
Vote
Comment
inconsistency between Requirements and Measures. But,
how would the ambiguity between "manage" and "prevent
encroachment" be resolved? One auditor could interpret
that the requirement is to "manage" and accept a
vegetation management program and plan and proof that
the plan was executed as appropriate evidence. Another
auditor could interpret that "prevent" is the key word and
look for evidence proving that there was never a vegetation
encroachment. How would evidence be produced to
provide the auditor that vegetation never encroached?
Would video cameras and other surveillance measures
need to operate 24 hours a day? Would we cause an entity
to survey the lines periodically? One can easily see that
"prevent encroachment" is inappropriate here since it is
infeasible to create evidence of compliance. FMPA suggests
one of two approaches: Eliminate the word manage, but do
not focus on encroachment and instead focus on outages.
For instance: "Each Transmission Owner shall prevent
vegetation related outages (except as noted in Footnote 2)
of any of its applicable line(s) ..." Evidence of outages is
practical to gather and provide, evidence of encroachment
is not. Focus on the word "manage", similar to the existing
FAC-003 standard, and move R3 to a new R1 to develop a
management plan, and then the existing R1 and R2 become
R2 an R3 and require execution of that plan in the words of
R7, which would in turn enables elimination of R7.
Response: The SDT thanks you for your comments. In Order 693 FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
15
Voter
Entity
Segment
Vote
Comment
Affirmative
For the Requirement R1 and R2 VSLs, we suggest that the
proposed Moderate (fall-ins) and High (blowing together)
VSL be interchanged. We believe that fall-ins are more
severe encroachments than blowing together and the
categories listed in the compliance section support this
point. Category 1 (grow-ins) is most severe, followed by
Category 2 & 3 (fall-ins) and Category 4 (blowing together.
If the team elects to not make the suggested VSL changes
then a change in the category listing within the compliance
section is warranted. Either way they should be consistent.
inspections in which clearances are evaluated.
Douglas
Hohlbaugh
Ohio Edison
Company
4
Response: The SDT believes that there is consensus that “blowing-together” events are more indicative of a program failure
than are “fall-in” events. Further, the risk to the transmission system from blowing-together events is greater than for fall-ins;
partly because blowing-together events are more likely to repeat themselves, whereas fall-ins generally end on the spot. The
SDT agrees with you that the ordering of the categories seems to convey a different message; however, re-sequencing the
categories in order of severity would have led to a clash with the existing categories in Version 1 and thus would have provoked
widespread confusion.
Francis J.
Halpin
Bonneville
Power
Administration
5
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Affirmative
In R1 and R2 and their associated VSLs, the SDT added the
phrase “in order of increasing severity” and added the
sentence, “The types of encroachments are listed in order
of increasing degrees of severity in non-compliant
performance as it relates to a failure of a TO’s vegetation
maintenance program.” to the Rationale boxes for R1/R2.
Do you agree? If answer is no, please explain.
BPA prefers the stratified levels of violation severity
presented in the table for R1 and R2. Foot note # 2 on page
8 needs to be clarified with respect to arboricultural
activities or horticultural or agricultural activities.
16
Voter
Entity
Segment
Vote
Comment
Foot note # 4 on page 12 needs to be clarified with respect
to arboricultural activities or horticultural or agricultural
activities.
In response to comments received that requirement R3 is
unclear with respect to intent, the SDT added
“maintenance strategies.” Do you agree this clarifies the
intent? If answer is no, please offer alternative language.
The TO procedures / policies and specifications shall
demonstrate the TO’s ability to manage the system at all
rated conditions to maintain reliability. BPA believes that
the intent is clear, but the fundamental approach of using
the MVCD (table 2) to manage a vegetation program is still
problematic. These values are flashover distances and are
way too close. This is acknowledged in a footnote to table 2
but no identification of allowable buffers/distances
between energized phase conductors at rated
temperatures and vegetation is discussed (this is left up the
transmission owners). Clarity is needed on this topic.
Setting a finite distance limit based on recognized
standards, good science and risk avoidance should be done
for the industry. BPA has previously made this comment
during the drafting of the standard. It was not addressed
then, nor has it been addressed now.
Response: The SDT thanks you for your comments. The footnotes were changed to conform with your suggestions.
With respect to comments about the MVCD, R3 does not suggest the MVCD be used as a distance to manage vegetation. The
MVCD was established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line
within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
17
Voter
Entity
Segment
Vote
Comment
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD distances.
In a performance based standard, requirements are focused on “what” needs to be accomplished to achieve desired results
and avoids prescriptive requirements of “how” to achieve that result. TO’s are in the best position to determine the
appropriate management approach suited for their system rather than a “one size fits all” requirements that could suppress
best practices for vegetation management.
James B
Lewis
Consumers
Energy
5
Negative
See comments on the Standard.
Response: The SDT thanks you for your comments that were made during the formal comment period for the Standard; the
SDT’s responses to those comments are available there.
Bob Essex
Cowlitz
County PUD
5
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
Referring back to Cowlitz’ negative vote made on the 7/919/2010 ballot, Cowlitz tried to convey the problem that
the statement in R4 “without intentional time delay” will
require subjective judgment on the part of the auditor. In
other words, maintaining equal auditing standard
throughout the interconnection will be impossible with this
verbiage in a requirement. Cowlitz agrees with the SDT that
establishing an equitable time frame is very difficult (it may
be impossible!); however leaving it to the judgment of the
auditor to determine whether an intentional delay was
made is most disagreeable. Cowlitz respectfully points out
that the SDT did not adequately address the subjective
nature the auditor is forced into with this requirement. If
establishing “[t]he time required by the to report an issue is
subject to many variables...” and “[f]or this reason it is
difficult to establish a time period which would fairly apply
to all TO’s,” how does leaving this to the auditor to decide
going to make it any better?
18
Voter
Entity
Segment
Vote
Comment
Response: The SDT thanks you for your comments. The SDT believes that it was not prudent to suggest a quantitative time
element for notification in R4. The technical reference offers examples of acceptable unintentional delays for your review. The
SDT notes that this language is already embodied in at least one other FERC-approved, in-force Standard.
David
Schumann
Florida
Municipal
Power Agency
5
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
R1 and R2 requirement reads: "Each Transmission Owner
shall manage to prevent encroachment ....". The results of
manage would be invoices of tree trimming actually
performed, documentation of a vegetation management
program that would be managed to, etc. However, the
Measures proposed are all actual outages which are neither
evidence of management nor evidence of encroachment
since there can be encroachment without an outage, and in
fact, many if not most encroachments do not result in
outages. Hence, the Measures are inconsistent with the
requirements. Further, there is ambiguity of the action
required in requirements R1 and R2 - e.g., do entities need
evidence that they: 1) "manage", or 2) "prevent
encroachment"; or 3) as implied by the Measures, prevent
vegetation related outages?. In other words, what needs to
be proven through evidence? Certainly the third, prevent
vegetation related outages, is not in the Requirement; yet,
that us what is proposed for the Measures, highlighting the
inconsistency between Requirements and Measures. But,
how would the ambiguity between "manage" and "prevent
encroachment" be resolved? One auditor could interpret
that the requirement is to "manage" and accept a
vegetation management program and plan and proof that
the plan was executed as appropriate evidence. Another
auditor could interpret that "prevent" is the key word and
look for evidence proving that there was never a vegetation
encroachment. How would evidence be produced to
provide the auditor that vegetation never encroached?
19
Voter
Entity
Segment
Vote
Comment
Would video cameras and other surveillance measures
need to operate 24 hours a day? Would we cause an entity
to survey the lines periodically? One can easily see that
"prevent encroachment" is inappropriate here since it is
infeasible to create evidence of compliance. FMPA suggests
one of two approaches: Eliminate the word manage, but do
not focus on encroachment and instead focus on outages.
For instance: "Each Transmission Owner shall prevent
vegetation related outages (except as noted in Footnote 2)
of any of its applicable line(s) ..." Evidence of outages is
practical to gather and provide, evidence of encroachment
is not. Focus on the word "manage", similar to the existing
FAC-003 standard, and move R3 to a new R1 to develop a
management plan, and then the existing R1 and R2 become
R2 an R3 and require execution of that plan in the words of
R7, which would in turn enables elimination of R7.
Response: The SDT thanks you for your comments. In Order 693 FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Brenda S.
Anderson
Bonneville
Power
Administration
6
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Affirmative
BPA Comments with Yes Vote: In R1 and R2 and their
associated VSLs, the SDT added the phrase “in order of
increasing severity” and added the sentence, “The types of
encroachments are listed in order of increasing degrees of
severity in non-compliant performance as it relates to a
failure of a TO’s vegetation maintenance program.” to the
Rationale boxes for R1/R2. Do you agree? If answer is no,
please explain.
BPA prefers the stratified levels of violation severity
20
Voter
Entity
Segment
Vote
Comment
presented in the table for R1 and R2.
Foot note # 2 on page 8 needs to be clarified with respect
to arboricultural activities or horticultural or agricultural
activities. Foot note # 4 on page 12 needs to be clarified
with respect to arboricultural activities or horticultural or
agricultural activities.
In response to comments received that requirement R3 is
unclear with respect to intent, the SDT added
“maintenance strategies.” Do you agree this clarifies the
intent? If answer is no, please offer alternative language.
The TO procedures / policies and specifications shall
demonstrate the TO’s ability to manage the system at all
rated conditions to maintain reliability. BPA believes that
the intent is clear, but the fundamental approach of using
the MVCD (table 2) to manage a vegetation program is still
problematic. These values are flashover distances and are
way too close. This is acknowledged in a footnote to table 2
but no identification of allowable buffers/distances
between energized phase conductors at rated
temperatures and vegetation is discussed (this is left up the
transmission owners). Clarity is needed on this topic.
Setting a finite distance limit based on recognized
standards, good science and risk avoidance should be done
for the industry. BPA has previously made this comment
during the drafting of the standard. It was not addressed
then, nor has it been addressed now.
Response: The SDT thanks you for your comments. The footnotes were changed to conform with your suggestions. With
respect to comments about the MVCD, R3 does not suggest the MVCD be used as a distance to manage vegetation. The MVCD
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
21
Voter
Entity
Segment
Vote
Comment
was established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line within its
rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner’ consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD distances.
In a performance based standard, requirements are focused on “what” needs to be accomplished to achieve desired results
and avoids prescriptive requirements of “how” to achieve that result. TO’s are in the best position to determine the
appropriate management approach suited for their system rather than a “one size fits all” requirement that could suppress
best practices for vegetation management.
Nickesha P
Carrol
Consolidated
Edison Co. of
New York
6
Affirmative
The VSLs in R6 and R7 should be consistent with each
other: R6 says '...TO failed to inspect 5% or less.....' and R7
says '...TO failed to complete up to 5%....' They both should
use the same verbiage in each VSL whether it is 'x% or less'
or 'up to and including x%.'
Response: The SDT thanks you for your comments. The SDT has changed the verbiage in the VSLs in R6 and R7 such that it
addresses you suggestion.
Mark S
Travaglianti
FirstEnergy
Solutions
6
Affirmative
FirstEnergy supports standard FAC-003-2 and would
appreciate consideration of our comments submitted
through the formal comment period.
Response: The SDT thanks you for your comments and has reviewed and responded to your comments made during the formal
comment period.
Thomas E
Washburn
Florida
Municipal
Power Pool
6
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
The concern is that entities may not be able prove
compliance with the standard. R1 and R2 say that: "Each
Transmission Owner shall manage vegetation to prevent
encroachments ...". If the requirements were interpreted
such that "manage" is the operative word, then, we are OK
because we can provide evidence of managing a program,
such as a vegetation management plan and evidence of
22
Voter
Entity
Segment
Vote
Comment
executing that plan (which does not align with the
Measures). However, that 1) would cause the standard to
not be performance based, and 2) it would be duplicative of
the other requirements of the standard. If the
requirements were interpreted with "prevent
encroachment" as the operative phrase (which would be an
incorrect interpretation from the construct of the sentence)
there is no way to provide sufficient evidence that
encroachment was prevented during the audit-period. The
suggested Measures are not sufficient evidence to prove
compliance with that interpretation of the requirement. For
instance, most encroachments do not result in outages;
hence, lack of outages cannot prove that there were no
encroachments, and real time observations are insufficient
because it is a spot-check that does not cover the audit
period. There are other weaknesses in the standard, such
as R4 being un-measurable therefore unenforceable.
However, in the guilty until proven innocent paradigm we
live in, FMPA's primary concern is that industry could be
put into a no-win situation of not being able to prove
compliance with the standard if R1 and R2 are interpreted
as "prevent encroachment", and if R1 and R2 are
interpreted as "manage" then it is not a performance based
standard as advertised. Performance based focused on
preventing vegetation related outages. For instance: "Each
Transmission Owner shall prevent vegetation related
outages (except as noted in Footnote 2) of any of its
applicable line(s) ..." Evidence of outages is practical to
gather and provide, evidence of encroachment is not.
Modify the standard to be similar to the currently
mandatory non-results based standard and focus on the
word "manage". This would essentially mean eliminating R1
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
23
Voter
Entity
Segment
Vote
Comment
and R2 since the rest of the standard focuses on having a
plan and managing to that plan..
Response: The SDT thanks you for your comments. In Order 693 FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Thomas
Saitta
Kansas City
Power & Light
Co.
6
Negative
The VSL for Requirement 7 should be clear and specifically
state this specifically addresses only "all applicable lines".
Response: The SDT thanks you for your comments. The team has added the phrase, “applicable lines” as proposed to all the
VSLs for R7.
James
Eckelkamp
Progress
Energy
6
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “installation of."
Response: The SDT thanks you for your comments. The changes to the footnotes have been made as proposed.
Guy V. Zito
Northeast
Power
Coordinating
Council, Inc.
10
Affirmative
The use of the term “encroachment”, and the lack of clarity
in defining clearances is an issue that should be addressed
by the Drafting Team.
Response: The SDT thanks you for your comments. With regard to the use of “encroachment” and the clarity in defining
clearances as it relates to the VRFs and VSLs, the SDT has taken what was a “gray” area in Version 1 and added more clarity
with regard to compliance. In Version 1, it is not actually clear whether experiencing an encroachment or experiencing outage
is a violation of the standard. The SDT recognized this concern and has addressed this via the proposed VSLs for R1 and R2.
These proposed VSLs are designed such to correlate to the severity level of failure of the Transmission Owner’s vegetation
management program.
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
24
Voter
Entity
Segment
Vote
Comment
If you refer to the VSLs for R1 and R2, only the “Lower” VSLs apply to an encroachment, and that has been defined as “an
encroachment into the MVCD observed in Real-time, absent a Sustained Outage.” The “MVCD” clearance distance is clearly
defined in Table 2 of the Standard. After the Lower VSL level for these requirements, the Moderate to Severe VSLs are
correlated more directly to the severity of failure of the Transmission Owner’s vegetation management program associated
with a Sustained Outage. The SDT makes this recommendation of VSLs based on this being an improvement for compliance
clarity over version 1 of the standard.
Anthony E
Jablonski
ReliabilityFirst
Corporation
10
Negative
ReliabilityFirst votes negative and has the following
comments regarding the VRFs and VSLs:
1. VRF for R1 and R2 a. The Final Report on the August
14th, 2003 Blackout in the United States and Canada:
Causes and Recommendations Blackout Report, highlights
the importance of all vegetation management work by
identifying inadequate vegetation management as one of
the causes of the 2003 Blackout. Based on the Blackout
Report there should be no distinction between
encroachments of applicable line(s) identified as an
element of an Interconnection Reliability Operating Limit
(IROL) or Major Western Electricity Coordinating Council
(WECC) transfer path(s) and encroachments of applicable
line(s) not identified as an element of an Interconnection
Reliability Operating Limit (IROL) or Major Western
Electricity Coordinating Council (WECC) transfer path(s).
Therefore, ReliabilityFirst recommends that VRFs should be
the same for R1 and R2.
2. VSL for R3 a. Since this requirement has sub-parts
associated with it, the associated sub-part number should
be referenced in the VSL itself.
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
25
Voter
Entity
Segment
Vote
Comment
3. VSL for R4 a. The words in the VLS do not match the
language in the requirement. The words “vegetation
threat” is not mentioned in Requirement R4. Based on the
FERC Guideline #3 “Violation Severity Level Assignment
Should Be Consistent with the Corresponding Requirement”
4. VSL for R6 a. The following qualifier should be added to
the end of each of the four VSLs, “...at least once per
calendar year and with no more than 18 months between
inspections on the same ROW” to be consistent with the
corresponding requirement and in accordance with the
FERC Guideline #3.
5. VSL for R7 a. There is no associated VSL dealing with the
second part of the requirement which references that “...
the Modifications to the work plan... must be
documented.” Where does an entity fall if they have
complete 100% of its annual vegetation work plan, but
failed to document any modifications to the work plan?
This aspect of the requirement should be addressed in the
corresponding VSLs.
Response: The SDT thanks you for your comments.
1) In Order 693 FERC was very specific that “…FAC-003-1 is designed to minimize transmission outages from vegetation located
on or near transmission rights-of-way by maintaining safe clearances between transmission lines and vegetation” (emphasis
added). Following that concept, the SDT used R1 and R2 to move the clearance from a documentation requirement to a
performance requirement. .
R1 and R2 are dealing with the differentiation between lines that fall into an IROL or WECC Transfer Path definition and those
lines that do not. The SDT asserts that different VRF’s for IROL and non-IROL lines strengthens the reliability of the standard.
Vegetation managers that do not know which lines are IROL or WECC Transfer Paths may be inappropriately limiting resources
allocated to vegetation management for an IROL line or a WECC Transfer Path. A vegetation manager must ensure that the
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
26
Voter
Entity
Segment
Vote
Comment
IROL lines and WECC transfer paths are absolutely clear. By correctly identifying the risk associated with an IROL line and/or a
WECC Transfer Path, the standard helps to assure that appropriate resources are applied.
2) The sub-parts referred to are part of the RBS building block approach to document how a TO prevents encroachment of
vegetation into the MVCD. The sub parts are not separate elements but make up the processes, strategies, procedures or
specifications to prevent encroachment in to the MVCD.
3) The SDT believes the correlation between R4 and the VSL is appropriate.
4) The SDT believes the correlation between R6 and the VSL is appropriate.
5) The wording in the VSL for R7 has been modified to address modifications to the annual work plan.
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
27
Successive Ballot (February 18-28, 2011) Consideration of
Comments Report
Project 2007-07 Vegetation Management — September 30, 2011
Summary Consideration:
In order to be consistent with the latest version of NERC’s Results Based Standards template, the heading “Objective” was replaced
with “Purpose,” and the numbering, headings, and sections were reformatted as necessary.
Several entities expressed concern with the use of the Minimum Vegetation Clearance Distance (MVCD) and elimination of
Clearance 1. With respect to comments about the MVCD, R3 does not suggest the MVCD be used as a distance to manage
vegetation. The MVCD was established as a beginning of a series of “building blocks” for a program to ensure reliability of a
Transmission line within its rating and all rated electrical operating conditions. R3 requires that a Transmission Owner consider the
MVCD distances, as well as variables of conductor movement and vegetation growth, when designing the Transmission Owner’s
overall vegetation management approach. The net result of this “building block” approach is that when entities implement R7, their
efforts will result in vegetation management at clearance distances greater than the MVCD. In a performance-based standard,
requirements are focused on “what” needs to be accomplished to achieve desired results and avoids prescriptive requirements of
“how” to achieve that result. TO’s are in the best position to determine the appropriate management approach suited for their
system, rather than a “one size fits all” or “fill in the blank” requirement that could suppress best practices for vegetation
management.
Other entities questioned whether the goal of the standard was to “prevent outages” or to “manage vegetation.” In Order 693, FERC
was very specific that “…FAC-003-1 is designed to minimize transmission outages from vegetation located on or near transmission
rights-of-way by maintaining safe clearances between transmission lines and vegetation.” The drafting team followed that concept
and used R1 and R2 to move the clearance from a documentation requirement to a performance requirement. Item 1 in the
requirements defines how an encroachment without an outage would be documented. Each Transmission Owner is also required to
conduct inspections in which clearances are evaluated.
Some entities expressed concern with the mandatory inspection intervals proposed in the standard. The SDT recognizes that a
number of Transmission Owners in North America may prefer to set their own inspection intervals. Because there is substantial
industry support for an annual inspection interval the SDT believes that the industry is best served with this approach.
Several entities suggested making minor changes to clarify the footnotes. The team did so.
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment
serious consideration in this process. If you feel there has been an error or omission, you can contact the Vice President and Director
of Standards, Herb Schrayshuen, at 404-446-2563 or at [email protected]. In addition, there is a NERC Reliability Standards
Appeals Process.1
Voter
Paul B.
Johnson
Entity
American
Electric Power
Segment
1
Vote
Affirmative
Comment
American Electric Power believes that the phrase
"arboricultural activities or horticultural or agricultural
activities" was mistakenly introduced into Footnotes 2 and
4, and should be deleted from both footnotes. If the phrase
remains in the Standard, it may empower orchard growers,
landowners and others to plant trees on the right of way
and challenge Transmission Owners' rights to perform
maintenance on the presumption that the standard will
exempt the TO from violating the outage or encroachment
requirements.
For increased clarity, AEP offers the following change to the
second paragraph of M1, as well as the second paragraph of
M2. The original text “If a later confirmation of a Fault by
the Transmission Owner shows that a vegetation
encroachment within the MVCD has occurred from
vegetation within the ROW, this shall be considered the
equivalent of a Real-time observation” should be replaced
1
The appeals process is in the Reliability Standards Development Procedure: http://www.nerc.com/files/RSDP_V6_1_12Mar07.pdf.
Consideration of Comments on Successive Ballot of FAC-003-2
2
Voter
Entity
Segment
Vote
Comment
with “If a later confirmation of a Fault by the Transmission
Owner shows that a vegetation encroachment within the
MVCD has occurred from vegetation growing into or
blowing together with the conductor within the ROW, this
shall be considered the equivalent of a Real-time
observation. A brief encroachment caused by falling
vegetation passing through the MVCD is not considered an
encroachment in this requirement”.
Response: Thank you for your comments. The SDT made suggested changes to the footnotes as proposed.
Regarding the issue of fall-ins, the SDT is sympathetic to your concern. In fact, the SDT had originally crafted language similar to
that which you suggested. However, due to concerns expressed by regulators and others, the exemption for encroachment
violations due to falling vegetation from inside the right of way was removed.
Robert D
Smith
Arizona Public
Service Co.
1
Negative
Overall comment: The objective, as written, is about
outages that can lead to cascading and not about reliability.
Recommended change to Standard Objective: To maintain a
reliable electric transmission system, implement a defensein-depth strategy to manage vegetation located on
transmission rights of way (ROW) and minimize
encroachments from vegetation located adjacent to the
ROW.
Response: The SDT thanks you for your comment. With respect to the Purpose as written in the proposed standard, the
language clearly states “To improve the reliability of the electric Transmission system…” The SDT made it a point to keep the
Purpose as concise as possible without getting into issues that are covered further in the body of the standard.
John
Bussman
Associated
Electric
Cooperative,
Inc.
1
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
R1 - “Each Transmission Owner shall manage vegetation to
prevent encroachments of the types shown below, into the
Minimum Vegetation Clearance Distance (MVCD) of any of
its applicable line(s) identified as an element of an
Interconnection Reliability Operating Limit (IROL) in the
planning horizon by the Planning Coordinator; or Major
Western Electricity Coordinating Council (WECC) transfer
3
Voter
Entity
Segment
Vote
Comment
path(s); operating within its Rating and all Rated Electrical
Operating Conditions...”
The following is my preliminary comment on this
requirement. R1 - Associated Electric Cooperative Inc wants
to thank the SDT for their hard work and all the effort
associated with this standard. However we currently
disagrees with the inclusion in this requirement of any and
all IROLs identified within the entire planning horizon
(typically 10 years or more). Associated Electric certainly
agrees that in real time and in the near term sub 200 kV
elements of an IROL should be subject to R1. It seems
unreasonable, however, to include a sub 200 kV
transmission line that might become an IROL element 10
years in the future. Perhaps the time frame could be limited
to the Transmission Owner’s planned maintenance cycle.
Response: The SDT thanks you for your comment, and has revised the Standard’s effective dates (exceptions) accordingly.
Gregory S
Miller
Baltimore Gas
& Electric
Company
1
Affirmative
There seems to be a marginal level of improvement over the
previous drafts.
Negative
R1 and R2 Requirement reads: "Each Transmission Owner
shall manage to prevent encroachment ....". The results of
manage would be invoices of tree trimming actually
performed, documentation of a vegetation management
program that would be managed to, etc. However, the
Measures proposed are all actual outages which are neither
Response: The SDT thanks you for your comment.
Joseph S.
Stonecipher
Beaches
Energy
Services
1
Consideration of Comments on Successive Ballot of FAC-003-2
4
Voter
Entity
Segment
Vote
Comment
evidence of management nor evidence of encroachment
since there can be encroachment without an outage, and in
fact, many if not most encroachments do not result in
outages. Hence, the Measures are inconsistent with the
Requirements.
Further, there is ambiguity of the action required in
requirements R1 and R2 - e.g., do entities need evidence
that they: 1) "manage", or 2) "prevent encroachment"; or 3)
as implied by the Measures, prevent vegetation related
outages? In other words, what needs to be proven through
evidence? Certainly the third, prevent vegetation related
outages, is not in the Requirement; yet, that us what is
proposed for the Measures, highlighting the inconsistency
between Requirements and Measures. But, how would the
ambiguity between "manage" and "prevent encroachment"
be resolved? One auditor could interpret that the
Requirement is to "manage" and accept a vegetation
management program and plan and proof that the plan was
executed as appropriate evidence. Another auditor could
interpret that "prevent" is the key word and look for
evidence proving that there was never a vegetation
encroachment. How would evidence be produced to
provide the auditor that vegetation never encroached?
Would video cameras and other surveillance measures need
to operate 24 hours a day? Would we cause an entity to
survey the lines periodically? One can easily see that
"prevent encroachment" is inappropriate here since it is
infeasible to create evidence of compliance.
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
Consideration of Comments on Successive Ballot of FAC-003-2
5
Voter
Entity
Segment
Vote
Comment
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Donald S.
Watkins
Bonneville
Power
Administration
1
Affirmative
R2. Do you agree? If answer is no, please explain.
BPA prefers the stratified levels of violation severity
presented in the table for R1 and R2. Foot note # 2 on page
8 needs to be clarified with respect to arboricultural
activities or horticultural or agricultural activities. Foot note
# 4 on page 12 needs to be clarified with respect to
arboricultural activities or horticultural or agricultural
activities.
In response to comments received that requirement R3 is
unclear with respect to intent, the SDT added “maintenance
strategies.” Do you agree this clarifies the intent? If answer
is no, please offer alternative language.
The TO procedures / policies and specifications shall
demonstrate the TO’s ability to manage the system at all
rated conditions to maintain reliability. BPA believes that
the intent is clear, but the fundamental approach of using
the MVCD (table 2) to manage a vegetation program is still
problematic. These values are flashover distances and are
way too close. This is acknowledged in a footnote to table 2
but no identification of allowable buffers/distances
between energized phase conductors at rated temperatures
and vegetation is discussed (this is left up the transmission
owners). Clarity is needed on this topic. Setting a finite
distance limit based on recognized standards, good science
and risk avoidance should be done for the industry. BPA has
previously made this comment during the drafting of the
Consideration of Comments on Successive Ballot of FAC-003-2
6
Voter
Entity
Segment
Vote
Comment
standard. It was not addressed then, nor has it been
addressed now.
Response: The SDT thanks you for your comments. The footnotes were changed to conform with your suggestions.
With respect to comments about the MVCD, R3 does not suggest the MVCD be used as a distance to manage vegetation. The
MVCD was established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line
within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD
In a performance based standard, requirements are focused on “what” needs to be accomplished to achieve desired results
and avoids prescriptive requirements of “how” to achieve that result. TO’s are in the best position to determine the
appropriate management approach suited for their system, rather than a “one size fits all” that could suppress best practices
for vegetation management.
Randall
McCamish
City of Vero
Beach
1
Negative
Vero Beach's concern is that entities may not be able prove
compliance with the standard. R1 and R2 say that: "Each
Transmission Owner shall manage vegetation to prevent
encroachments ...". If the requirements were interpreted
such that "manage" is the operative word, then, we are OK
because we can provide evidence of managing a program,
such as a vegetation management plan and evidence of
executing that plan (which does not align with the
Measures). However, that 1) would cause the standard to
not be performance based, and 2) it would be duplicative of
the other requirements of the standard.
If the requirements were interpreted with "prevent
encroachment" as the operative phrase (which would be an
Consideration of Comments on Successive Ballot of FAC-003-2
7
Voter
Entity
Segment
Vote
Comment
incorrect interpretation from the construct of the sentence)
there is no way to provide sufficient evidence that
encroachment was prevented during the audit-period. The
suggested Measures are not sufficient evidence to prove
compliance with that interpretation of the requirement. For
instance, most encroachments do not result in outages;
hence, lack of outages cannot prove that there were no
encroachments, and real time observations are insufficient
because it is a spot-check that does not cover the audit
period.
There are other weaknesses in the standard, such as R4
being un-measurable therefore unenforceable. However, in
the guilty until proven innocent paradigm we live in, FMPA's
primary concern is that industry could be put into a no-win
situation of not being able to prove compliance with the
standard if R1 and R2 are interpreted as "prevent
encroachment", and if R1 and R2 are interpreted as
"manage" then it is not a performance based standard as
advertised. Vero Beach suggests one of two approaches:
1. Performance based focused on preventing vegetation
related outages. For instance: "Each Transmission Owner
shall prevent vegetation related outages (except as noted in
Footnote 2) of any of its applicable line(s) ..." Evidence of
outages is practical to gather and provide, evidence of
encroachment is not.
2. Modify the standard to be similar to the currently
mandatory non-results based standard and focus on the
word "manage". This would essentially mean eliminating R1
Consideration of Comments on Successive Ballot of FAC-003-2
8
Voter
Entity
Segment
Vote
Comment
and R2 since the rest of the standard focuses on having a
plan and managing to that plan.
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Danny
McDaniel
Cleco Power
LLC
1
Negative
Cleco disagrees with the SDT revising the definition for
Right-of-Way (ROW). Right-of-Way is a term that has had a
consistent meaning throughout history. If NERC tries to
redefine the term, it will only add confusion because most
entities will not reference the NERC glossary for a term
which is widely used in the industry. In lieu of "Active
Transmission Line ROW", please use another term such as
Transmission Corridor. No assumptions would be made
when reading in the Standard the the Entity is to maintain
vegetation located within the Transmission Corridor. Since
the term is not commonly used, the NERC glossary would be
referenced.
Also, Cleco disagrees that an encroachment into the MCVD
that does not cause an outage should be considered noncompliant as stated in R1 and R2. The encroachment should
only be reportable similar to misoperations as is in the PRC004 standard.
Response: Thank you for your comments.
The existing ROW definition in the glossary was created by and for the FAC-003-1 and was moved there when that standard
was adopted. The definition includes a series of options that give the Transmission Owner latitude in establishing ROW width.
It does not require selecting a single method for its system. The term “blowout standard” is not capitalized and is not a defined
Consideration of Comments on Successive Ballot of FAC-003-2
9
Voter
Entity
Segment
Vote
Comment
term. This phrase in the definition allows a Transmission Owner to use its internal engineering standards or the general
engineering standards that were in effect when the line was constructed to determine the ROW width. The SDT has limited the
definition of Right-of-Way to a corridor of land with a defined width to operate a transmission line. This does not include
danger tree rights.
The definition of the MVCD is now added to this Standard. While use of the pre-2007 records is a compliance issue and is not in
the purview of the SDT, it is the intent of the language in the definition that you could use this information.
Regarding your second comment, R3 does not suggest the MVCD be used as a distance to manage vegetation. The MVCD was
established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line within its
rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD
Other related requirements of this “Defense in Depth” Standard serve to address any number of scenarios which may arise or
hinder the TO’s ability to always strictly adhere to the management approach(s) established within R3. Thus the other
requirements of this Standard provide the latitude for appropriate actions to remedy the condition without penalty. Further,
trees which have encroached inside the MVCD are evidence of a deficiency in vegetation maintenance.
Christopher
L de
Graffenried
Consolidated
Edison Co. of
New York
1
Affirmative
Reply to Question 5 on Comment Form: The added language
for the annual work plan percentage complete calculation is
shown in R7 not M7 as stated in the question. In the
Guideline and Technical Basis Section for Requirement R6,
there is a sample calculation shown for the amount of lines
the TO failed to inspect. An example should also be included
for Requirement R7 since there is some confusion regarding
how modifications to the work plan affect the calculation.
In the Lower VSL column for R7, it states that the TO failed
to complete up to 5% of its annual vegetation work plan
(including modifications if any). If a TO operates 100 lines
and submits a justified modification that affects 10 miles of
Consideration of Comments on Successive Ballot of FAC-003-2
10
Voter
Entity
Segment
Vote
Comment
lines, the total number of units in the final amended plan is
90 miles. When you read the VSL, it is somewhat confusing
since the information in parenthesis says that the
calculation 'includes' the modifications. Should it state
'excludes modifications if any' or the VSLs can simply be rewritten to state that ..The TO failed to complete up to x% of
the final amended plan.'
Also, the VSLs in R6 and R7 should be consistent with each
other: R6 says '...TO failed to inspect 5% or less.....' and R7
says '...TO failed to complete up to 5%....' They both should
use the same verbiage in each VSL whether it is 'x% or less'
or 'up to and including x%.'
Response: The SDT thanks you for your comments.
The percentage should be based on the plan as modified. The SDT has changed the language in the standard to reflect this
more clearly, and has modified the VSLs to be consistent as you have suggested.
Robert
Martinko
FirstEnergy
Energy
Delivery
1
Affirmative
FirstEnergy supports standard FAC-003-2 and would
appreciate consideration of our comments submitted
through the formal comment period.
Response: The SDT thanks you for your comments. Please see our consideration of your comments within the responses to
the formal comments.
Luther E.
Fair
Gainesville
Regional
Utilities
1
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
1. It would seem that the impetus for FAC003 is to eliminate
vegetation related outages within the rights-of-way as
defined and subject to the exclusions as stated in footnote
2. Thus the requirement is to manage the ROW to prevent
vegetation related sustained outages with the measure
being no outages. With grow-ins and fall-ins from within the
defined ROW being controllable factors.
11
Voter
Entity
Segment
Vote
Comment
2. Including encroachments leaves the door open for fines
to be imposed with no actual outage(s) having occurred.
This may be like being found guilty of a crime that has not
yet taken place.
3. Combine vegetation related sustained outages by “growins” and “blowing together of lines and vegetation located
inside the ROW” as one item as they are both consequences
of the growth of vegetation either vertically and
horizontally.
4. Leave vegetation related sustained outages by “fall-in” as
a standalone as this will be related to structural problems
occurring from a variety of sources.
5. Combine R3 and R7 to R1 (development and
implementation of a Transmission Vegetation Management
Plan which shall include documented maintenance
strategies or procedures or processes or specifications,
delineation of an annual work plan and completion of
same). Thus this would be the competency based
requirements as a program without execution is
meaningless.
6. R1 and R2 become R2 and R3.
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
Consideration of Comments on Successive Ballot of FAC-003-2
12
Voter
Entity
Segment
inspections in which clearances are evaluated.
Ted E
Hobson
JEA
1
Vote
Negative
Comment
Need to align the "measures" with the standard
requirement language and the performance-based
philosophy.
Response: The SDT thanks you for your comments. We are not quite clear as to what misalignment you refer to between the
standard language and the measures. The SDT went to great lengths to ensure continuity between the requirements and the
measures. While this standard was a first attempt at a "Results Based" approach, the SDT did have limitation in deciding what
could be excluded from the standard. This standard has a mixture of the three types of requirements that comprise a results
based approach: 1) Performance Based 2) Risk Based and 3) Competency Based. Having only performance-based requirements
would not have resulted in a comprehensive, proactive standard.
Michael
Gammon
Kansas City
Power & Light
Co.
1
Negative
The Standard lacks clarity regarding the facilities that are
subject to Requirement 7. It is important that a Standard be
clear and not introduce ambiguity or confusion. There are
several references throughout the Standard to "for all
applicable lines" and it should be made clear the work plan
is specific to "all applicable lines".
Response: The SDT thanks you for your comments. The team has made the appropriate modifications where necessary.
Stan T. Rzad
Keys Energy
Services
1
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
Concern is that entities may not be able prove compliance
with the standard. R1 and R2 say that: "Each Transmission
Owner shall manage vegetation to prevent encroachments
...". If the requirements were interpreted such that
"manage" is the operative word, then, we are OK because
we can provide evidence of managing a program, such as a
vegetation management plan and evidence of executing
that plan (which does not align with the Measures).
However, that 1) would cause the standard to not be
performance based, and 2) it would be duplicative of the
13
Voter
Entity
Segment
Vote
Comment
other requirements of the standard.
If the requirements were interpreted with "prevent
encroachment" as the operative phrase (which would be an
incorrect interpretation from the construct of the sentence)
there is no way to provide sufficient evidence that
encroachment was prevented during the audit-period. The
suggested Measures are not sufficient evidence to prove
compliance with that interpretation of the requirement. For
instance, most encroachments do not result in outages;
hence, lack of outages cannot prove that there were no
encroachments, and real time observations are insufficient
because it is a spot-check that does not cover the audit
period.
There are other weaknesses in the standard, such as R4
being un-measurable therefore unenforceable. However, in
the guilty until proven innocent paradigm we live in, FMPA's
primary concern is that industry could be put into a no-win
situation of not being able to prove compliance with the
standard if R1 and R2 are interpreted as "prevent
encroachment", and if R1 and R2 are interpreted as
"manage" then it is not a performance based standard as
advertised. One of two approaches are suggested:
Performance based focused on preventing vegetation related
outages. For instance: "Each Transmission Owner shall
prevent vegetation related outages (except as noted in
Footnote 2) of any of its applicable line(s) ..." Evidence of
outages is practical to gather and provide, evidence of
encroachment is not.
Modify the standard to be similar to the currently mandatory
Consideration of Comments on Successive Ballot of FAC-003-2
14
Voter
Entity
Segment
Vote
Comment
non-results based standard and focus on the word
"manage". This would essentially mean eliminating R1 and
R2 since the rest of the standard focuses on having a plan
and managing to that plan.
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Walt Gill
Lake Worth
Utilities
1
Negative
CLWU's concern is that entities may not be able prove
compliance with the standard. R1 and R2 say that: "Each
Transmission Owner shall manage vegetation to prevent
encroachments ...". If the requirements were interpreted
such that "manage" is the operative word, then, we are OK
because we can provide evidence of managing a program,
such as a vegetation management plan and evidence of
executing that plan (which does not align with the
Measures). However, that 1) would cause the standard to
not be performance based, and 2) it would be duplicative of
the other requirements of the standard.
If the requirements were interpreted with "prevent
encroachment" as the operative phrase (which would be an
incorrect interpretation from the construct of the sentence)
there is no way to provide sufficient evidence that
encroachment was prevented during the audit-period. The
suggested Measures are not sufficient evidence to prove
compliance with that interpretation of the requirement. For
instance, most encroachments do not result in outages;
hence, lack of outages cannot prove that there were no
Consideration of Comments on Successive Ballot of FAC-003-2
15
Voter
Entity
Segment
Vote
Comment
encroachments, and real time observations are insufficient
because it is a spot-check that does not cover the audit
period.
There are other weaknesses in the standard, such as R4
being un-measurable therefore unenforceable. However, in
the guilty until proven innocent paradigm we live in, FMPA's
primary concern is that industry could be put into a no-win
situation of not being able to prove compliance with the
standard if R1 and R2 are interpreted as "prevent
encroachment", and if R1 and R2 are interpreted as
"manage" then it is not a performance based standard as
advertised. CLWU suggests one of two approaches:
1. Performance based focused on preventing vegetation
related outages. For instance: "Each Transmission Owner
shall prevent vegetation related outages (except as noted in
Footnote 2) of any of its applicable line(s) ..." Evidence of
outages is practical to gather and provide, evidence of
encroachment is not.
2. Modify the standard to be similar to the currently
mandatory non-results based standard and focus on the
word "manage". This would essentially mean eliminating R1
and R2 since the rest of the standard focuses on having a
plan and managing to that plan..
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Consideration of Comments on Successive Ballot of FAC-003-2
16
Voter
Saurabh
Saksena
Entity
National Grid
Segment
1
Vote
Affirmative
Comment
The revised ROW definition emphasizes the ROW width
needed to operate the transmission line(s). It is National
Grid’s interpretation that the width established when the
line was constructed is the width to be maintained. This
width is documented in engineering drawings, per-2007
vegetation records or blow-out standards. This definition
does not imply that danger tree rights beyond the
constructed and maintained width are incorporated in the
definition; therefore fallins - from outside the ROW but
within an area with danger tree rights would not be
considered fallin-ins from within the ROW. National Grid
would like the SDT to comment on this interpretation in its
response to these comments.
Response: Your interpretation is consistent with the intent of the definition that the SDT provided. However the definition
includes a series of options that give the Transmission Owner latitude in establishing ROW width. It does not require selecting a
single method for its system. This phrase in the definition allows a TO to use its internal engineering standards or the general
engineering standards that were in effect when the line was constructed to determine the ROW width. The SDT has limited the
definition of Right-of-Way to a corridor of land with a defined width to operate a transmission line. This does not include
danger tree rights.
Michael T.
Quinn
Oncor Electric
Delivery
1
Affirmative
In footnote 2 (pg. 8) and 4 (page 10), the wording
“arboricultural activities or horticultural or agricultural
activities” should be deleted and replaced with “or removal
of, installation of, or digging around vegetation.”
Response: The SDT thanks you for your comments. The footnotes have been changed.
John C.
Collins
Platte River
Power
Authority
1
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
Vegetation Inspection: Is the intent of “... and those
vegetation conditions under the TO’s control” to clarify that
an entity must have ownership of the transmission line and
right-of-way in addition to maintenance or operational
responsibility (control), or something different? In situations
17
Voter
Entity
Segment
Vote
Comment
where a TO owns one circuit on a double circuit, but the
other circuit, facilities and ROW belong to another TO who
has maintenance, and vegetation management
responsibility, who would be responsible for violations? If
the definition was modified to allow both maintenance and
vegetation inspections to be performed concurrently, the
intent might be clearer if it read: “This may be combined
with other line inspections”, or “This may be combined with
a maintenance inspection” opposed to a general line
inspection.
R1 and R2: Does R1 correlate to facilities in 4.2.2. and 4.2.3.
(overhead transmission lines operated below 200 kV) and
R2 correlate to facilities in 4.2.1. (overhead transmission
lines operated at 200kV or higher)? It isn’t clear why the
two requirements are split. Could it be one requirement
which reads “...identified as a facility in Section 4.2”?
R4: Our current imminent threat procedure requires a call
to the Manager who confirms the existence of a vegetation
condition that is likely to cause a Fault at any moment prior
to notifying the control center. We assume notification,
without any intentional time delay, would take place after
managerial confirmation but feel like the enforcement
authorities could interpret this differently based on how it is
written in R4. If the intent of the requirement is how we
interpret it, the requirement might be clearer if it read:
After a Transmission Owner has confirmed a vegetation
condition likely to cause a Fault at any moment, they shall
notify the control center holding switching authority for the
associated applicable transmission line, without any
Consideration of Comments on Successive Ballot of FAC-003-2
18
Voter
Entity
Segment
Vote
Comment
intentional delay.
Response: The SDT thanks you for your comment. With regard to responsibility for a violation, the TO is the accountable party
even if it has an agreement with another TO to inspect and manage vegetation.
With regard to your suggestion in changing the definition of Vegetation Inspection, the SDT does not believe the proposed
changes are necessary for the definition to be clear.
With regard to R1 and R2, they applicability applies to 4.2.1 thru 4.2.3. The distinction between the requirement is R1 applies to
all lines designated as having an Interconnection Reliability Operating Limit (IROL) in the planning horizon by the Planning
Coordinator; or lines designated as Major Western Electricity Coordinating Council (WECC) transfer path(s).
With regard to your imminent threat procedure, the standard is not prescriptive to define a TO’s imminent threat procedure.
So, if your procedure includes managerial confirmation, then this would not be considered intentional delay.
Sammy
Roberts
Progress
Energy
Carolinas
1
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “or installation of."
Response: The SDT thanks you for your comments. The footnotes have been changed.
Laurie
Williams
Public Service
Company of
New Mexico
1
Negative
PNM is voting negative but offers the following comments
to improve the standard.
1. The last sentence of the Background on page 7 states:
Thus, this Standard’s emphasis is on vegetation grow-ins.
However, R1 says that we shall manage encroachments as
follows: R1. Each Transmission Owner shall manage
vegetation to prevent encroachment that could result in a
Sustained Outage encroachments of the types shown
Consideration of Comments on Successive Ballot of FAC-003-2
19
Voter
Entity
Segment
Vote
Comment
below, into the Minimum Vegetation Clearance Distance
(MVCD) of....... 2. An encroachment due to a fall-in from
inside the active transmission line Right-of-Way (ROW) that
caused a vegetation-related Sustained Outage, This seems
contradictory.
2. Fac-003-2 makes reference to FAC-014 and a “Planning
Coordinator” in section 4.2.2 of Applicability: pg 5 see
below:
4.2.2. Overhead transmission lines operated below 200kV
having been identified as included in the definition of an
Interconnection Reliability Operating Limit (IROL) under
NERC Standard FAC-014 by the Planning Coordinator.
In addition, on pg 8, R1 of FAC-003-2 makes reference to the
“planning coordinator” However, FAC-014 makes no
reference, or at least it is inconsistent, to a “Planning
Coordinator” See below:
Taken from FAC-014
4. Applicability
4.1. Reliability Coordinator
4.2. Planning Authority
4.3. Transmission Planner
4.4. Transmission Operator
The terminology and definitions seem to be inconsistent.
Consideration of Comments on Successive Ballot of FAC-003-2
20
Voter
Entity
Segment
Vote
Comment
3. R1 and R2 are the same requirements with different
applicabilities. R1 applies to lines that are connected to
WECC, IROL, etc. R2 applies to all other applicable lines that
are NOT an element of WECC or IROL. My Question is: If the
line is not part of WECC or IROL or any other connection
then, how is it applicable to the Standard?
4. R7 says the TO shall complete a %100 of annual plan but
allows for modifications that include:
Change in expected growth rate/ environmental factors
Major storms
Circumstances that are beyond the control of a Transmission
Owner5
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance
agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the
landowner
Funding adjustments (increase or decrease)
Emerging technologies
[VRF - Medium] [Time Horizon - Operations Planning]
The requirement says we shall complete a %100 of the
annual plan however, some of the modifications have
historically taken over a year to mitigate. SHALL should be
Consideration of Comments on Successive Ballot of FAC-003-2
21
Voter
Entity
Segment
Vote
Comment
replaced with SHOULD with acceptable modifications and
without compromising integrity of system.
Response: The SDT thanks you for your comments.
Item 1: It is intended that the Standard will cover any situation within the ROW that causes an encroachment into the MVCD
including fall-ins, grow-ins or blowing-together. The arrangement of the Violation Severity Levels for R1. and R2. emphasize
that a grow-in results in the greatest risk to a power system, and also is the most egregious and severe failure to meet the
intent of these requirements.
Item 2: The term Planning Authority (PA) included in FAC-014 was replaced by NERC in the functional model Version 5 with
Planning Coordinator. Where references to PA are included in legacy Standards, Planning Coordinator is now used as follows
Planning Coordinator (Planning Authority). Obviously, proposed new Standards or versions must use the currently accepted
terms.
Item 3: R1 and R2 are dealing with the differentiation between lines that fall into IROL/WECC Transfer Path definition and
those lines that do not. Keep in mind that this standard refers to all transmission lines over 200-kV.
Item 4: The SDT believes replacing the word “shall” with the word “should” in Requirement 7 changes the requirement to a
recommendation.
Pawel
Krupa
Seattle City
Light
1
Affirmative
The revisions to the proposed FAC-003-2 Standards
produced a better version through greater clarity,
appropriate pragmatism, and technical foundation; A few
good points that highlight this follow:
1. Definition of Terms Used in Standard: The revised
definition of Right-of-Way (ROW) establishes the width of
the corridor from a technical basis with the following
statement "The width of the corridor is established by
engineering or construction standards..."
2. Introduction, Applicability, Section 4.2 Facilities: Section
4.2.4 which pertains to substations clarifies that this
standard does not apply to applicable transmission lines,
inside the substation, just to "any portion of the span of the
Consideration of Comments on Successive Ballot of FAC-003-2
22
Voter
Entity
Segment
Vote
Comment
transmission line that is crossing the substation fence".
3. Requirements and Measures: Requirement 1 underscores
sensible purpose by replacing the wording of "preventing
outages from vegetation" to "manage vegetation to prevent
encroachments..."
4. Guideline and Technical Basis Section: Requirement 7
contains a great practicle reference explanation as it
pertains to the annual work plan. Requirement 7 explains:
..." the vegetation management approach should use the
full extent of the Transmission Owner's easement, fee
simple and other legal rights allowed. A comprehensive
approach that exercises the full extent of legal rights on the
ROW is superior to incremental management in the long
term because it reduces the overall potential for
encroachment, and it ensures that future planned work and
future planned inspection cycles are sufficient".
Response: The SDT thanks you for your comments.
William G.
Hutchison
Southern
Illinois Power
Coop.
1
Negative
I beleive that the reliability region should have the right to
exclude lines below 200KV. Not all lines above 100KV
negative impact the BES.
Response: The SDT thanks you for your comment. This issue is presently before FERC and NERC and is outside the scope of the
SDT.
Keith V
Carman
Tri-State G & T
Association,
Inc.
1
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “ installation of”.
23
Voter
Entity
Segment
Vote
Comment
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Brandy A
Dunn
Western Area
Power
Administration
1
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “ installation of”
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Gregory L
Pieper
Xcel Energy,
Inc.
1
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
Xcel Energy still believes the requirement in R6 that
mandates an annual inspection is an ineffective approach
and may actually go against the Commission’s
determination in FERC Order No. 693. The drafting team’s
response to our last round of comments on this issue was
that “...the SDT was directed by Order 693 to set a minimum
inspection criteria”. It is clear in Order 693 that the
Commission is not satisfied with allowing entities to choose
their own inspection cycles, as the standard currently
allows. However, we fail to see where the Commission
mandated a minimum inspection cycle to be uniformly
applied continent-wide. We urge the drafting team to revisit
paragraphs 719 through 721 of Order 693. According to
paragraph 721, the Commission recognizes that unique
intervals by region, “based on local factors”, are reasonable
and appropriate. By use of the plural term “cycles”, FERC
anticipates the resolution may include multiple inspection
cycles. Furthermore, in paragraph 719, FERC acknowledges
that a minimum inspection cycle may not be the only way to
address their concern. In fact, mandating an annual
inspection cycle may actually go against the Commission’s
guidance in paragraph 720. Here is an excerpt: “...the
24
Voter
Entity
Segment
Vote
Comment
Commission is dissuaded from requiring the ERO to create a
backstop inspection cycle at this time. Instead, the
Commission agrees that an entity’s vegetation management
program should be tailored to anticipated growth in the
region and take into account other environmental factors.
The goal is to assure that transmission owners conduct
inspections at reasonable intervals.”
As an alternative, we propose a mid-cycle inspection. A midcycle inspection is based on an interval that is justified with
data and technical expertise. A mid-cycle inspection would
still require entities to conduct inspections at a specified
interval, while allowing for differences based upon “physical
and geographic factors”. Not only would this approach fully
address the Commissions concerns, but it would take into
account the interests of stakeholders, landowners and ratepayers. We recognize that a mid-cycle inspection interval is
not as easy to audit as an annual requirement, but it is a far
more practical and cost-effective approach that, when
applied based on an entity’s expertise with its own facilities,
ensures reliability.
Response: The SDT thanks you for your comments. The SDT recognizes that a number of Transmission Owners in North
America may prefer to set their own inspection intervals. The SDT can also see attractiveness for a mid-cycle inspection
concept; however, this introduces new complexities in planning, documentation and auditing. Because there is substantial
industry support for an annual inspection interval the SDT believes that the industry is best served with this approach.
Mark B
Thompson
Alberta
Electric
System
Operator
2
Consideration of Comments on Successive Ballot of FAC-003-2
Abstain
Due to slow vegetation growth rates in many parts of
Alberta, not all transmission right-of-ways require annual
inspection as required in R6. TOs should be able to include
planned inspection cycles in their Transmission Vegetation
Management Plan.
25
Voter
Entity
Segment
Vote
Comment
Response: The SDT thanks you for your comments. In FERC Order 693, para. 721, FERC stated, “The Commission continues to
be concerned with leaving complete discretion to the transmission owners in determining inspection cycles, which limits the
effectiveness of the Reliability Standard.”
The SDT established an inspection cycle at least once per calendar year and with no more than 18 calendar months between
inspections on the same ROW. There was a survey of the industry in a previous request for comments to this standard. The
response to that survey is the basis for the use of the 1-year period. While there was a range of growth rates across the
continent, the SDT had sufficient feedback to recommend the 1-year cycle. The inspection also would cover inspecting for fallin threats. Please note that vegetation inspections can also be combined with other line inspections.
Alden Briggs
New
Brunswick
System
Operator
2
Affirmative
The term “encroachment” has to be defined, and the use of
that term and the clearances required clarification. The
Table listing the clearances also needed clarification.
Response: The SDT thanks you for your comment. The SDT endorses the standard dictionary definition of the term
“encroachment” and as such it does not require a NERC-specific definition. The use of encroachment regarding the clearance
table is explained in detail in the Technical Reference Document.”
Richard J.
Mandes
Alabama
Power
Company
3
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “ installation of”.
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Steven
Norris
APS
3
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
The objective, as written, is about outages that can lead to
cascading and not about reliability. Recommended change
to Standard Objective: To maintain a reliable electric
transmission system, implement a defense-in-depth
strategy to manage vegetation located on transmission
rights of way (ROW) and minimize encroachments from
vegetation located adjacent to the ROW.
26
Voter
Entity
Segment
Vote
Comment
Response: The SDT thanks you for your comment. With respect to the Purpose as written in the proposed standard, the
language clearly states “To improve the reliability of the electric Transmission system…”. The SDT made it a point to keep the
Purpose as concise as possible without getting into issues that are covered further in the body of the standard.
Rebecca
Berdahl
Bonneville
Power
Administration
3
Affirmative
In R1 and R2 and their associated VSLs, the SDT added the
phrase “in order of increasing severity” and added the
sentence, “The types of encroachments are listed in order
of increasing degrees of severity in non-compliant
performance as it relates to a failure of a TO’s vegetation
maintenance program.” to the Rationale boxes for R1/R2.
Do you agree? If answer is no, please explain.
BPA prefers the stratified levels of violation severity
presented in the table for R1 and R2.
Foot note # 2 on page 8 needs to be clarified with respect to
arboricultural activities or horticultural or agricultural
activities.
Foot note # 4 on page 12 needs to be clarified with respect
to arboricultural activities or horticultural or agricultural
activities.
In response to comments received that requirement R3 is
unclear with respect to intent, the SDT added “maintenance
strategies.” Do you agree this clarifies the intent? If answer
is no, please offer alternative language.
The TO procedures / policies and specifications shall
demonstrate the TO’s ability to manage the system at all
rated conditions to maintain reliability. BPA believes that
the intent is clear, but the fundamental approach of using
the MVCD (table 2) to manage a vegetation program is still
Consideration of Comments on Successive Ballot of FAC-003-2
27
Voter
Entity
Segment
Vote
Comment
problematic. These values are flashover distances and are
way too close. This is acknowledged in a footnote to table 2
but no identification of allowable buffers/distances
between energized phase conductors at rated temperatures
and vegetation is discussed (this is left up the transmission
owners). Clarity is needed on this topic. Setting a finite
distance limit based on recognized standards, good science
and risk avoidance should be done for the industry. BPA has
previously made this comment during the drafting of the
standard. It was not addressed then, nor has it been
addressed now.
Response: The SDT thanks you for your comments.
Footnotes #2 and #4 have been changed to reflect your suggestion to clarify arboricultural or horticultural or agricultural
activities.
With respect to comments about the MVCD, R3 does not suggest the MVCD be used as a distance to manage vegetation. The
MVCD was established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line
within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD
In a performance based standard, requirements are focused on “what” needs to be accomplished to achieve desired results
and avoids prescriptive requirements of “how” to achieve that result. TO’s are in the best position to determine the
appropriate management approach suited for their system, rather than a “one size fits all” or “fill in the blank” requirement
that could suppress best practices for vegetation management.
Matt
Culverhouse
City of Bartow,
Florida
3
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
The suggested Measures are not sufficient evidence to
prove compliance with that interpretation of the
requirement. For instance, most encroachments do not
result in outages; hence, lack of outages cannot prove that
there were no encroachments, and real time observations
28
Voter
Entity
Segment
Vote
Comment
are insufficient because it is a spot-check that does not
cover the audit period.
There are other weaknesses in the standard, such as R4
being un-measurable therefore unenforceable. However, in
the guilty until proven innocent paradigm we live in, FMPA's
primary concern is that industry could be put into a no-win
situation of not being able to prove compliance with the
standard if R1 and R2 are interpreted as "prevent
encroachment", and if R1 and R2 are interpreted as
"manage" then it is not a performance based standard as
advertised.
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated. Also please reference footnote 3.
Bryan Y
Harper
Cleco Utility
Group
3
Negative
Cleco disagrees with the SDT revising the definition for
Right-of-Way (ROW). Right-of-Way is a term that has had a
consistent meaning throughout history. If NERC tries to
redefine the term, it will only add confusion because most
entities will not reference the NERC glossary for a term
which is widely used in the industry. In lieu of "Active
Transmission Line ROW", please use another term such as
Transmission Corridor. No assumptions would be made
when reading in the Standard the the Entity is to maintain
vegetation located within the Transmission Corridor. Since
the term is not commonly used, the NERC glossary would be
referenced.
Also, Cleco disagrees that an encroachment into the MCVD
Consideration of Comments on Successive Ballot of FAC-003-2
29
Voter
Entity
Segment
Vote
Comment
that does not cause an outage should be considered noncompliant as stated in R1 and R2. The encroachment should
only be reportable similar to misoperations as is in the PRC004 standard.
Response: Thanks for your comments. The existing ROW definition in the glossary was created by and for the FAC-003-1 and
was moved there when that standard was adopted. The definition includes a series of options that give the Transmission
Owner latitude in establishing ROW width. It does not require selecting a single method for its system. The term blowout
standard is not capitalized and is not a defined term. This phrase in the definition allows a Transmission Owner to use its
internal engineering standards or the general engineering standards that were in effect when the line was constructed to
determine the ROW width. The SDT has limited the definition of Right-of-Way to a corridor of land with a defined width to
operate a transmission line. This does not include danger tree rights. The definition of the MVCD is now added to this Standard.
While use of the pre-2007 records is a compliance issue and is not in the purview of the SDT, it is the intent of the language in
the definition that you could use this information.
Regarding your second comment, the MVCD was established as a beginning of a series of “building blocks” for a program to
ensure reliability of a Transmission line within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD.
Other related requirements of this “Defense in Depth” Standard serve to address any number of scenarios which may arise or
hinder the TO’s ability to always strictly adhere to the management approach(s) established within R3. Thus the other
requirements of this Standard provide the latitude for appropriate actions to remedy the condition without penalty. Further,
trees which have encroached inside the MVCD are evidence of a deficiency in vegetation maintenance.
Peter T Yost
Consolidated
Edison Co. of
New York
3
Affirmative
Reply to Question 5 on Comment Form: The added language
for the annual work plan percentage complete calculation is
shown in R7 not M7 as stated in the question.
In the Guideline and Technical Basis Section for
Requirement R6, there is a sample calculation shown for the
amount of lines the TO failed to inspect. An example should
Consideration of Comments on Successive Ballot of FAC-003-2
30
Voter
Entity
Segment
Vote
Comment
also be included for Requirement R7 since there is some
confusion regarding how modifications to the work plan
affect the calculation. In the Lower VSL column for R7, it
states that the TO failed to complete up to 5% of its annual
vegetation work plan (including modifications if any). If a TO
operates 100 lines and submits a justified modification that
affects 10 miles of lines, the total number of units in the
final amended plan is 90 miles. When you read the VSL, it is
somewhat confusing since the information in parenthesis
says that the calculation 'includes' the modifications. Should
it state 'excludes modifications if any' or the VSLs can simply
be re-written to state that ..The TO failed to complete up to
x% of the final amended plan.'
Also, the VSLs in R6 and R7 should be consistent with each
other: R6 says '...TO failed to inspect 5% or less.....' and R7
says '...TO failed to complete up to 5%....' They both should
use the same verbiage in each VSL whether it is 'x% or less'
or 'up to and including x%.'
Response: The SDT thanks you for your comments. Your correction is accurate.
The percentage should be based on the plan as modified. The SDT has changed the language in the standard to reflect this
more clearly.
The VSLs have been modified to be consistent as suggested.
David A.
Lapinski
Consumers
Energy
3
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
Comments on FAC-003-2 February 25, 2011
Consumers Energy submits the following comments on FAC003-2: In general we are please with FAC-003-2 and the
many clarifications that the STD has made in this version of
the standard. However, we do have one major
disagreement with the STD and cannot support this
standard as drafted.
31
Voter
Entity
Segment
Vote
Comment
We disagree with the use of the Minimum Vegetation
Clearance Distance (MVCD) developed by the drafting team
for Requirements R1 and R2. These distances are not the
design distances used for designing and constructing
transmission facilities as stated in the document for
minimum distances between conductors and grounded
objects. The proposed Table 2 provides a distance of 3.12
feet as the acceptable distance for an alternate current
345kV line at sea level. This distance is considerably less
than the distance used for line design to separate the
grounded tower structure from the energized conductor. If
the distance in Table 2 is acceptable to prevent energized
portions of a transmission line from grounding to a tree why
then is this distance not the design criteria used for tower
design to prevent flashover from conductor to tower? The
STD needs to explain why a ground tree should have a
different standard that a grounded steel tower or wood
pole structure.
The STD erroneously viewed the possibility of transient over
voltage as only occurring during re-energizing and not from
natural events such as a lightning strike that can occur and
does occur to energized operating lines. Secondly, the
proposed distances in Table 2 are considerably less than the
distances specified in OSHA requirements for air gap
clearance required by tree workers to safely remove trees
or limbs from conductors energized at the voltages
specified. A transmission owner/operator could let a tree
grow to within 3.5 feet of a 345 kV line and not be in
violation of this proposed standard. To remove the tree, the
Consideration of Comments on Successive Ballot of FAC-003-2
32
Voter
Entity
Segment
Vote
Comment
line would have to be de-energized, tagged, tested deenergized, and grounded. Working clearance would have to
be established by the operating entity and then the tree
crew could remove the tree. The net result is the loss of the
capacity of the line because an outage was forced on the
line in order to remove the tree that did not trigger a
violation of FAC-003-2. This situation, in our opinion, is a
violation of the intent of the standard, which is to ensure
the continued operation of the line. Therefore, the
minimum distance any tree should be able to approach a
conductor is more than the minimum requirement for air
gap distance between the tree and conductor as required by
OSHA worker standards. The STD did not like referring to
another standard to provide the distance requirements for
R1 and R2. This can be alleviated by putting in a table with
the IEEE 516 distances but not reference it as the IEEE 516
standard. The distances provided in the current draft do not
adequately provide or ensure the continued safe operation
of the transmission facilities in the United States and the
reasoning for the distances provided is unfounded and not
based on current design practices.
Response: The SDT thanks you for your comments. You are correct that these distances do not represent complete design
specifications for towers, nor define and describe safe worker approach distances. These practices are correctly specified in the
other standards you referenced. The SDT feels the standard is clear in that regard. The footnote associated with the Table 2
distances clearly states that these are only distances to prevent flashover under appropriate conditions. The SDT would also
like to point out that the transient overvoltage factors used to derive these distances are the maximums normally seen with a
transmission line in steady state service. Thus, a tower design would have to account for the larger overvoltage factors that are
possible while taking lines out of service.
As has been stated before, these distances were derived using a known set of line design equations and only represent
distances that will prevent spark-over from the transmission line to a grounded object. These are not distances to be managed
to – they have been established as a beginning of a series of “building blocks” for a program to ensure reliability of a
Consideration of Comments on Successive Ballot of FAC-003-2
33
Voter
Entity
Segment
Vote
Comment
Transmission line within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner’ consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD.
These distances are smaller than safety standard distances that have many other factors involved in the determination, such as
inadvertent human movement and larger safety factors. In regard to the over-voltages caused by lightning, even the maximum
overvoltage factors contained in the IEEE-516 tables do not account for these.
Russell A
Noble
Cowlitz
County PUD
3
Negative
Referring back to Cowlitz’ negative vote made on the 7/919/2010 ballot, Cowlitz tried to convey the problem that the
statement in R4 “without intentional time delay” will
require subjective judgment on the part of the auditor. In
other words, maintaining equal auditing standard
throughout the interconnection will be impossible with this
verbiage in a requirement. Cowlitz agrees with the SDT that
establishing an equitable time frame is very difficult (it may
be impossible!); however leaving it to the judgment of the
auditor to determine whether an intentional delay was
made is most disagreeable. Cowlitz respectfully points out
that the SDT did not adequately address the subjective
nature the auditor is forced into with this requirement. If
establishing “[t]he time required by the to report an issue is
subject to many variables...” and “[f]or this reason it is
difficult to establish a time period which would fairly apply
to all TO’s,” how does leaving this to the auditor to decide
going to make it any better?
Response: The SDT believes that it was not prudent to suggest a quantitative time element for notification in R4. The technical
reference offers examples of acceptable unintentional delays for your review. The SDT notes that this language is already
embodied in at least one other FERC-approved, in-force Standard.
Consideration of Comments on Successive Ballot of FAC-003-2
34
Voter
Kevin
Querry
Entity
FirstEnergy
Solutions
Segment
3
Vote
Affirmative
Comment
FirstEnergy supports standard FAC-003-2 and would
appreciate consideration of our comments submitted
through the formal comment period.
Response: The SDT thanks you for your comments. Please see our consideration of your comments within the responses to
the formal comments.
Lee
Schuster
Florida Power
Corporation
3
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “installation of."
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Anthony L
Wilson
Georgia Power
Company
3
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “ installation of”.
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Charles
Locke
Kansas City
Power & Light
Co.
3
Negative
The Standard lacks clarity regarding the facilities that are
subject to Requirement 7. It is important that a Standard be
clear and not introduce ambiguity or confusion. There are
several references throughout the Standard to "for all
applicable lines" and it should be made clear the work plan
is specific to "all applicable lines".
Response: The SDT thanks you for your comments. The team has made the appropriate modifications where necessary.
Mace
Hunter
Lakeland
Electric
3
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
R1. Each Transmission Owner shall manage vegetation to
prevent encroachments of the types shown below, -----------35
Voter
Entity
Segment
Vote
Comment
---- and all Rated Electrical Operating Conditions.2 1. An
encroachment into the MVCD as shown in FAC-003-Table 2,
observed in Real-time, absent a Sustained Outage, that is
not corrected within 5 working days of discovery, Make the
same change to R2 Type 1 encroachment and reflect the
changes in Table 1. Rational: This condition would enable a
entity to discover an encroachment and clear it without
having to self report a possible violation as long as the
conditions was corrected within 5 working days. The change
should encourage extra inspections for problem areas more
often than annually as required in R6. There should be no
negative consequences for diligent inspection of lines as
long as the problem is clear with a defined time such as 5 or
10 working days.
Response: The SDT thanks you for your comment. As a general rule, a revised standard should not be less stringent than the
existing standard it replaces. In the existing standard, a violation occurs when the encroachment occurs. A ‘find and fix’ of five
days would be viewed as a lowering of the level of required performance established by the current standard.
Bruce
Merrill
Lincoln
Electric
System
3
Affirmative
While supportive of the drafting team’s efforts, LES believes
a change is warranted in Footnote 2 and Footnote 4 to
remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace with the
term “installation of”. As currently drafted, the wording
could potentially be construed to mean that the TO would
or could be constrained or refused permission to prune and
remove any and all vegetation in the ROW in accordance
with the full legal rights of the ROW agreement(s).
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Don Horsley
Mississippi
Power
3
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
36
Voter
Entity
Segment
Vote
Comment
horticultural or agricultural activities” and replace it with
the term “ installation of”.
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Terry L
Baker
Platte River
Power
Authority
3
Negative
FAC-003-2 Comments Vegetation Inspection: Is the intent of
“... and those vegetation conditions under the TO’s control”
to clarify that an entity must have ownership of the
transmission line and right-of-way in addition to
maintenance or operational responsibility (control), or
something different? In situations where a TO owns one
circuit on a double circuit, but the other circuit, facilities and
ROW belong to another TO who has maintenance, and
vegetation management responsibility, who would be
responsible for violations?
If the definition was modified to allow both maintenance
and vegetation inspections to be performed concurrently,
the intent might be clearer if it read: “This may be combined
with other line inspections”, or “This may be combined with
a maintenance inspection” opposed to a general line
inspection.
R1 and R2: Does R1 correlate to facilities in 4.2.2. and 4.2.3.
(overhead transmission lines operated below 200 kV) and
R2 correlate to facilities in 4.2.1. (overhead transmission
lines operated at 200kV or higher)? It isn’t clear why the
two requirements are split. Could it be one requirement
which reads “...identified as a facility in Section 4.2”?
R4: Our current imminent threat procedure requires a call
Consideration of Comments on Successive Ballot of FAC-003-2
37
Voter
Entity
Segment
Vote
Comment
to the Manager who confirms the existence of a vegetation
condition that is likely to cause a Fault at any moment prior
to notifying the control center. We assume notification,
without any intentional time delay, would take place after
managerial confirmation but feel like the enforcement
authorities could interpret this differently based on how it is
written in R4. If the intent of the requirement is how we
interpret it, the requirement might be clearer if it read:
After a Transmission Owner has confirmed a vegetation
condition likely to cause a Fault at any moment, they shall
notify the control center holding switching authority for the
associated applicable transmission line, without any
intentional delay.
Response: The SDT thanks you for your comment. With regard to responsibility for a violation, the TO is the accountable party
even if it has an agreement with another TO to inspect and manage vegetation.
With regard to your suggestion in changing the definition of Vegetation Inspection, the SDT does not believe the proposed
changes are necessary for the definition to be clear.
With regard to R1 and R2, they applicability applies to 4.2.1 thru 4.2.3. The distinction between the requirement is R1 applies to
all lines designated as having an Interconnection Reliability Operating Limit (IROL) in the planning horizon by the Planning
Coordinator; or lines designated as Major Western Electricity Coordinating Council (WECC) transfer path(s).
With regard to your imminent threat procedure, the standard is not prescriptive to define a TO’s imminent threat procedure.
So, if your procedure includes managerial confirmation, then this would not be considered intentional delay.
Dana
Wheelock
Seattle City
Light
3
Affirmative
The revisions to the proposed FAC-003-2 Standards
produced a better version through greater clarity,
appropriate pragmatism, and technical foundation; A few
good points that highlight this follow:
1. Definition of Terms Used in Standard: The revised
definition of Right-of-Way (ROW) establishes the width of
the corridor from a technical basis with the following
Consideration of Comments on Successive Ballot of FAC-003-2
38
Voter
Entity
Segment
Vote
Comment
statement "The width of the corridor is established by
engineering or construction standards..."
2. Introduction, Applicability, Section 4.2 Facilities: Section
4.2.4 which pertains to substations clarifies that this
standard does not apply to applicable transmission lines,
inside the substation, just to "any portion of the span of the
transmission line that is crossing the substation fence".
3. Requirements and Measures: Requirement 1 underscores
sensible purpose by replacing the wording of "preventing
outages from vegetation" to "manage vegetation to prevent
encroachments..."
4. Guideline and Technical Basis Section: Requirement 7
contains a great practicle reference explanation as it
pertains to the annual work plan. Requirement 7 explains:
..." the vegetation management approach should use the
full extent of the Transmission Owner's easement, fee
simple and other legal rights allowed. A comprehensive
approach that exercises the full extent of legal rights on the
ROW is superior to incremental management in the long
term because it reduces the overall potential for
encroachment, and it ensures that future planned work and
future planned inspection cycles are sufficient".
Response: The SDT thanks you for your comments.
Michael
Ibold
Xcel Energy,
Inc.
3
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
Xcel Energy still believes the requirement in R6 that
mandates an annual inspection is an ineffective approach
and may actually go against the Commission’s
39
Voter
Entity
Segment
Vote
Comment
determination in FERC Order No. 693. The drafting team’s
response to our last round of comments on this issue was
that “...the SDT was directed by Order 693 to set a minimum
inspection criteria”. It is clear in Order 693 that the
Commission is not satisfied with allowing entities to choose
their own inspection cycles, as the standard currently
allows. However, we fail to see where the Commission
mandated a minimum inspection cycle to be uniformly
applied continent-wide. We urge the drafting team to revisit
paragraphs 719 through 721 of Order 693. According to
paragraph 721, the Commission recognizes that unique
intervals by region, “based on local factors”, are reasonable
and appropriate. By use of the plural term “cycles”, FERC
anticipates the resolution may include multiple inspection
cycles. Furthermore, in paragraph 719, FERC acknowledges
that a minimum inspection cycle may not be the only way to
address their concern. In fact, mandating an annual
inspection cycle may actually go against the Commission’s
guidance in paragraph 720. Here is an excerpt: “...the
Commission is dissuaded from requiring the ERO to create a
backstop inspection cycle at this time. Instead, the
Commission agrees that an entity’s vegetation management
program should be tailored to anticipated growth in the
region and take into account other environmental factors.
The goal is to assure that transmission owners conduct
inspections at reasonable intervals.”
As an alternative, we propose a mid-cycle inspection. A midcycle inspection is based on an interval that is justified with
data and technical expertise. A mid-cycle inspection would
still require entities to conduct inspections at a specified
interval, while allowing for differences based upon “physical
Consideration of Comments on Successive Ballot of FAC-003-2
40
Voter
Entity
Segment
Vote
Comment
and geographic factors”. Not only would this approach fully
address the Commissions concerns, but it would take into
account the interests of stakeholders, landowners and ratepayers. We recognize that a mid-cycle inspection interval is
not as easy to audit as an annual requirement, but it is a far
more practical and cost-effective approach that, when
applied based on an entity’s expertise with its own facilities,
ensures reliability.
Response: The SDT thanks you for your comments. The SDT recognizes that a number of Transmission Owners in North
America may prefer to set their own inspection intervals. The SDT can also see attractiveness for a mid-cycle inspection
concept; however, this introduces new complexities in planning, documentation and auditing. Because there is substantial
industry support for an annual inspection interval the SDT believes that the industry is best served with this approach.
Rick Syring
Cowlitz
County PUD
4
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
Referring back to Cowlitz’ negative vote made on the 7/919/2010 ballot, Cowlitz tried to convey the problem that the
statement in R4 “without intentional time delay” will
require subjective judgment on the part of the auditor. In
other words, maintaining equal auditing standard
throughout the interconnection will be impossible with this
verbiage in a requirement. Cowlitz agrees with the SDT that
establishing an equitable time frame is very difficult (it may
be impossible!); however leaving it to the judgment of the
auditor to determine whether an intentional delay was
made is most disagreeable. Cowlitz respectfully points out
that the SDT did not adequately address the subjective
nature the auditor is forced into with this requirement. If
“[t]he time required by the entity to report an issue is
subject to many variables...” and “[f]or this reason it is
difficult to establish a time period which would fairly apply
to all TO’s,” how does leaving this to the auditor to decide
going to make it any better? You will be forcing the audited
entity to "prove the negative."
41
Voter
Entity
Segment
Vote
Comment
Response: The SDT believes that it was not prudent to suggest a quantitative time element for notification in R4. The technical
reference offers examples of acceptable unintentional delays for your review. The SDT notes that this language is already
embodied in at least one other FERC-approved, in-force Standard.
Frank
Gaffney
Florida
Municipal
Power Agency
4
Negative
R1 and R2 requirement reads: "Each Transmission Owner
shall manage to prevent encroachment ....". The results of
manage would be invoices of tree trimming actually
performed, documentation of a vegetation management
program that would be managed to, etc. However, the
Measures proposed are all actual outages which are neither
evidence of management nor evidence of encroachment
since there can be encroachment without an outage, and in
fact, many if not most encroachments do not result in
outages. Hence, the Measures are inconsistent with the
requirements.
Further, there is ambiguity of the action required in
requirements R1 and R2 - e.g., do entities need evidence
that they: 1) "manage", or 2) "prevent encroachment"; or 3)
as implied by the Measures, prevent vegetation related
outages?. In other words, what needs to be proven through
evidence? Certainly the third, prevent vegetation related
outages, is not in the Requirement; yet, that us what is
proposed for the Measures, highlighting the inconsistency
between Requirements and Measures. But, how would the
ambiguity between "manage" and "prevent encroachment"
be resolved? One auditor could interpret that the
requirement is to "manage" and accept a vegetation
management program and plan and proof that the plan was
executed as appropriate evidence. Another auditor could
interpret that "prevent" is the key word and look for
evidence proving that there was never a vegetation
Consideration of Comments on Successive Ballot of FAC-003-2
42
Voter
Entity
Segment
Vote
Comment
encroachment. How would evidence be produced to
provide the auditor that vegetation never encroached?
Would video cameras and other surveillance measures need
to operate 24 hours a day? Would we cause an entity to
survey the lines periodically? One can easily see that
"prevent encroachment" is inappropriate here since it is
infeasible to create evidence of compliance.
FMPA suggests one of two approaches:
Eliminate the word manage, but do not focus on
encroachment and instead focus on outages. For instance:
"Each Transmission Owner shall prevent vegetation related
outages (except as noted in Footnote 2) of any of its
applicable line(s) ..." Evidence of outages is practical to
gather and provide, evidence of encroachment is not.
Focus on the word "manage", similar to the existing FAC003 standard, and move R3 to a new R1 to develop a
management plan, and then the existing R1 and R2 become
R2 an R3 and require execution of that plan in the words of
R7, which would in turn enables elimination of R7.
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Thomas W.
Richards
Fort Pierce
Utilities
4
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
R1 and R2 requirement reads: "Each Transmission Owner
shall manage to prevent encroachment ....". The results of
43
Voter
Entity
Authority
Segment
Vote
Comment
manage would be invoices of tree trimming actually
performed, documentation of a vegetation management
program that would be managed to, etc. However, the
Measures proposed are all actual outages which are neither
evidence of management nor evidence of encroachment
since there can be encroachment without an outage, and in
fact, many if not most encroachments do not result in
outages. Hence, the Measures are inconsistent with the
requirements.
Further, there is ambiguity of the action required in
requirements R1 and R2 - e.g., do entities need evidence
that they: 1) "manage", or 2) "prevent encroachment"; or 3)
as implied by the Measures, prevent vegetation related
outages?. In other words, what needs to be proven through
evidence? Certainly the third, prevent vegetation related
outages, is not in the Requirement; yet, that us what is
proposed for the Measures, highlighting the inconsistency
between Requirements and Measures. But, how would the
ambiguity between "manage" and "prevent encroachment"
be resolved? One auditor could interpret that the
requirement is to "manage" and accept a vegetation
management program and plan and proof that the plan was
executed as appropriate evidence. Another auditor could
interpret that "prevent" is the key word and look for
evidence proving that there was never a vegetation
encroachment. How would evidence be produced to
provide the auditor that vegetation never encroached?
Would video cameras and other surveillance measures need
to operate 24 hours a day? Would we cause an entity to
survey the lines periodically? One can easily see that
"prevent encroachment" is inappropriate here since it is
Consideration of Comments on Successive Ballot of FAC-003-2
44
Voter
Entity
Segment
Vote
Comment
infeasible to create evidence of compliance.
FPUA suggests one of two approaches:
1. Eliminate the word manage, but do not focus on
encroachment and instead focus on outages. For instance:
"Each Transmission Owner shall prevent vegetation related
outages (except as noted in Footnote 2) of any of its
applicable line(s) ..." Evidence of outages is practical to
gather and provide, evidence of encroachment is not.
2. Focus on the word "manage", similar to the existing FAC003 standard, and move R3 to a new R1 to develop a
management plan, and then the existing R1 and R2 become
R2 an R3 and require execution of that plan in the words of
R7, which would in turn enables elimination of R7.
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Joseph G.
DePoorter
Madison Gas
and Electric
Co.
4
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
“While supportive of the drafting team’s efforts, The MGE
believes a change is warranted in Footnote 2 and Footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace with the
term “installation of”. As currently drafted, the wording
could potentially be construed to mean that the TO would
or could be constrained or refused permission to prune and
remove any and all vegetation in the ROW in accordance
45
Voter
Entity
Segment
Vote
Comment
with the full legal rights of the ROW agreement(s).”
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Douglas
Hohlbaugh
Ohio Edison
Company
4
Affirmative
FirstEnergy supports standard FAC-003-2 and would
appreciate consideration of our comments submitted
through the formal comment period.
Response: The SDT thanks you for your comments. Please see our consideration of your comments within the responses to
the formal comments.
Hao Li
Seattle City
Light
4
Affirmative
The revisions to the proposed FAC-003-2 Standards
produced a better version through greater clarity,
appropriate pragmatism, and technical foundation; A few
good points that highlight this follow:
1. Definition of Terms Used in Standard: The revised
definition of Right-of-Way (ROW) establishes the width of
the corridor from a technical basis with the following
statement "The width of the corridor is established by
engineering or construction standards..."
2. Introduction, Applicability, Section 4.2 Facilities: Section
4.2.4 which pertains to substations clarifies that this
standard does not apply to applicable transmission lines,
inside the substation, just to "any portion of the span of the
transmission line that is crossing the substation fence".
3. Requirements and Measures: Requirement 1 underscores
sensible purpose by replacing the wording of "preventing
outages from vegetation" to "manage vegetation to prevent
encroachments..."
Consideration of Comments on Successive Ballot of FAC-003-2
46
Voter
Entity
Segment
Vote
Comment
4. Guideline and Technical Basis Section: Requirement 7
contains a great practicle reference explanation as it
pertains to the annual work plan. Requirement 7 explains:
..." the vegetation management approach should use the
full extent of the Transmission Owner's easement, fee
simple and other legal rights allowed. A comprehensive
approach that exercises the full extent of legal rights on the
ROW is superior to incremental management in the long
term because it reduces the overall potential for
encroachment, and it ensures that future planned work and
future planned inspection cycles are sufficient".
Response: The SDT thanks you for your comments.
Brock
Ondayko
AEP Service
Corp.
5
Affirmative
American Electric Power believes that the phrase
"arboricultural activities or horticultural or agricultural
activities" was mistakenly introduced into Footnotes 2 and
4, and should be deleted from both footnotes. If the phrase
remains in the Standard, it may empower orchard growers,
landowners and others to plant trees on the right of way
and challenge Transmission Owners' rights to perform
maintenance on the presumption that the standard will
exempt the TO from violating the outage or encroachment
requirements.
For increased clarity, AEP offers the following change to the
second paragraph of M1, as well as the second paragraph of
M2. The original text “If a later confirmation of a Fault by
the Transmission Owner shows that a vegetation
encroachment within the MVCD has occurred from
vegetation within the ROW, this shall be considered the
Consideration of Comments on Successive Ballot of FAC-003-2
47
Voter
Entity
Segment
Vote
Comment
equivalent of a Real-time observation” should be replaced
with “If a later confirmation of a Fault by the Transmission
Owner shows that a vegetation encroachment within the
MVCD has occurred from vegetation growing into or
blowing together with the conductor within the ROW, this
shall be considered the equivalent of a Real-time
observation. A brief encroachment caused by falling
vegetation passing through the MVCD is not considered an
encroachment in this requirement”.
Response: Thanks you for your comments. The SDT made suggested changes.
Regarding the issue of fall-ins, the SDT is sympathetic to your concern. In fact, the SDT had originally crafted language similar to
that which you suggested. However, due to concerns expressed by regulators and others, the exemption for encroachment
violations due to falling vegetation from inside the right of way was removed.
Francis J.
Halpin
Bonneville
Power
Administration
5
Affirmative
In R1 and R2 and their associated VSLs, the SDT added the
phrase “in order of increasing severity” and added the
sentence, “The types of encroachments are listed in order
of increasing degrees of severity in non-compliant
performance as it relates to a failure of a TO’s vegetation
maintenance program.” to the Rationale boxes for R1/R2.
Do you agree? If answer is no, please explain.
BPA prefers the stratified levels of violation severity
presented in the table for R1 and R2.
Foot note # 2 on page 8 needs to be clarified with respect to
arboricultural activities or horticultural or agricultural
activities.
Foot note # 4 on page 12 needs to be clarified with respect
to arboricultural activities or horticultural or agricultural
activities.
Consideration of Comments on Successive Ballot of FAC-003-2
48
Voter
Entity
Segment
Vote
Comment
In response to comments received that requirement R3 is
unclear with respect to intent, the SDT added “maintenance
strategies.” Do you agree this clarifies the intent? If answer
is no, please offer alternative language. The TO procedures /
policies and specifications shall demonstrate the TO’s ability
to manage the system at all rated conditions to maintain
reliability.
BPA believes that the intent is clear, but the fundamental
approach of using the MVCD (table 2) to manage a
vegetation program is still problematic. These values are
flashover distances and are way too close. This is
acknowledged in a footnote to table 2 but no identification
of allowable buffers/distances between energized phase
conductors at rated temperatures and vegetation is
discussed (this is left up the transmission owners). Clarity is
needed on this topic. Setting a finite distance limit based on
recognized standards, good science and risk avoidance
should be done for the industry. BPA has previously made
this comment during the drafting of the standard. It was not
addressed then, nor has it been addressed now.
Response: The SDT thanks you for your comments. The footnotes were changed to conform with your suggestions.
With respect to comments about the MVCD, R3 does not suggest the MVCD be used as a distance to manage vegetation. The
MVCD was established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line
within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD distances.
Consideration of Comments on Successive Ballot of FAC-003-2
49
Voter
Entity
Segment
Vote
Comment
In a performance based standard, requirements are focused on “what” needs to be accomplished to achieve desired results
and avoids prescriptive requirements of “how” to achieve that result. TO’s are in the best position to determine the
appropriate management approach suited for their system rather than a “one size fits all” or “fill in the blanks” requirements
that could suppress best practices for vegetation management.
Wilket
(Jack) Ng
Consolidated
Edison Co. of
New York
5
Affirmative
Reply to Question 5 on Comment Form: The added language
for the annual work plan percentage complete calculation is
shown in R7 not M7 as stated in the question. In the
Guideline and Technical Basis Section for Requirement R6,
there is a sample calculation shown for the amount of lines
the TO failed to inspect. An example should also be included
for Requirement R7 since there is some confusion regarding
how modifications to the work plan affect the calculation. In
the Lower VSL column for R7, it states that the TO failed to
complete up to 5% of its annual vegetation work plan
(including modifications if any). If a TO operates 100 lines
and submits a justified modification that affects 10 miles of
lines, the total number of units in the final amended plan is
90 miles. When you read the VSL, it is somewhat confusing
since the information in parenthesis says that the
calculation 'includes' the modifications. Should it state
'excludes modifications if any' or the VSLs can simply be rewritten to state that ..The TO failed to complete up to x% of
the final amended plan.'
Also, the VSLs in R6 and R7 should be consistent with each
other: R6 says '...TO failed to inspect 5% or less.....' and R7
says '...TO failed to complete up to 5%....' They both should
use the same verbiage in each VSL whether it is 'x% or less'
or 'up to and including x%.'
Consideration of Comments on Successive Ballot of FAC-003-2
50
Voter
Entity
Segment
Vote
Comment
Response: The SDT thanks you for your comments.
The percentage should be based on the plan as modified. The SDT has changed the language in the standard to reflect this
more clearly, and has modified the VSLs to be consistent as you have suggested.
James B
Lewis
Consumers
Energy
5
Negative
Consumers Energy submits the following comments on FAC003-2: In general we are please with FAC-003-2 and the
many clarifications that the STD has made in this version of
the standard. However, we do have one major
disagreement with the STD and cannot support this
standard as drafted.
We disagree with the use of the Minimum Vegetation
Clearance Distance (MVCD) developed by the drafting team
for Requirements R1 and R2. These distances are not the
design distances used for designing and constructing
transmission facilities as stated in the document for
minimum distances between conductors and grounded
objects. The proposed Table 2 provides a distance of 3.12
feet as the acceptable distance for an alternate current
345kV line at sea level. This distance is considerably less
than the distance used for line design to separate the
grounded tower structure from the energized conductor. If
the distance in Table 2 is acceptable to prevent energized
portions of a transmission line from grounding to a tree why
then is this distance not the design criteria used for tower
design to prevent flashover from conductor to tower? The
STD needs to explain why a ground tree should have a
different standard that a grounded steel tower or wood
pole structure.
The STD erroneously viewed the possibility of transient over
Consideration of Comments on Successive Ballot of FAC-003-2
51
Voter
Entity
Segment
Consideration of Comments on Successive Ballot of FAC-003-2
Vote
Comment
voltage as only occurring during re-energizing and not from
natural events such as a lightning strike that can occur and
does occur to energized operating lines. Secondly, the
proposed distances in Table 2 are considerably less than the
distances specified in OSHA requirements for air gap
clearance required by tree workers to safely remove trees
or limbs from conductors energized at the voltages
specified. A transmission owner/operator could let a tree
grow to within 3.5 feet of a 345 kV line and not be in
violation of this proposed standard. To remove the tree, the
line would have to be de-energized, tagged, tested deenergized, and grounded. Working clearance would have to
be established by the operating entity and then the tree
crew could remove the tree. The net result is the loss of the
capacity of the line because an outage was forced on the
line in order to remove the tree that did not trigger a
violation of FAC-003-2. This situation, in our opinion, is a
violation of the intent of the standard, which is to ensure
the continued operation of the line. Therefore, the
minimum distance any tree should be able to approach a
conductor is more than the minimum requirement for air
gap distance between the tree and conductor as required by
OSHA worker standards. The STD did not like referring to
another standard to provide the distance requirements for
R1 and R2. This can be alleviated by putting in a table with
the IEEE 516 distances but not reference it as the IEEE 516
standard. The distances provided in the current draft do not
adequately provide or ensure the continued safe operation
of the transmission facilities in the United States and the
reasoning for the distances provided is unfounded and not
based on current design practices.
52
Voter
Entity
Segment
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Comment
Response: The SDT thanks you for your comments. You are correct that these distances do not represent complete design
specifications for towers, nor define and describe safe worker approach distances. These practices are correctly specified in the
other standards you referenced. The SDT feels the standard is clear in that regard. The footnote associated with the Table 2
distances clearly states that these are only distances to prevent flashover under appropriate conditions. The SDT would also
like to point out that the transient overvoltage factors used to derive these distances are the maximums normally seen with a
transmission line in steady state service. Thus, a tower design would have to account for the larger overvoltage factors that are
possible while taking lines out of service.
As has been stated before, these distances were derived using a known set of line design equations and only represent
distances that will prevent spark-over from the transmission line to a grounded object. These are not distances to be managed
to – they have been established as a beginning of a series of “building blocks” for a program to ensure reliability of a
Transmission line within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD.
These distances are smaller than safety standard distances that have many other factors involved in the determination, such as
inadvertent human movement and larger safety factors. In regard to the over-voltages caused by lightning, even the maximum
overvoltage factors contained in the IEEE-516 tables do not account for these.
Bob Essex
Cowlitz
County PUD
5
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
Referring back to Cowlitz’ negative vote made on the 7/919/2010 ballot, Cowlitz tried to convey the problem that the
statement in R4 “without intentional time delay” will
require subjective judgment on the part of the auditor. In
other words, maintaining equal auditing standard
throughout the interconnection will be impossible with this
verbiage in a requirement. Cowlitz agrees with the SDT that
establishing an equitable time frame is very difficult (it may
be impossible!); however leaving it to the judgment of the
auditor to determine whether an intentional delay was
made is most disagreeable. Cowlitz respectfully points out
that the SDT did not adequately address the subjective
nature the auditor is forced into with this requirement. If
53
Voter
Entity
Segment
Vote
Comment
establishing “[t]he time required by the to report an issue is
subject to many variables...” and “[f]or this reason it is
difficult to establish a time period which would fairly apply
to all TO’s,” how does leaving this to the auditor to decide
going to make it any better?
Response: The SDT believes that it was not prudent to suggest a quantitative time element for notification in R4. The technical
reference offers examples of acceptable unintentional delays for your review. The SDT notes that this language is already
embodied in at least one other FERC-approved, in-force Standard.
Kenneth
Dresner
FirstEnergy
Solutions
5
Affirmative
FirstEnergy supports standard FAC-003-2 and would
appreciate consideration of our comments submitted
through the formal comment period.
Response: The SDT thanks you for your comments. Please see our consideration of your comments within the responses to
the formal comments.
David
Schumann
Florida
Municipal
Power Agency
5
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
R1 and R2 requirement reads: "Each Transmission Owner
shall manage to prevent encroachment ....". The results of
manage would be invoices of tree trimming actually
performed, documentation of a vegetation management
program that would be managed to, etc. However, the
Measures proposed are all actual outages which are neither
evidence of management nor evidence of encroachment
since there can be encroachment without an outage, and in
fact, many if not most encroachments do not result in
outages. Hence, the Measures are inconsistent with the
requirements.
Further, there is ambiguity of the action required in
requirements R1 and R2 - e.g., do entities need evidence
that they: 1) "manage", or 2) "prevent encroachment"; or 3)
as implied by the Measures, prevent vegetation related
outages?. In other words, what needs to be proven through
evidence? Certainly the third, prevent vegetation related
54
Voter
Entity
Segment
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Comment
outages, is not in the Requirement; yet, that us what is
proposed for the Measures, highlighting the inconsistency
between Requirements and Measures. But, how would the
ambiguity between "manage" and "prevent encroachment"
be resolved? One auditor could interpret that the
requirement is to "manage" and accept a vegetation
management program and plan and proof that the plan was
executed as appropriate evidence. Another auditor could
interpret that "prevent" is the key word and look for
evidence proving that there was never a vegetation
encroachment. How would evidence be produced to
provide the auditor that vegetation never encroached?
Would video cameras and other surveillance measures need
to operate 24 hours a day? Would we cause an entity to
survey the lines periodically? One can easily see that
"prevent encroachment" is inappropriate here since it is
infeasible to create evidence of compliance. FMPA suggests
one of two approaches: Eliminate the word manage, but do
not focus on encroachment and instead focus on outages.
For instance: "Each Transmission Owner shall prevent
vegetation related outages (except as noted in Footnote 2)
of any of its applicable line(s) ..." Evidence of outages is
practical to gather and provide, evidence of encroachment
is not. Focus on the word "manage", similar to the existing
FAC-003 standard, and move R3 to a new R1 to develop a
management plan, and then the existing R1 and R2 become
R2 an R3 and require execution of that plan in the words of
R7, which would in turn enables elimination of R7.
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
Consideration of Comments on Successive Ballot of FAC-003-2
55
Voter
Entity
Segment
Vote
Comment
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Richard J.
Padilla
Pacific Gas
and Electric
Company
5
Affirmative
There needs to be a change in the footnotes 2 and 4 to
remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “ installation of"
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Wayne
Lewis
Progress
Energy
Carolinas
5
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “installation of.
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Liam
Noailles
Xcel Energy,
Inc.
5
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
Xcel Energy still believes the requirement in R6 that
mandates an annual inspection is an ineffective approach
and may actually go against the Commission’s
determination in FERC Order No. 693. The drafting team’s
response to our last round of comments on this issue was
that “...the SDT was directed by Order 693 to set a minimum
inspection criteria”. It is clear in Order 693 that the
Commission is not satisfied with allowing entities to choose
their own inspection cycles, as the standard currently
allows. However, we fail to see where the Commission
mandated a minimum inspection cycle to be uniformly
applied continent-wide. We urge the drafting team to revisit
paragraphs 719 through 721 of Order 693. According to
paragraph 721, the Commission recognizes that unique
intervals by region, “based on local factors”, are reasonable
and appropriate. By use of the plural term “cycles”, FERC
anticipates the resolution may include multiple inspection
56
Voter
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Segment
Vote
Comment
cycles. Furthermore, in paragraph 719, FERC acknowledges
that a minimum inspection cycle may not be the only way to
address their concern. In fact, mandating an annual
inspection cycle may actually go against the Commission’s
guidance in paragraph 720. Here is an excerpt: “...the
Commission is dissuaded from requiring the ERO to create a
backstop inspection cycle at this time. Instead, the
Commission agrees that an entity’s vegetation management
program should be tailored to anticipated growth in the
region and take into account other environmental factors.
The goal is to assure that transmission owners conduct
inspections at reasonable intervals.”
As an alternative, we propose a mid-cycle inspection. A midcycle inspection is based on an interval that is justified with
data and technical expertise. A mid-cycle inspection would
still require entities to conduct inspections at a specified
interval, while allowing for differences based upon “physical
and geographic factors”. Not only would this approach fully
address the Commissions concerns, but it would take into
account the interests of stakeholders, landowners and ratepayers. We recognize that a mid-cycle inspection interval is
not as easy to audit as an annual requirement, but it is a far
more practical and cost-effective approach that, when
applied based on an entity’s expertise with its own facilities,
ensures reliability.
Response: The SDT thanks you for your comments. The SDT recognizes that a number of Transmission Owners in North
America may prefer to set their own inspection intervals. The SDT can also see attractiveness for a mid-cycle inspection
concept; however, this introduces new complexities in planning, documentation and auditing. Because there is substantial
industry support for an annual inspection interval , the SDT believes that the industry is best served with this approach.
Consideration of Comments on Successive Ballot of FAC-003-2
57
Voter
Edward P.
Cox
Entity
AEP Marketing
Segment
6
Vote
Affirmative
Comment
American Electric Power believes that the phrase
"arboricultural activities or horticultural or agricultural
activities" was mistakenly introduced into Footnotes 2 and
4, and should be deleted from both footnotes. If the phrase
remains in the Standard, it may empower orchard growers,
landowners and others to plant trees on the right of way
and challenge Transmission Owners' rights to perform
maintenance on the presumption that the standard will
exempt the TO from violating the outage or encroachment
requirements.
For increased clarity, AEP offers the following change to the
second paragraph of M1, as well as the second paragraph of
M2. The original text “If a later confirmation of a Fault by
the Transmission Owner shows that a vegetation
encroachment within the MVCD has occurred from
vegetation within the ROW, this shall be considered the
equivalent of a Real-time observation” should be replaced
with “If a later confirmation of a Fault by the Transmission
Owner shows that a vegetation encroachment within the
MVCD has occurred from vegetation growing into or
blowing together with the conductor within the ROW, this
shall be considered the equivalent of a Real-time
observation. A brief encroachment caused by falling
vegetation passing through the MVCD is not considered an
encroachment in this requirement”.
Response: Thanks you for your comments. The SDT made the suggested changes to the footnotes.
Regarding the issue of fall-ins, the SDT is sympathetic to your concern. In fact, the SDT had originally crafted language similar to
that which you suggested. However, due to concerns expressed by regulators and others, the exemption for encroachment
violations due to falling vegetation from inside the right of way was removed.
Consideration of Comments on Successive Ballot of FAC-003-2
58
Voter
Brenda S.
Anderson
Entity
Bonneville
Power
Administration
Segment
6
Vote
Affirmative
Comment
BPA Comments with Yes Vote: In R1 and R2 and their
associated VSLs, the SDT added the phrase “in order of
increasing severity” and added the sentence, “The types of
encroachments are listed in order of increasing degrees of
severity in non-compliant performance as it relates to a
failure of a TO’s vegetation maintenance program.” to the
Rationale boxes for R1/R2. Do you agree? If answer is no,
please explain.
BPA prefers the stratified levels of violation severity
presented in the table for R1 and R2.
Foot note # 2 on page 8 needs to be clarified with respect to
arboricultural activities or horticultural or agricultural
activities.
Foot note # 4 on page 12 needs to be clarified with respect
to arboricultural activities or horticultural or agricultural
activities.
In response to comments received that requirement R3 is
unclear with respect to intent, the SDT added “maintenance
strategies.” Do you agree this clarifies the intent? If answer
is no, please offer alternative language. The TO procedures /
policies and specifications shall demonstrate the TO’s ability
to manage the system at all rated conditions to maintain
reliability.
BPA believes that the intent is clear, but the fundamental
approach of using the MVCD (table 2) to manage a
vegetation program is still problematic. These values are
Consideration of Comments on Successive Ballot of FAC-003-2
59
Voter
Entity
Segment
Vote
Comment
flashover distances and are way too close. This is
acknowledged in a footnote to table 2 but no identification
of allowable buffers/distances between energized phase
conductors at rated temperatures and vegetation is
discussed (this is left up the transmission owners). Clarity is
needed on this topic. Setting a finite distance limit based on
recognized standards, good science and risk avoidance
should be done for the industry. BPA has previously made
this comment during the drafting of the standard. It was not
addressed then, nor has it been addressed now.
Response: The SDT thanks you for your comments. The footnotes were changed to conform with your suggestions.
With respect to comments about the MVCD, R3 does not suggest the MVCD be used as a distance to manage vegetation. The
MVCD was established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line
within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD distances.
In a performance based standard, requirements are focused on “what” needs to be accomplished to achieve desired results
and avoids prescriptive requirements of “how” to achieve that result. TO’s are in the best position to determine the
appropriate management approach suited for their system rather than a “one size fits all” or “fill in the blanks” requirements
that could suppress best practices for vegetation management.
Matthew D
Cripps
Cleco Power
LLC
6
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
Cleco disagrees with the SDT revising the definition for
Right-of-Way (ROW). Right-of-Way is a term that has had a
consistent meaning throughout history. If NERC tries to
redefine the term, it will only add confusion because most
entities will not reference the NERC glossary for a term
which is widely used in the industry. In lieu of "Active
Transmission Line ROW", please use another term such as
Transmission Corridor. No assumptions would be made
when reading in the Standard the the Entity is to maintain
60
Voter
Entity
Segment
Vote
Comment
vegetation located within the Transmission Corridor. Since
the term is not commonly used, the NERC glossary would be
referenced.
Also, Cleco disagrees that an encroachment into the MCVD
that does not cause an outage should be considered noncompliant as stated in R1 and R2. The encroachment should
only be reportable similar to misoperations as is in the PRC004 standard.
Response: Thanks for your comments. The existing ROW definition in the glossary was created by and for the FAC-003-1 and
was moved there when that standard was adopted. The definition includes a series of options that give the Transmission
Owner latitude in establishing ROW width. It does not require selecting a single method for its system. The term blowout
standard is not capitalized and is not a defined term. This phrase in the definition allows a Transmission Owner to use its
internal engineering standards or the general engineering standards that were in effect when the line was constructed to
determine the ROW width. The SDT has limited the definition of Right-of-Way to a corridor of land with a defined width to
operate a transmission line. This does not include danger tree rights. The definition of the MVCD is now added to this Standard.
While use of the pre-2007 records is a compliance issue and is not in the purview of the SDT, it is the intent of the language in
the definition that you could use this information.
Regarding your second comment (begins with Also,): the MVCD was established as a beginning of a series of “building blocks”
for a program to ensure reliability of a Transmission line within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD.
Other related requirements of this “Defense in Depth” Standard serve to address any number of scenarios which may arise or
hinder the TO’s ability to always strictly adhere to the management approach(s) established within R3. Thus the other
requirements of this Standard provide the latitude for appropriate actions to remedy the condition without penalty. Further,
trees which have encroached inside the MVCD are evidence of a deficiency in vegetation maintenance.
Nickesha P
Carrol
Consolidated
Edison Co. of
6
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
Reply to Question 5 on Comment Form: The added language
for the annual work plan percentage complete calculation is
61
Voter
Entity
New York
Segment
Vote
Comment
shown in R7 not M7 as stated in the question. In the
Guideline and Technical Basis Section for Requirement R6,
there is a sample calculation shown for the amount of lines
the TO failed to inspect. An example should also be included
for Requirement R7 since there is some confusion regarding
how modifications to the work plan affect the calculation. In
the Lower VSL column for R7, it states that the TO failed to
complete up to 5% of its annual vegetation work plan
(including modifications if any). If a TO operates 100 lines
and submits a justified modification that affects 10 miles of
lines, the total number of units in the final amended plan is
90 miles. When you read the VSL, it is somewhat confusing
since the information in parenthesis says that the
calculation 'includes' the modifications. Should it state
'excludes modifications if any' or the VSLs can simply be rewritten to state that ..The TO failed to complete up to x% of
the final amended plan.'
Response: The SDT thanks you for your comments. The percentage should be based on the plan as modified. The SDT has
changed the language in the standard to reflect this more clearly.
Mark S
Travaglianti
FirstEnergy
Solutions
6
Affirmative
FirstEnergy supports standard FAC-003-2 and would
appreciate consideration of our comments submitted
through the formal comment period.
Response: The SDT thanks you for your comments. Please see our consideration of your comments within the responses to
the formal comments.
Thomas E
Washburn
Florida
Municipal
Power Pool
6
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
The concern is that entities may not be able prove
compliance with the standard. R1 and R2 say that: "Each
Transmission Owner shall manage vegetation to prevent
encroachments ...". If the requirements were interpreted
such that "manage" is the operative word, then, we are OK
because we can provide evidence of managing a program,
62
Voter
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Comment
such as a vegetation management plan and evidence of
executing that plan (which does not align with the
Measures). However, that 1) would cause the standard to
not be performance based, and 2) it would be duplicative of
the other requirements of the standard.
If the requirements were interpreted with "prevent
encroachment" as the operative phrase (which would be an
incorrect interpretation from the construct of the sentence)
there is no way to provide sufficient evidence that
encroachment was prevented during the audit-period. The
suggested Measures are not sufficient evidence to prove
compliance with that interpretation of the requirement. For
instance, most encroachments do not result in outages;
hence, lack of outages cannot prove that there were no
encroachments, and real time observations are insufficient
because it is a spot-check that does not cover the audit
period.
There are other weaknesses in the standard, such as R4
being un-measurable therefore unenforceable. However, in
the guilty until proven innocent paradigm we live in, FMPA's
primary concern is that industry could be put into a no-win
situation of not being able to prove compliance with the
standard if R1 and R2 are interpreted as "prevent
encroachment", and if R1 and R2 are interpreted as
"manage" then it is not a performance based standard as
advertised.
Performance based focused on preventing vegetation
related outages. For instance: "Each Transmission Owner
Consideration of Comments on Successive Ballot of FAC-003-2
63
Voter
Entity
Segment
Vote
Comment
shall prevent vegetation related outages (except as noted in
Footnote 2) of any of its applicable line(s) ..." Evidence of
outages is practical to gather and provide, evidence of
encroachment is not.
Modify the standard to be similar to the currently
mandatory non-results based standard and focus on the
word "manage". This would essentially mean eliminating R1
and R2 since the rest of the standard focuses on having a
plan and managing to that plan..
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Silvia P.
Mitchell
Florida Power
& Light Co.
6
Affirmative
1. The SDT proposes a revised NERC Glossary definition for
Right-of-Way (ROW). This revised definition will be used in
lieu of the Active Transmission Line ROW. Do you agree? If
answer is no, please explain. Yes
2. In R1 and R2 and their associated VSLs, the SDT added the
phrase “in order of increasing severity” and added the
sentence “The types of encroachments are listed in order of
increasing degrees of severity in non-compliant
performance as it relates to a failure of a TO’s vegetation
maintenance program.” to the Rationale boxes for R1/R2.
Do you agree? If answer is no, please explain. Yes Although
NextEra Energy Inc. (NextEra), including Florida Power &
Light Company, agrees with the changes referenced for R1
Consideration of Comments on Successive Ballot of FAC-003-2
64
Voter
Entity
Segment
Vote
Comment
and R2, NextEra is concerned that the exemptions identified
in footnote 2 for “...arboricultural activities or horticultural
or agricultural activities...,” and similar language in footnote
4, are too broad. For example, this language appears to
include an exemption for a landowner, who, during
arboricultural activities or horticultural or agricultural
activities, causes a vegetation contact with a transmission
line (e.g., cutting or lifting a tree into a transmission line).
This places the Transmission Owner in the difficult position
of a landowner arguing it is exempt from a controllable risk.
Thus, the “...arboricultural activities or horticultural or
agricultural activities...” references should be removed from
footnote 2, and the similar language in footnote 4
3. In response to comments received regarding the term
“investigation” in M1/M2, the SDT substituted
“confirmation...by the Transmission Owner..” in its place,
among other minor edits to these measures. Do you agree?
If answer is no, please explain. Yes
4. In response to comments received that requirement R3 is
unclear with respect to intent, the SDT added “maintenance
strategies”. Do you agree this clarifies the intent? If answer
is no, please offer alternative language. Yes
5. The SDT added clarifying language in M7 to explain how
the annual work plan percentage complete calculation is to
be performed. Is this adequate? If no, please provide
improved examples. Yes
Consideration of Comments on Successive Ballot of FAC-003-2
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Voter
Entity
Segment
Vote
Comment
Response: The SDT thanks you for your comments. The team has made the appropriate modifications to the footnotes as you
suggested.
Thomas
Saitta
Kansas City
Power & Light
Co.
6
Negative
The Standard lacks clarity regarding the facilities that are
subject to Requirement 7. It is important that a Standard be
clear and not introduce ambiguity or confusion. There are
several references throughout the Standard to "for all
applicable lines" and it should be made clear the work plan
is specific to "all applicable lines".
Response: The SDT thanks you for your comments. The phrase, “applicable lines” was added to R7 in support of your
suggestion.
Eric
Ruskamp
Lincoln
Electric
System
6
Affirmative
While supportive of the drafting team’s efforts, LES believes
a change is warranted in Footnote 2 and Footnote 4 to
remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace with the
term “installation of”. As currently drafted, the wording
could potentially be construed to mean that the TO would
or could be constrained or refused permission to prune and
remove any and all vegetation in the ROW in accordance
with the full legal rights of the ROW agreement(s).
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
John T
Sturgeon
Progress
Energy
6
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “installation of.
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
David F.
Lemmons
Xcel Energy,
Inc.
6
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
Xcel Energy still believes the requirement in R6 that
mandates an annual inspection is an ineffective approach
and may actually go against the Commission’s
66
Voter
Entity
Segment
Vote
Comment
determination in FERC Order No. 693. The drafting team’s
response to our last round of comments on this issue was
that “...the SDT was directed by Order 693 to set a minimum
inspection criteria”. It is clear in Order 693 that the
Commission is not satisfied with allowing entities to choose
their own inspection cycles, as the standard currently
allows. However, we fail to see where the Commission
mandated a minimum inspection cycle to be uniformly
applied continent-wide. We urge the drafting team to revisit
paragraphs 719 through 721 of Order 693. According to
paragraph 721, the Commission recognizes that unique
intervals by region, “based on local factors”, are reasonable
and appropriate. By use of the plural term “cycles”, FERC
anticipates the resolution may include multiple inspection
cycles. Furthermore, in paragraph 719, FERC acknowledges
that a minimum inspection cycle may not be the only way to
address their concern. In fact, mandating an annual
inspection cycle may actually go against the Commission’s
guidance in paragraph 720. Here is an excerpt: “...the
Commission is dissuaded from requiring the ERO to create a
backstop inspection cycle at this time. Instead, the
Commission agrees that an entity’s vegetation management
program should be tailored to anticipated growth in the
region and take into account other environmental factors.
The goal is to assure that transmission owners conduct
inspections at reasonable intervals.”
As an alternative, we propose a mid-cycle inspection. A midcycle inspection is based on an interval that is justified with
data and technical expertise. A mid-cycle inspection would
still require entities to conduct inspections at a specified
interval, while allowing for differences based upon “physical
Consideration of Comments on Successive Ballot of FAC-003-2
67
Voter
Entity
Segment
Vote
Comment
and geographic factors”. Not only would this approach fully
address the Commissions concerns, but it would take into
account the interests of stakeholders, landowners and ratepayers. We recognize that a mid-cycle inspection interval is
not as easy to audit as an annual requirement, but it is a far
more practical and cost-effective approach that, when
applied based on an entity’s expertise with its own facilities,
ensures reliability.
Response The SDT thanks you for your comments. The SDT recognizes that a number of Transmission Owners in North America
may prefer to set their own inspection intervals. The SDT can also see attractiveness for a mid-cycle inspection concept;
however, this introduces new complexities in planning, documentation and auditing. Because there is substantial industry
support for an annual inspection interval and due to the vastly simpler auditing associated with an annual interval, the SDT
believes that the industry is best served with this approach.
Jacquie
Smith
ReliabilityFirst
Corporation
10
Negative
ReliabilityFirst votes “No” on the proposed FAC-003-2
because ReliabilityFirst believes that the currently effective
FAC-003-1, despite any weaknesses it may have, better
ensures the reliability of the bulk electric system.
First, under the proposed FAC-003-2, Requirements 1 and 2,
the minimum clearances are reduced.
Second, under the proposed structure of FAC-003-2,
Requirements 1 and 2, violations would only occur where an
encroachment of the Minimum Vegetation Clearance
Distance (“MVCD”) is observed in real time or after
vegetation contact, i.e., after actual harm has occurred.
Consequently, the proposed structure appears to convert a
preventative maintenance standard into a standard that is
essentially only violated after it is too late. The current
structure from Version 1 of the standard (i.e., the Clearance
Consideration of Comments on Successive Ballot of FAC-003-2
68
Voter
Entity
Segment
Vote
Comment
1 and 2 requirements) better ensures reliability because
they seek to ensure that registered entities discover
problematic vegetation conditions prior to encroachments
leading to flashover or vegetation contacts. For example,
the current Clearance 1 is the “clearance distances to be
achieved at the time of transmission vegetation
management work.” And the current Clearance 2 is the
“specific radial clearances to be maintained under all rated
electrical operating conditions.” See FAC-003-1, R1.2.1 and
R1.2.2 (emphasis added).
Third, the draft standard appears to inappropriately and
unnecessarily reduce the risk factor assigned to some
failures to manage vegetation. It draws a distinction
between those transmission lines that are elements of IROLs
or Major Western Electricity Coordinating Council (“WECC”)
transfer paths and those that are not. This distinction is
apparently based on the assumption that vegetation
management violations on transmission lines that are not
elements of IROLS or Major WECC transfer paths are less
important. ReliabilityFirst disagrees with this assumption.
Simply put, both are serious issues and the distinction is
inappropriate and unnecessary. The Final Report on the
August 14, 2003 Blackout in the United States and Canada:
Causes and Recommendations, highlights the importance of
all vegetation management work by identifying inadequate
vegetation management as one of the causes of the 2003
Blackout. See Blackout Report, at p. 20.
Finally, ReliabilityFirst disagrees with the proposed Violation
Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”)
Consideration of Comments on Successive Ballot of FAC-003-2
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Voter
Entity
Segment
Vote
Comment
because they are premised on the same inappropriate and
unnecessary distinction that vegetation management
violations on transmission lines that are not elements of
IROLS or Major WECC transfer paths are less important.
For the foregoing reasons, ReliabilityFirst votes “No” on the
proposed FAC-003-2.
Response: As with a Transmission Owner's determination of its Clearance 1 distances under version 1 of the Standard,
Requirement 3 of the revised Standard begins with the MVCD distances (just as Clearance 1 began with IEEE-516 distances) and
then requires additional consideration for conductor movement, vegetation growth variables, and the utility's maintenance
approach. These are essentially the same considerations required by version 1 of the existing Standard when developing
Clearance 1 distances. Therefore, nothing has been lost in the revised Standard.
The MVCD was established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission
line within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD distances.
The defense-in-depth strategy for reliability standards development recognizes that each requirement in a NERC reliability
standard has a role in preventing system failures, and that these roles are complementary and reinforcing. Reliability standards
should not be viewed as a body of unrelated requirements, but rather should be viewed as part of a portfolio of requirements
designed to achieve an overall defense-in-depth strategy and comport with the quality objectives of a reliability standard. The
draft, when taken in whole, does present a "preventative” maintenance standard.
The Standard has been designed utilizing a "Defense in Depth" strategy which provides for multiple layers of defense against a
MVCD encroachment or an outage. These other layers of defense are identified in requirements R3 through R7. R3 through R7
are the same preventative maintenance requirements as contained in Version 1 of the Standards. Additionally, Measure 3 for
R3 now tests the reasonableness and practicality of a TO’s vegetation management approach long before field work is
implemented; other requirements such as R7 require preventative maintenance work to be completed before encroachments
occur.
The SDT asserts that different VRF’s for IROL and non-IROL lines strengthens the reliability of the standard. Vegetation
Consideration of Comments on Successive Ballot of FAC-003-2
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Voter
Entity
Segment
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Comment
managers that do not know which lines have IROLs or are designated as WECC Transfer Paths may be inappropriately limiting
resources allocated to vegetation management for a line with an IROL or a line designated as a WECC Transfer Path. A
vegetation manager must ensure that the lines with IROLs and lines designated as WECC transfer paths are absolutely clear. By
correctly identifying the risk associated with lines with IROLs line and/or lines designated as WECC Transfer Paths, the standard
helps to assure that appropriate resources are applied.
Consideration of Comments on Successive Ballot of FAC-003-2
71
Exhibit F
Analysis of how VRFs and VSLs Were Determined Using FERC Guidelines
Violation Risk Factor and Violation Severity
Level Assignments
Project 2007-07 Vegetation Management
This document provides the drafting team’s justification for assignment of violation risk factors (VRFs)
and violation severity levels (VSLs) for each requirement in FAC-003-2 Vegetation Management.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support
the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the ERO Sanction Guidelines.
Justification for Assignment of Violation Risk Factors
The SDT applied the following NERC criteria when developing these VRFs:
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures; or, a requirement
in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures, or could hinder
restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if
violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system
instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
Violation Risk Factor & Violation Severity Level Assignments
1
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor and control the bulk electric system; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would
not, under the emergency, abnormal, or restorative conditions anticipated by the preparations,
be expected to adversely affect the electrical state or capability of the bulk electric system, or
the ability to effectively monitor, control, or restore the bulk electric system. A planning
requirement that is administrative in nature.
The SDT also considered consistency with the FERC Violation Risk Factor Guidelines for setting VRFs: 1
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of
Reliability Standards in these identified areas appropriately reflect their historical critical impact
on the reliability of the Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the Bulk-Power System: 2
−
−
−
−
−
−
−
−
−
−
−
−
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk
Factor assignments and the main Requirement Violation Risk Factor assignment.
1
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145
(2007) (“VRF Rehearing Order”).
2
Id. at footnote 15.
Violation Risk Factor & Violation Severity Level Assignments
2
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to
Requirements that address similar reliability goals in different Reliability Standards would be
treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular
Violation Risk Factor level conforms to NERC’s definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk
reliability objective, the VRF assignment for such Requirements must not be watered down to
reflect the lower risk level associated with the less important objective of the Reliability
Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The
team did not address Guideline 1 directly because of an apparent conflict between Guidelines 1 and 4.
Whereas Guideline 1 identifies a list of topics that encompass nearly all topics within NERC’s Reliability
Standards and implies that these requirements should be assigned a “High” VRF, Guideline 4 directs
assignment of VRFs based on the impact of a specific requirement to the reliability of the system. The
SDT believes that Guideline 4 is reflective of the intent of VRFs in the first instance and therefore
concentrated its approach on the reliability impact of the requirements.
VRF Justification
VRF for FAC-003-2, Requirements R1:
The SDT assigned this requirement a VRF of High.
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The Requirement states
transmission owners must manage vegetation for lines that represent a significant risk of
cascading, instability, or separation. The VRF is only applied at the Requirement level and each
Requirement Part is treated equally.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. The requirement mandates
measurable performance with regard to vegetation management to ensure that the risk of
cascading, separation, and instability is minimized. Other requirements with similar performance
based outcomes that could lead to cascading, instability, or separation carry a High VRF.
Violation Risk Factor & Violation Severity Level Assignments
3
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. IROLs and Major WECC
Transfer Paths by definition have an increased potential for leading to cascading, separation, or
instability. Therefore this requirement was assigned a High VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One Objective. The
requirement contains only one objective (to manage vegetation of lines that carry increased risk of
instability, cascading, or separation) and only one VRF was assigned.
VRF for FAC-003-2, Requirements R2:
The SDT assigned this requirement a VRF of Medium.
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The Requirement states
transmission owners must manage vegetation for lines that do not represent a significant risk of
cascading, instability, or separation. The VRF is only applied at the Requirement level and each
Requirement Part is treated equally.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. The requirement mandates
measurable performance with regard to vegetation management to ensure that the risk of
equipment damage is minimized. Other requirements similar performance based outcomes that
could lead to equipment damage carry a Medium VRF.
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Lines that are not IROLs and
Major WECC Transfer Paths by definition have less potential for leading to cascading, separation, or
instability. Therefore this requirement was assigned a Medium VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One Objective. The
requirement contains only one objective (to manage vegetation of lines that carry minimal risk
instability, cascading, or separation) and only one VRF was assigned.
VRF for FAC-003-2, Requirements R3:
The SDT assigned this requirement a VRF of Lower.
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The Requirement mandates the
Transmission Owner to have documented strategies, procedures, processes, or specifications. The
VRF is only applied at the Requirement level and each Requirement Part is treated equally.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. This requirement calls for an entity
to have documented strategies, procedures, processes, or specifications. This requirement is
administrative in nature, and is consistent with other standards requiring documentation.
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Failure to have a document is
not likely to directly affect the electrical state or the capability of the bulk electric system, or the
Violation Risk Factor & Violation Severity Level Assignments
4
ability to effectively monitor and control the bulk electric system. Development of the documents
is a requirement that is administrative in nature and is in a planning time frame that, if violated,
would not, under emergency, abnormal, or restorative conditions anticipated by the preparations,
be expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system.. Therefore this
requirement was assigned a Lower VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One Objective. R2
contains only one objective which is to have documents(s). Since the requirement is to have a
documents, only one VRF was assigned.
VRF for FAC-003-2, Requirements R4:
The SDT assigned this requirement a VRF of Medium.
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The Requirement specifies that
transmission owners must report vegetation conditions that are likely to cause a Fault to the
control center holding switching authority for the associated line. The VRFs are only applied at the
Requirement level and there are no Requirement Parts for separate consideration.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. The requirement mandates
notifications that could hinder the ability to effectively monitor and control the bulk electric
system. Other requirements that address with similar outcomes are also assigned Medium VRFs.
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Failure to report vegetation
conditions may affect the ability to effectively monitor and control the bulk electric system
Therefore this requirement was assigned a Medium VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One Objective. The
requirement contains only one objective (to report) , and only one VRF was assigned.
VRF for FAC-003-2, Requirements R5:
The SDT assigned this requirement a VRF of Medium.
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The Requirement mandates that a
Transmission Owner, when constrained from performing vegetation work that may lead to a
vegetation encroachment into the MVCD prior to the implementation of the next annual work plan,
must take corrective action to ensure continued vegetation management to prevent
encroachments. The VRF is only applied at the Requirement level and there are no Requirement
Parts for separate consideration.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. The requirement mandates
corrective action that, if not taken, could directly affect the electrical state or the capability of the
bulk electric system. Other requirements with similar outcomes are also assigned Medium VRFs.
Violation Risk Factor & Violation Severity Level Assignments
5
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Failure to take corrective action
could directly affect the electrical state or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system. Therefore this requirement was assigned a
Medium VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One Objective. The
requirement contains only one objective (to take corrective action), and only one VRF was
assigned.
VRF for FAC-003-2, Requirements R6:
The SDT assigned this requirement a VRF of Medium.
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The Requirement specifies that the
transmission owner must perform a Vegetation Inspection of 100% of its lines at least once per
calendar year. The VRFs are only applied at the Requirement level and there are no Requirement
Parts for separate consideration.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. The requirement mandates
inspections that, if not performed, could affect the ability to effectively monitor and control the
bulk electric system. Other requirements with similar outcomes are also assigned Medium VRFs.
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Failure to perform an inspection
could affect the ability to effectively monitor and control the bulk electric system. Therefore this
requirement was assigned a lower VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One Objective. The
requirement contains only one objective (to perform a Vegetation inspection), and only one VRF
was assigned.
VRF for FAC-003-2, Requirements R7:
The SDT assigned this requirement a VRF of Medium.
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The Requirement specifies that the
Transmission Owner must complete 100% of its annual vegetation work plan. The VRFs are only
applied at the Requirement level and there are no Requirement Parts for separate consideration.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. The requirement mandates
completion of work that, if not completed, could affect the electrical state or the capability of the
bulk electric system. Other requirements with similar outcomes are also assigned Medium VRFs.
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Failure to complete the annual
vegetation work plan could affect the electrical state or the capability of the bulk electric system.
Therefore this requirement was assigned a lower VRF.
Violation Risk Factor & Violation Severity Level Assignments
6
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One Objective. The
Requirement contains only one objective (to complete 100% of the annual vegetation work plan),
and only one VRF was assigned.
Justification for Assignment of Violation Severity Levels
In developing the VSLs, the SDT anticipated the evidence that would be reviewed during an audit, and
developed its VSLs based on the noncompliance an auditor may find during a typical audit. The SDT
based its assignment of VSLs on the following NERC criteria:
Lower
Missing a minor
element (or a small
percentage) of the
required
performance
The performance or
product measured
has significant value
as it almost meets the
full intent of the
requirement.
Moderate
Missing at least one
significant element
(or a moderate
percentage) of the
required
performance.
The performance or
product measured
still has significant
value in meeting the
intent of the
requirement.
High
Severe
Missing more than
one significant
element (or is missing
a high percentage) of
the required
performance or is
missing a single vital
component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant
elements (or a
significant
percentage) of the
required
performance.
The performance
measured does not
meet the intent of
the requirement or
the product delivered
cannot be used in
meeting the intent of
the requirement.
FERC’s VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for
each requirement meet the FERC Guidelines for assessing VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended Consequence of
Lowering the Current Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may
encourage a lower level of compliance than was required when levels of non-compliance were
used.
Violation Risk Factor & Violation Severity Level Assignments
7
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the
Determination of Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant
performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the Corresponding
Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A
Cumulative Number of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a
requirement is a separate violation. Section 4 of the Sanction Guidelines states that assessing
penalties on a per violation per day basis is the “default” for penalty calculations.
Violation Risk Factor & Violation Severity Level Assignments
8
VSLs for FAC-003-2 Requirement R1:
Compliance with
NERC’s VSL
Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should
Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
The proposed VSL uses
the same terminology as
used in the associated
requirement, and is,
therefore, consistent with
the requirement.
The VSL is based on
a single violation and
not cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R1
Meets NERC’s
VSL guidelines.
There is an
incremental
aspect to the
violation and the
VSLs follow the
guidelines for
incremental
violations..
This is a new
requirement, and
accordingly cannot
lower the current level
of compliance.
The proposed VSL does not use
any ambiguous terminology,
thereby supporting uniformity
and consistency in the
determination of similar
penalties for similar violations.
Violation Risk Factor & Violation Severity Level Assignments
9
VSLs for FAC-003-2 Requirement R2:
Compliance with
NERC’s VSL
Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should
Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based
on A Single
Violation, Not on A
Cumulative
Number of
Violations
The proposed VSL uses
the same terminology as
used in the associated
requirement, and is,
therefore, consistent with
the requirement.
The VSL is based
on a single
violation and not
cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R2.
Meets NERC’s
VSL guidelines.
There is an
incremental
aspect to the
violation and the
VSLs follow the
guidelines for
incremental
violations.
This is a new
requirement, and
accordingly cannot
lower the current level
of compliance.
The proposed VSL does not use
any ambiguous terminology,
thereby supporting uniformity
and consistency in the
determination of similar
penalties for similar violations.
Violation Risk Factor & Violation Severity Level Assignments
10
VSLs for FAC-003-3 Requirement R3
Compliance with
NERC’s Revised
VSL Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should
Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based
on A Single
Violation, Not on A
Cumulative
Number of
Violations
The proposed VSLs use
the same terminology as
used in the associated
requirement, and are,
therefore, consistent with
the requirement.
The VSLs are
based on a single
violation and not
cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R3.
Meets NERC’s
VSL guidelines.
There is an
incremental
aspect to the
violation and the
VSLs follow the
guidelines for
incremental
violations.
The previous standard
graded the VSLs based
on the completeness of
the TVMP. The new
VSL is structured
similarly, but has
omitted the “Low”
level, effectively raising
the minimum level of
compliance.
The proposed VSLs do not use
any ambiguous terminology,
thereby supporting uniformity and
consistency in the determination
of similar penalties for similar
violations.
Violation Risk Factor & Violation Severity Level Assignments
11
VSLs for FAC-003-3 Requirement R4:
Compliance with
NERC’s Revised
VSL Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should
Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based
on A Single
Violation, Not on A
Cumulative
Number of
Violations
The proposed VSLs use
the same terminology as
used in the associated
requirement, and are,
therefore, consistent with
the requirement.
The VSLs are
based on a single
violation and not
cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R4.
Meets NERC’s
VSL guidelines.
There is an
incremental
aspect to the
violation and the
VSLs follow the
guidelines for
incremental
violations.
The previous standard
does not require actual
communication, while
the new standard does.
Accordingly, this
should be treated as a
new requirement, and
therefore cannot lower
the current level of
compliance.
The proposed VSLs do not use
any ambiguous terminology,
thereby supporting uniformity and
consistency in the determination
of similar penalties for similar
violations.
Violation Risk Factor & Violation Severity Level Assignments
12
VSLs for FAC-003-3 Requirement R5:
Compliance with
NERC’s Revised
VSL Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should
Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based
on A Single
Violation, Not on A
Cumulative
Number of
Violations
The proposed VSLs use
the same terminology as
used in the associated
requirement, and are,
therefore, consistent with
the requirement.
The VSLs are
based on a single
violation and not
cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R5.
Meets NERC’s
VSL guidelines Severe: The
performance or
product measured
does not
substantively
meet the intent of
the requirement.
The only VSL is
Severe, and therefore,
the VSL cannot result in
a lower level of
compliance.
The proposed VSLs do not use
any ambiguous terminology,
thereby supporting uniformity and
consistency in the determination
of similar penalties for similar
violations.
Violation Risk Factor & Violation Severity Level Assignments
13
VSLs for FAC-003-3 Requirement R6:
Compliance with
NERC’s Revised
VSL Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should
Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based
on A Single
Violation, Not on A
Cumulative
Number of
Violations
The proposed VSLs use
the same terminology as
used in the associated
requirement, and are,
therefore, consistent with
the requirement.
The VSLs are
based on a single
violation and not
cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R6.
Meets NERC’s
VSL guidelines.
There is an
incremental
aspect to the
violation and the
VSLs follow the
guidelines for
incremental
violations.
The previous standard
does not require actual
inspections, while the
new standard does.
Accordingly, this
should be treated as a
new requirement, and
therefore cannot lower
the current level of
compliance.
The proposed VSLs do not use
any ambiguous terminology,
thereby supporting uniformity and
consistency in the determination
of similar penalties for similar
violations.
Violation Risk Factor & Violation Severity Level Assignments
14
VSLs for FAC-003-3 Requirement R7:
Compliance with
NERC’s Revised
VSL Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should
Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based
on A Single
Violation, Not on A
Cumulative
Number of
Violations
The proposed VSLs use
the same terminology as
used in the associated
requirement, and are,
therefore, consistent with
the requirement.
The VSLs are
based on a single
violation and not
cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R7.
Meets NERC’s
VSL guidelines.
There is an
incremental
aspect to the
violation and the
VSLs follow the
guidelines for
incremental
violations.
The VSLs in the
previous standard were
focused on
completeness of the
document, with the
“Severe” VSL only
reserved for entities that
did not have or
implement their plan.
The proposed VSLs are
graded based on the
amount of the plan
completed, giving a
clear indication that
partial completion is
still a violation,
establishing a level of
compliance in excess of
what was established
previously.
The proposed VSLs do not use
any ambiguous terminology,
thereby supporting uniformity and
consistency in the determination
of similar penalties for similar
violations.
Violation Risk Factor & Violation Severity Level Assignments
15
Exhibit G
Record of Development of Proposed FAC-003-2 — Transmission Vegetation
Management Reliability Standard
Project 2007-07
Transmission Vegetation Management
Related Files
Status:
Adopted by the Board of Trustees on November 3, 2011.
Purpose/Industry Need:
FAC-003-1 was approved in 2006. It has some ‘fill-in-the-blank’ components to eliminate.
In addition, the following comments submitted by FERC and stakeholders need to be
addressed in the refinement of the standard:
FERC Order 693 items
Address the issue regarding applicability:
• Work with the reliability entities and the ERO to collect and make available to the
FERC, a list of critical lower voltage transmission lines. (Refer to Applicability 4.3
section of the standard.)
• Consider other criteria in determining applicability of the standard to sub 200kV
lines.
• Address the issue of clearances for lines on both federal and non-federal lands:
• Review and analyze outage data (collected by the ERO) then consider defining
clearances needed to avoid sustained vegetation-related outages that would apply to
transmission lines crossing both federal and non-federal land.
•
Consider revising the definition of right of way to encompass required clearance
areas.
• Review the suitability of IEEE 516-2003 standard for minimum vegetation clearance.
•
Review and analyze outage data (collected by the ERO) then consider defining
clearances needed to avoid sustained vegetation-related outages that would apply to
transmission lines crossing both federal and non-federal land.
• Consider revising the definition of right of way to encompass required clearance
areas.
• Review the suitability of IEEE 516-2003 standard for minimum vegetation clearance.
Procedural items
• Re-format standard to bring it into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
• Remove references to RRO in the standard and substitute a responsible entity.
• Add newly developed compliance elements such as time horizons, violation risk
factors, violation severity levels, etc.
Stakeholder items
• Prepare technical reference material such as a “white paper” to aid in understanding
the technical basis for the standard.
• Review reporting criteria for Category 3 outages in the proposed technical reference
material and may remove the reporting requirement of Category 3 outages in R.3
and R.4.
• Consider deleting requirement R.4.
• Review the reporting exemptions to include all category outages under major
disasters in Requirement R3.2.
The development may include other improvements to the standards deemed appropriate
by the drafting team, with the consensus of stakeholders, consistent with establishing
high quality, enforceable and technically sufficient bulk power system reliability
standards.
Draft
Action
Dates
Results
Consideration
of Comments
Draft 6 Standard
FAC-003-2
Clean (73)| Redline to Last
Posting(74)
Implementation Plan
Clean(75) | Redline(76)
Technical References:
Clean (77)| Redline to Last
Posting(78)
Recirculation
Ballot
Supporting Materials:
FAC-003-1(79)
Info(85)
Mapping Table(80)
Vote >>
10/04/11 Summary(86)
10/13/11
Full
(closed)
Record(87)
New and Modified Definitions(81)
Consideration of Issues and
Directives(82)
Violation Risk Factor & Violation
Severity Level Assignment(83)
Technical, Policy and Regulatory
Issues Addressed by SDT(84)
Draft 5 Standard
FAC-003-2
Successive
Ballot
FAC-003-2
Clean (56)| Redline to Last
Posting(57)
Info(64)
Vote >>
Full
Record(66)
02/18/11
Summary(67)
02/28/11
Non-binding
Results(68)
Consideration
of Comments
(70)
Consideration
of Comments:
Non-Binding
Poll (71)
Implementation Plan
Clean(58) | Redline to Last
Posting(59)
Supporting Materials:
FAC-003-1(60)
Comment Form (Word)(61)
Technical White Paper
Clean (62)| Redline to Last
Posting(63)
Draft 4
Standard − FAC-003-2
FAC-003-2
Clean (41)| Redline to Last
Posting(42)
Implementation Plan
Clean(43) | Redline to Last
Posting(44)
Supporting Materials:
Comment Form (Word)(45)
Mapping Document(46)
Technical White Paper(47)
Comment
Period
Info(65) |
Submit
Comments>>
01/27/11
Comments
Received(69)
02/28/11
Consideration
of Comments
(72)
Initial Ballot
Vote>> |
Info(48)
07/09/10
Full
Record(51)
07/19/10
(closed) Summary(52)
Consideration
of
Comments(54)
Pre-ballot
Review
Join>> |
Info(49)
Comment
Period
Info(50) |
Submit
Comments >>
06/17/10
07/07/10
(closed)
06/17/10
Comments
07/17/10 Received(53)
(closed)
Consideration
of Comments
(55)
03/01/10
Comments
03/31/10 Received(39)
(closed)
Consideration
of Comments
(40)
Draft 3
Standard − FAC-003-2
FAC-003-2(33)
Implementation Plan(34)
Mapping Document(35)
Supporting Materials:
Comment Form (Word)(36)
Technical Reference Document(37)
Informal
Comment
Period
Info(38) |
Submit
Comments>>
Draft 2
Standard − FAC-003-2
FAC-003-2
Clean (24)| Redline to Last
Posting(25)
Mapping Document(26)
Supporting Materials:
Comment Form (Word)(27)
FAC-003-2 Technical White
Paper(28)
Implementation Plan(29)
Comment
Period
Info(30) |
Submit
Comments>>
09/10/09
Comments
Summaries (32)
10/24/09 Received(31)
(closed)
Draft 1
Standard − FAC-003-2
FAC-003-2(17)
Comment
Period
Mapping Changes(18)
Supporting Materials:
Comment Form (Word)(19)
Info(21) |
Submit
Comments>>
10/27/08
–
Comments
11/25/08 Received(22)
(closed)
Consideration
of
Comments(23)
FAC-003-2 − Technical White
Paper(20)
Draft SAR Version 3
Vegetation Management
Draft SAR Version 2(13)
Standard
Drafting Team
Nomination
Draft SAR Version 3
Clean (14)| Redline to 1st
Posting(15)
Submit
Nomination(16)
Draft SAR Version 2
Comment
Period
07/03/07
07/17/07
(closed)
04/10/07 Comments
Received(11)
Consideration
of
Vegetation Management
Draft SAR Version 2(7)
Redline to 1st Posting(8)
Info(9)> |
Submit
Comments(10)
SAR Drafting
Team
Nominations
05/09/07
(closed)
Comments(12)
01/29/07
(closed)
Submit
Nomination(6)
Draft SAR Version 1
Vegetation Management
Draft SAR Version 1(1)
Comment
Period
01/15/07
02/14/07
Info(2) |Submit
(closed)
Comments(3)
Comments
Received(4)
Consideration
of Comments
(5)
Standards Authorization Request Form
Standard Authorization Request Form
Title of Proposed Standard
Project 2007-07
Revisions to FAC-003-1 Vegetation Management Program
Request Date
January 9, 2007
SAR Type (Check a box for each one
that applies.)
SAR Requestor Information
Name Richard Schneider (To be
replaced by SAR DT Chair when the SAR DT is
appointed.)
New Standard
Primary Contact
Revision to existing Standard
Telephone
Richard Schneider
609-452-8060
Withdrawal of existing Standard
[email protected]
Urgent Action
Fax
E-mail
Purpose/Industry Need (Describe the purpose of the standard — what the standard will
achieve in support of reliability.)
The purpose of revising this standard is to:
1. Provide an adequate level of reliability for the North American bulk power systems - the
standard is complete and the requirements are set at an appropriate level to ensure
reliability.
2. Ensure it is enforceable as a mandatory reliability standard with financial penalties - the
applicability to bulk power system owners, operators, and users, and as appropriate
particular classes of facilities, is clearly defined; the purpose, requirements, and
measures are results-focused and unambiguous; the consequences of violating the
requirements are clear.
3. Incorporate other general improvements described in the attached Standard Review
Guidelines
4. Consider comments received from ERO regulatory authorities and stakeholders, as noted
in the attached review sheets.
5. Satisfy the standards procedure requirement for five-year review of the standards.
SAR- 1
Standards Authorization Request Form
Brief Description
This is a new standard that was approved in 2006. It has some ‘fill-in-the-blank’
components to eliminate. In addition, the following comments submitted by FERC and
stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to Bulk-Power System transmission lines that have
an impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- RA vs. RRO
- Too weak on compliance
- Format inconsistencies
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
SAR- 2
Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Coordinator
Ensures the reliability of the bulk transmission system within its
Reliability Coordinator area. This is the highest reliability
authority.
Balancing Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within its metered boundary and
supports system frequency in real time.
Interchange
Authority
Authorizes valid and balanced Interchange Schedules.
Planning Authority
Plans the Bulk Electric System.
Resource Planner
Develops a long-term (>one year) plan for the resource adequacy
of specific loads within a Planning Authority area.
Transmission
Planner
Develops a long-term (>one year) plan for the reliability of
transmission systems within its portion of the Planning Authority
area.
Transmission
Service Provider
Provides transmission services to qualified market participants
under applicable transmission service agreements
Transmission Owner
Owns transmission facilities.
Transmission
Operator
Operates and maintains the transmission facilities, and executes
switching orders.
Distribution
Provider
Provides and operates the “wires” between the transmission
system and the customer.
Generator Owner
Owns and maintains generation unit(s).
Generator Operator
Operates generation unit(s) and performs the functions of
supplying energy and Interconnected Operations Services.
Purchasing-Selling
Entity
The function of purchasing or selling energy, capacity, and all
necessary Interconnected Operations Services as required.
Market Operator
Integrates energy, capacity, balancing, and transmission
resources to achieve an economic, reliability-constrained dispatch.
Load-Serving Entity
Secures energy and transmission (and related generation
services) to serve the end user.
SAR- 3
Standards Authorization Request Form
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk electric systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk electric systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk electric
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk electric
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk electric systems.
6. Personnel responsible for planning and operating interconnected bulk electric
systems shall be trained, qualified, and have the responsibility and authority to
implement actions.
7. The security of the interconnected bulk electric systems shall be assessed,
monitored and maintained on a wide area basis.
Does the proposed Standard comply with all the following Market Interface
Principles? (Select “yes” or “no” from the drop-down box.)
1. The planning and operation of bulk electric systems shall recognize that reliability is an
essential requirement of a robust North American economy. Yes
2. An Organization Standard shall not give any market participant an unfair competitive
advantage.Yes
3. An Organization Standard shall neither mandate nor prohibit any specific market structure.
Yes
4. An Organization Standard shall not preclude market solutions to achieving compliance with
that Standard. Yes
5. An Organization Standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes
SAR- 4
Standards Authorization Request Form
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Explanation
Regional Differences
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
SAR- 5
Standard Review Guidelines
Standard Review Guidelines
Applicability
Does this reliability standard clearly identify the functional classes of entities responsible for
complying with the reliability standard, with any specific additions or exceptions noted?
Where multiple functional classes are identified is there a clear line of responsibility for each
requirement identifying the functional class and entity to be held accountable for
compliance? Does the requirement allow overlapping responsibilities between Registered
Entities possibly creating confusion for who is ultimately accountable for compliance?
Does this reliability standard identify the geographic applicability of the standard, such as
the entire North American bulk power system, an interconnection, or within a regional entity
area? If no geographic limitations are identified, the default is that the standard applies
throughout North America.
Does this reliability standard identify any limitations on the applicability of the standard
based on electric facility characteristics, such as generators with a nameplate rating of 20
MW or greater, or transmission facilities energized at 200 kV or greater or some other
criteria? If no functional entity limitations are identified, the default is that the standard
applies to all identified functional entities.
Purpose
Does this reliability standard have a clear statement of purpose that describes how the
standard contributes to the reliability of the bulk power system? Each purpose statement
should include a value statement.
Performance Requirements
Does this reliability standard state one or more performance requirements, which if
achieved by the applicable entities, will provide for a reliable bulk power system, consistent
with good utility practices and the public interest?
Does each requirement identify who shall do what under what conditions and to what
outcome?
Measurability
Is each performance requirement stated so as to be objectively measurable by a third party
with knowledge or expertise in the area addressed by that requirement?
Does each performance requirement have one or more associated measures used to
objectively evaluate compliance with the requirement?
If performance results can be practically measured quantitatively, are metrics provided
within the requirement to indicate satisfactory performance?
Technical Basis in Engineering and Operations
Is this reliability standard based upon sound engineering and operating judgment, analysis,
or experience, as determined by expert practitioners in that particular field?
Completeness
Is this reliability standard complete and self contained? Does the standard depend on
external information to determine the required level of performance?
Page 1 of 4
January 15, 2006
Standard Review Guidelines
Consequences for Noncompliance
In combination with guidelines for penalties and sanctions, as well as other ERO and
regional entity compliance documents, are the consequences of violating a standard clearly
known to the responsible entities?
Clear Language
Is the reliability standard stated using clear and unambiguous language? Can responsible
entities, using reasonable judgment and in keeping with good utility practices, arrive at a
consistent interpretation of the required performance?
Practicality
Does this reliability standard establish requirements that can be practically implemented by
the assigned responsible entities within the specified effective date and thereafter?
Capability Requirements versus Performance Requirements
In general, requirements for entities to have “capabilities” (this would include facilities for
communication, agreements with other entities, etc.) should be located in the standards for
certification. The certification requirements should indicate that entities have a
responsibility to “maintain” their capabilities.
Consistent Terminology
To the extent possible, does this reliability standard use a set of standard terms and
definitions that are approved through the NERC reliability standards development process?
If the standard uses terms that are included in the NERC Glossary of Terms Used in
Reliability Standards, then the term must be capitalized when it is used in the standard.
New terms should not be added unless they have a “unique” definition when used in a NERC
reliability standard. Common terms that could be found in a college dictionary should not
be defined and added to the NERC Glossary.
Are the verbs on the “verb list” from the Drafting Team Guidelines? If not, do new verbs
need to be added to the guidelines or could you use one of the verbs from the verb list?
Violation Risk Factors (Risk Factor)
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk power
system instability, separation, or a cascading sequence of failures, or could place the
bulk electric system at an unacceptable risk of instability, separation, or cascading
failures;
or a requirement in a planning time frame that, if violated, could, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of
failures, or could place the bulk power system at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the
capability of the bulk power system, or the ability to effectively monitor and control
the bulk power system. However, violation of a medium risk requirement is unlikely
to lead to bulk electric system instability, separation, or cascading failures;
Page 2 of 4
January 15, 2006
Standard Review Guidelines
or a requirement in a planning time frame that, if violated, could, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system. However,
violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system
instability, separation, or cascading failures, nor to hinder restoration to a normal
condition.
Lower Risk Requirement
A requirement that, if violated, would not be expected to adversely affect the
electrical state or capability of the bulk power system, or the ability to effectively
monitor and control the bulk power system. A requirement that is administrative in
nature;
or a requirement in a planning time frame that, if violated, would not, under the
emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric
system, or the ability to effectively monitor, control, or restore the bulk electric
system. A planning requirement that is administrative in nature.
Mitigation Time Horizon
The drafting team should also indicate the time horizon available for mitigating a violation to
the requirement using the following definitions:
•
Long-term Planning — a planning horizon of one year or longer.
•
Operations Planning — operating and resource plans from day ahead up to and
including seasonal.
•
Same-day Operations — routine actions required within the time frame of a day,
but not real time.
•
Real-time Operations — actions required within one hour or less to preserve the
reliability of the bulk power system.
•
Operations Assessment — follow-up evaluations and reporting of real-time
operations.
Violation Severity Levels
The drafting team should indicate a set of violation severity levels that can be applied for
the requirements within a standard. (“Violation severity levels” replace existing “levels of
non-compliance.”) The violation severity levels may be applied for each requirement or
combined to cover multiple requirements, as long as it is clear which requirements are
included.
The violation severity levels should be based on the following definitions:
•
Lower: mostly compliant with minor exceptions — The responsible entity is
mostly compliant with and meets the intent of the requirement but is deficient with
respect to one or more minor details. Equivalent score: 95% to 99% compliant.
•
Moderate: mostly compliant with significant exceptions — The responsible
entity is mostly compliant with and meets the intent of the requirement but is
deficient with respect to one or more significant elements. Equivalent score: 85% to
94% compliant.
Page 3 of 4
January 15, 2006
Standard Review Guidelines
•
High: marginal performance or results — The responsible entity has only
partially achieved the reliability objective of the requirement and is missing one or
more significant elements. Equivalent score: 70% to 84% compliant.
•
Severe: poor performance or results — The responsible entity has failed to meet
the reliability objective of the requirement. Equivalent score: less than 70%
compliant.
Compliance Monitor
Replace “Regional Reliability Organization” with “Electric Reliability Organization”
Fill-in-the-blank Requirements
Do not include any “fill-in-the-blank” requirements. These are requirements that assign one
entity responsibility for developing some performance measures without requiring that the
performance measures be included in the body of a standard — then require another entity
to comply with those requirements.
Every reliability objective can be met, at least at a threshold level, by a North American
standard. If we need regions to develop regional standards, such as in underfrequency load
shedding, we can always write a uniform North American standard for the applicable
functional entities as a means of encouraging development of the regional standards.
Requirements for Regional Reliability Organization
Do not write any requirements for the Regional Reliability Organization. Any requirements
currently assigned to the RRO should be re-assigned to the applicable functional entity.
Effective Dates
Must be 1st day of 1st quarter after entities are expected to be compliant — must include
time to file with regulatory authorities and provide notice to responsible entities of the
obligation to comply. If the standard is to be actively monitored, time for the Compliance
Monitoring and Enforcement Program to develop reporting instructions and modify the
Compliance Data Management System(s) both at NERC, and Regional Entities must be
provided in the implementation plan.
Associated Documents
If there are standards that are referenced within a standard, list the full name and number
of the standard under the section called, “Associated Documents.”
Functional Model Version 3
Review the requirements against the latest descriptions of the responsibilities and tasks
assigned to functional entities as provided in pages 13 through 53 of the draft Functional
Model Version 3.
Page 4 of 4
January 15, 2006
Maureen E. Long
Standards Process Manager
January 15, 2007
TO:
REGISTERED BALLOT BODY
Ladies and Gentlemen:
Announcement: Comment Periods Open for SAR to Modify Vegetation Management, SAR
for Reliability Coordination and SAR and Standard to Modify Facility Ratings Standards
The Standards Committee (SC) announces the following standards actions:
SAR to Modify the Vegetation Management Standard FAC-003-1 Posted for 30-day
Comment Period January 15–February 14, 2007
The SAR for Project 2007-07 proposes modifying the Vegetation Management standard FAC-003-1 to
address concerns raised by FERC and stakeholders and to bring the standard into conformance with the
ERO Rules of Procedure and the latest version of the Reliability Standards Development Procedure.
Please use the comment form to provide comments on this SAR.
SAR to Modify the Reliability Coordinator Standards Posted for 30-day Comment Period
January 15–February 14, 2007
The SAR for Project 2006-06 proposes retiring, modifying, or adding to existing requirements for the
reliability coordinator to ensure that the complete set of requirements addresses all the processes,
procedures, plans, tools, and authorities the reliability coordinator needs to support the reliable operation
of the interconnected bulk power systems. This project involves addressing concerns raised by FERC and
stakeholders and also involves bringing the set of standards into conformance with the ERO Rules of
Procedure and the latest version of the Reliability Standards Development Procedure. Please use the
comment form to provide comments on this SAR.
SAR and Standard to Modify the Facility Ratings Standards Posted for 45-day Comment
Period January 15–February 28, 2007
The SAR for Project 2006-09 proposes modifying two Facility Ratings standards, FAC-008-1 and FAC009-1, to address concerns raised by FERC and stakeholders and to bring the standard into conformance
with the ERO Rules of Procedure and the latest version of the Reliability Standards Development
Procedure. Because there were relatively few technical changes recommended for this set of standards,
the revised standard, which combines FAC-008-1 and FAC-009-1, is posted for comment along with an
implementation plan. Please use the comment form to provide comments on this SAR, standard and
implementation plan.
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards
development process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate. If you have any questions, please
contact me at 813-468-5998 or [email protected].
Sincerely,
Maureen E. Long
cc:
Registered Ballot Body Registered Users
Standards Mailing List
NERC Roster
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments:
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments:
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
William J. Smith
Organization: Allegheny Power
Telephone:
(724) 838-6552
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments:
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments:
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Michael Johnson
Organization: Bonneville Power Administration
Telephone:
360.418.2161
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: Ok, Yes and No. The first FERC NOPR bullet needs to be addressed.
The second bullet is clearly discribed in the standard. A. 4.4.3. The reader must read
the statement in context. It meets the Standard Review Guidelines.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: Since this posting is for comment it would have been nice to provide more
information as to why the FERC staff objects to the IEEE standard (since it meet the
guidelines for as a North America standard. Also, why are stakeholder concerned with
Reliability Coordinators vs. RRO?
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: It is not clear if categroy 1 and 2 refer only to occupied ROW, or also to
unoccupied area reserved by the Transmission Owner for future expansion.
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
William T. Rees
Organization: Baltimore Gas and electric
Telephone:
410-291-3479
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: The revisions listed in the NOPR and FERC Staff Report do not provide the
necessary justification to alter the requirements in the current FAC-003-1 document.
The existing requirements already allow for each utility to specify the inspection
requirements. There is no need to more prescriptive. The existing requirements already
allow for the ERO to designate critical lines less than 200 kV so removal of the 200 kV
benchmark is unecessary. The IEEE Standard is worthwhile to keep as a benchmark
without which there would be no solid guidance for minimum clearances.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: As noted above.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Brian D. Bartos
Organization: Bandera Electric Cooperative, Inc.
Telephone:
830-796-6074
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: The items listed as potential revisions are vague and do not provide
sufficient justification to alter the current requirements of this standard which has been
in effect less than 1 year. The current standard allows for the region to determine which
transmission lines are critical to reliability and should be included in a Transmission
Owner's Transmission Vegetation Management Plan regardless of voltage classification.
The current standard also allows each TO the flexibility to develop its plan in accordance
with its specific geography and operating environment. There is no need to be more
prescriptive.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: As submitted, the SAR appears to completely re-open this standard negating
many months of work and industry comment to reach the consensus reflected in the
current FAC-003.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: See Comment #2
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
David Kiguel
Organization: Hydro One Networks Inc.
Telephone:
416-345-5313
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Hydro One Networks Inc.
Lead Contact:
David Kiguel
Contact Organization:
Hydro One Networks Inc.
Contact Segment:
1
Contact Telephone:
416-345-5313
Contact E-mail:
[email protected]
Additional Member Name
George Juhn
Additional Member
Organization
Hydro One Networks Inc.
Region*
NPCC
Segment*
1
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: We believe that at this time it is premature to move forward with changes to
the standard that are based on voltage class issues. The Standard, as developed,
applies to the BES which have been determined by a performance based methodology.
NERC should wait until the BES vs. BPS issue is resolved.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: To address FERC's objection to use the IEEE standard, it is necessary to
clarify the objective of the Vegetation Management Standard. As we understand it, the
focus of the FAC-003-1 standard is system reliability and as such, the responsibility and
authority on defining and applying the safety margins is rightly assigned to the
transmission owner. We request clarification on how employing safety factors will
address reliability and how prescribing minimum clearances within the standard will
improve reliability.
Please note that the Canadian Standards Association is revising standard C22.3 No. 1 Overhead Systems. The new version will include clearances to vegetation and the
proposed minimum clearances are in alignment with FAC-003-1.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
NPCC, CP9 Reliability Standards Working Group
Lead Contact:
Guy V. Zito
Contact Organization:
NPCC
Contact Segment:
10
Contact Telephone:
212-840-1070
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Ralph Rufrano
New York Power Authority
NPCC
1
Ed Thompson
Con Ed
NPCC
1
Jerad Barnhart
NSTAR
NPCC
1
Roger Champagne
Hydro Quebec TransEnergie
NPCC
1
Herb Schrayshuen
National Grid US
NPCC
1
Greg Campoli
New York ISO
NPCC
2
Kathleen Goodman
ISO-New England
NPCC
2
Bill Shemley
ISO-New England
NPCC
2
Ron Falsetti
The IESO, Ontario
NPCC
2
David Kiguel
Hydro One Networks Inc.
NPCC
1
Don Nelson
MA Dept of Tele. and Energy
NPCC
9
Murale Gopinathan
Northeast Utilities
NPCC
1
Guy Zito
NPCC
NPCC
10
Brian Hogue
NPCC
NPCC
10
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: NPCC participating members believe that it is premature to move forward
with changes based on voltage class. Applicability of the standard should only be to
those portions of the system that are part of the Bulk Power System which have been
determined by a performance based methodology.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: See response to question 1, above.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: Only if the Bulk Power System is determined as an impact based
performance based methodology.
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Jimmy Etheridge
Organization: Georgia Transmission Corporation
Telephone:
770-270-7650
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
SERC Vegetation Management Subcommittee
Lead Contact:
Richard Dearman
Contact Organization:
TVA
Contact Segment:
1
Contact Telephone:
256-519-2067
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Jay Farrington
Alabama Electric Coop
SERC
1
Randy Gann
Alabama Power Co.
SERC
1
Raymond Wiesehan
Ameren
SERC
1
John Neagle
Associated Electric Coop
SERC
1
Billy George
Duke Energy Carolinas
SERC
1
Ralph Hale
Entergy
SERC
1
Marc Tunstall
Fayetteville PWC
SERC
1
Jack Gardner
Progress Energy Carolinas
SERC
1
Jerry Lindler
SCE&G
SERC
1
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: The SERC VMS is unsure how to answer the question as it is worded, but
has the following comments on the SAR:
The current standard contains appropriate requirements and measures to ensure the
owners vegetation management program is implemented and managed to ensure the
reliability of the transmission system. Mandating inspection cycle frequencies will not
enhance nor ensure reliability by inspecting more or less frequently. The minimum
vegetation clearances at maximum operating conditions that are established within the
owner's program, which is auditable by the ERO, will ensure reliability. Extending the
requirements to lines other than those >200KV may reduce the focus on those lines and
may cause the allocation of resources away from lines >200KV. Generally easements
are narrower on lower voltage lines, requiring more resources and emphasis on these
lines. This may have an effect on the ability to focus clearing efforts on those lines that
will have a much greater impact on the bulk power system. The IEEE standard when
used as the minimum clearance distance at maximum operating condition will ensure
reliability when these clearances are maintained by vegetation management activities.
In addition, we do not agree that a standard of zero tolerance for vegetaion-related
outages in the ROW is weak on compliance.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: Minimum Inspection Intervals:
The SERC VMS believes that FAC 003-1 provides the proper amount of flexibility
regarding vegetation inspection cycles and that the Standards Drafting Team should not
impose minimum inspection intervals on a continent with such regional diversity in
climate and plant life.
The purpose of Requirement 1.1 of standard FAC-003-1 is to put the responsibility
for proper inspection cycles on the entity that knows the local conditions and can best
define what that inspection frequency should be, the Transmission Owner. Both NERC
and the FERC staff have recognized that various local conditions can have an affect on
the determination of adequate inspection frequencies. Establishing a mandatory
minimum inspection frequency could have two detrimental effects on the industry.
First, where a particular region is heavily forested and has heavy rainfall along with
extended or year round growing seasons, a “back stop” minimum inspection frequency
could lead transmission owners to conduct inspections less frequently than required by
the local conditions. This could result in a Transmission Owner complying with the
Page 4 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
standard while not adequately protecting the reliability of that region’s transmission
system. This is a “lowest common denominator” approach which FERC has repeatedly
stated is inappropriate for the reliability standards.
Second, where a particular region is arid, sparsely forested or has a minimum
growing season, a “back stop” minimum could require a more frequent interval than is
realistically needed. This would result in increased and unnecessary costs for electric
utility customers without providing an increase in system reliability.
In its discussion of inspection intervals, FERC indicates that a “one-year vegetation
inspection cycle is reasonable.” FERC NOPR, 10/20/2002 paragraph 383. The
Commission continues by stating “a one-year inspection cycle is the ‘norm’ for the
industry, but not the lowest common denominator…” It follows from this observation
that the industry as a whole recognizes and follows appropriate inspection intervals
without a need to change the standard. Further, FERC also states “some variation to a
continent-wide, one-year minimum inspection cycle should be allowed due to physical
differences such as climate and species of vegetation.” FERC NOPR 10/20/2006,
paragraph 382. FERC’s express recognition that a “one size fits all” approach is not
appropriate further supports the SERC VMS’s contention that the existing inspection
requirements in standard FAC-003-1 should remain unchanged.
Finally, the performance metrics of FAC-003 require the reporting of applicable
transmission interruptions that are caused by vegetation. This process should
appropriately identify Transmission Owners’ inspection cycles that are not adequate. In
this event, the ERO has the authority to engage the Transmission Owner in enforcement
compliance actions and, therefore, can remedy any vegetation-related outage that is
attributed to the Transmission Owner’s inspection frequency.
Standard Applicability:
The SERC VMS disagrees with the proposal to revise the 200 kV threshold for
determining facilities subject to this standard.
The majority of transmission facilities below 200 kV have significantly different
design/construction/operating characteristics and have not been cited as impacting bulk
power system reliability. For example, the Final Report on the August 14, 2003 Blackout
in the United states and Canada: Causes and Recommendations April 2004 by the U.S.Canada Power System Outage Task Force and all referenced major blackouts(pages 103115) in that report, cited only outages which involved vegetation at line voltages above
200 kV. Generally applying requirements appropriate for 200 kV lines to lines less than
200 kV will result in significant documentation and reporting of items such as
restrictions, mitigation plans, off right-of-way vegetation-related outage
investigation/information and other issues, all of which dilutes the focus on lines that
directly impact bulk power system reliability.
Revising the standard to use general criteria or broad language for defining "Bulk
Power System" transmission lines covered by the standard could become a “one size fits
all” approach. If that approach were taken, the standard would cover a significant
number of transmission lines that have no direct impact on bulk power system reliability
under standard planning/operating conditions, resulting in a significant increase in costs
for electric customers without improving “Bulk Power System” system reliability. The
SERC VMS believes that the applicability provision of the standard should instead focus
attention of the standard only on the transmission lines below 200 kV that directly
impact “Bulk Power System” reliability, as the current version requires.
In sum, while the SERC VMS recognizes some validity in the Commission’s concern,
the SERC VMS recommends that the applicability provision of this standard should be
revised only if existing system design, planning or operating reliability criteria and
parameters are considered as a basis for defining the applicability of the standard. To
Page 5 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
that end, the SERC VMS recommends each Regional Entity (RE) determine applicability
of FAC-003 to those lines within the region that are between 100 kV and 200 KV if and
only if they are identified as operationally significant elements of Interconnection
Reliability Operating Limits (“IROLs”).
IEEE Standard for Minimum Clearances:
The SERC VMS disagrees with objections in the FERC staff report to the use of the IEEE
516-2003 clearance as the minimum acceptable distances for “Clearance 2”. The IEEE
516-2003 tables are appropriate for defining the minimum acceptable clearances to
prevent flashover between conductors and vegetation under all rated electrical operating
conditions. Closer minimum clearances such as the minimum length of a support
insulator could have been adopted as a “lowest common denominator” clearance.
However the clearance in IEEE 516-2003 was adopted to ensure an additional margin of
reliability. FERC staff references ANSI Z-133 which is a safety standard that addresses
worker safety as well as the safety of the general public. As such, the purpose of ANSI
Z-133 is to address worker safety and is not focused on transmission line reliability,
which is the purpose of FAC-003-1. OSHA, NESC and other related safety standards
have clearances in excess of IEEE 516-2003. Those clearances are clearly focused on
safety issues and will still apply to other aspects of design and operation of electric
facilities (such as public and worker safety) but do not need to be referenced in a
vegetation management reliability standard.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: Standard Applicability:
The outage reporting requirement for the RRO should be deleted. Making FAC-003
applicable to the RRO is in violation of the legislation that established the ERO. This
legislation states that enforceable standards can apply only to owners, users and
operators of the bulk power system. Futher, in the NOPR on NERC standards, FERC
declined to approve those standards that applied to the RROs, in part because the RROs
are not owners, users or operators.
Compliance:
The SERC VMS recommends deleting reporting requirements for Category 3 outages.
These outages are not controllable, not relevant to compliance, not related to grid
reliability, not related to cascading blackouts, and such reporting leads to unnecessarily
biasing reliability related information.
Page 6 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
John Loftis
Organization: Dominion - Electric Transmission
Telephone:
(804) 819-2337
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments:
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: We disagree with the proposal from FERC NOPR regarding removing
applicability to transmission lines >200kv. The proposal to apply the Standard to lines
the ERO deems to have an impact on reliability can create inconsistency between
regions and is a "fill in the blank" requirement. It is not clear whether the proposed
change would increase or decrease the number of transmission lines which are subject
to reportable outages. In addition, we support the Standard's existing language that
limits reporting to locked out lines only.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Midwest Reliability Organization
Lead Contact:
Dick Pursley
Contact Organization:
MRO for Group (Great River Energy for Contact)
Contact Segment:
10
Contact Telephone:
763.241.2249
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Neal Balu
WPSR
MRO
10
Terry Bilke
MISO
MRO
10
Alan Boesch
NPPD
MRO
10
Robert Coish, Chair
MHEB
MRO
10
Carol Gerou
MP
MRO
10
Ken Goldsmith
ALT
MRO
10
Todd Gosnell
OPPD
MRO
10
Jim Haigh
WAPA
MRO
10
Tom Mielnik
MEC
MRO
10
Pam Oreschnick
XEL
MRO
10
Dave Rudolph
BEPC
MRO
10
Eric Ruskamp
LES
MRO
10
Joe Knight
MRO
MRO
10
27 Additional MRO Members
Not Named Above
MRO
10
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments:
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: The scope of this SAR would have been better defined if the complete
Standard Review Form for the Vegetation Management Standard had been included as
an attachment to the SAR. Several issues in the Standard Review Form for this SAR
were excluded with this posted SAR. For example, issues related to R3.1 and R3.2.
The MRO is also not clear on the scope of the instruction to the SDT to "Expand the
applicability to include transmission lines operated at 200 kV and above and other
facilities as determined by the ERO so that the Reliability Standard applies to Bulk-Power
System transmission lines that have an impact on reliability" It is not clear to the MRO
what is meant by "as determined by the ERO". What process will the ERO use? The
ERO should use stakeholder input to make this determination. The current standard is
applicable to all transmission lines 200 kV and above and to any lower voltage lines
designated by the RRO as critical to the electric system in the region. Will the ERO be in
a position to assume the assessment of the criticality of lines less than 200 kV without
input from the entities that have historically operated in each region?
Also, the MRO is not clear on what is included in the term Bulk-Power System. What
guidance will the SDT have in determining what is meant by the Bulk-Power System?
Since this relates to the large issue of the Bulk Electric System versus Bulk-Power
System is this SAR the appropriate vehicle to address this issue? There should be a
wider discussion and resolution to this issue for consistent application to all standards by
all SDTs.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: Since the IEEE standard does not appear to be a favorable clearance
requirement, minimum clearance requirements should be tied to legal documents such
as easments, state statute, or permits. This will help Transmission Owners to maintain
Page 4 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
their ROWs based on their agreements with the land owners and not rely on historical
ROW management practices. It would also provide flexibility in clearance requirements
based on geopraphical and climatological factors that influence different regions because
landowner agreements will be different depending on local influences.
Page 5 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Florida Power and Light Company
Lead Contact:
John Tamsberg
Contact Organization:
Florida Power and Light Company
Contact Segment:
1
Contact Telephone:
(561) 694-3975
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Marty Mennes, PE.
FRCC
1
Barbara Jaindl, PE.
FRCC
1
Michael Warr, PE.
FRCC
1
Greg Keller, PE.
FRCC
1
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: FPL recognizes the need to address the concerns outlined in the NOPR and
by the FERC Staff.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: Establishing minimum inspection cycles is a very problematic given the large
variety of vegetative conditions throughout North America. In reality most lines are
inspected annually for all failure modes including vegetation. The trees that played a
part of the North East Blackout were known and on the radar screen. The utility failed to
take action. The inspection did not prevent the outage from occurring. The failure to
take action on the known site condition was the contributing factor to the Blackout.
We do not understand the need to establish separate criteria other than the RRO’s
critical designation. A transmission line is either necessary to the system to prevent an
overload situation or it is not. To add lines that might not be critical to the system would
dilute the effort needed to insure that the critical lines are properly maintained. Since
system stability is the focus of the standard, what criteria would be used to bring
additional lower voltage lines under the standard.
When developing Clearance 2, the committee needed to determine a distance at which a
Transmission Owner could be out of compliance even though no interruption has
occurred. In a sense this is the maximum ‘speed limit’ at which the utility would be in
violation. Their criteria was “How close can a tree be and not cause an outage?” The
engineers on the team reviewed scientific data and current standards. The IEEE MAID
standard was the consensus selection of the sub committee. All parties need to
understand that this is one of the building blocks that would be used in determining the
width of an easement or ROW. Picking the ANSI Z133.1 Table 1 or 2 as the NOPR
suggests could immediately place thousands of miles of transmission lines out of
compliance that have performed satisfactorily for years. The ANSI tables are phase to
phase safety calculations when grow-in tree interruptions are phase to ground
situations.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Page 4 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Yes
No
Comments: Requirement 3.2 exempts reporting of outages from outside the ROW when
natural disasters such as tornados or hurricanes occur. Our experience with numerous
hurricanes indicates that all outages during these types of events should be exempt. The
focus in these situations is to get the lines back in service and restore customers. There
is insufficient manpower to adequately complete the forensics necessary to determine an
accurate root cause. It is not uncommon to find vegetation debris in the lines or downed
trees on the ROW in this situation. In most cases it is not possible to determine the
original location of these trees.
In the compliance section of the document a transmission owner becomes non compliant
with a single category 1 or 2 outage. This occurs regardless of the circumstances. A non
compliant penalty for a single outage in a situation where no customers were affected
and the system could not have been compromised is not reasonable. It is also not an
indicator of a poorly maintained system. We agree that several Category 1 or 2
interruptions could be an indicator of neglect but one is not. We recommend that The
compliance section be reviewed with this in mind.
Page 5 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
FRCC
Lead Contact:
Eric Senkowicz
Contact Organization:
FRCC
Contact Segment:
10
Contact Telephone:
813-289-5644
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Alan Gale
City of Tallahassee
FRCC
5
Clark Hawkins
Lee County Electric Cooperative
FRCC
3
Mark Bennett
Gainesville Regional Utilities
FRCC
5
Pedro Modia
Florida Power and Light
FRCC
1
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments:
NERC as the ERO along with its regulated stakeholders need to use the Standards
Process to continue refining the industry's suite of standards, especially to address
inconsistencies within the standards. The process also serves to address real or
perceived reliability concerns in a balanced and open forum.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: As stated in this SAR comment form, the improvements should be made to
bring the standard into conformance with the Reliability Standards Development
Procedure which at this time is version 6.0, adopted by NERC BOT, 11/1/2006. The SAR
scope via the attached Standard Review Guidelines includes two areas not defined within
the procedure. The Mitigation Time Horizons and definitions for the violation severity
levels (VSLs), Lower, Moderate, High and Severe.
We understand the description of Mitigation Time Horizons and definitions for VSLs are
included in the SAR (the concept of Violation Time Horizons is included in the Sanctions
Guidelines, appendix 4B, NERC Compliance Filing to FERC dated October 18th, 2006),
but these discrepancies are part of a broader policy issue and since their use is not
clearly stipulated in the NERC Reliability Standards Development Procedure, including
them in the scope of the SAR is premature and will cause unnecessary confusion to
stakeholders and regulators.
The process is requesting the industry to comment on a scope that is defined outside the
reliability standards process and as such is subject to revisions and interpretations
outside the process as well. This appears inappropriate and at the extreme will lead to
inconsistent understanding, measurement and enforcement of compliance actions.
The Mitigation Time Horizons and VSL levels should be defined in the Reliability
Standards Development Procedure prior to inclusion in the scope of a SAR.
Specific Items Within Current SAR Scope:
The establishment of minimum inspection cycles has been addressed previously, in the
development of the current standard and was found very problematic given the large
variety of vegetative conditions throughout North America. The vegetation that was
Page 4 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
identified as a contributing cause to the 2003 Northeast Blackout had already been
identified by previous inspection activities. It was the failure to take action on the
known site conditions that contributed to the event. Therefore, a minimum inspection
cycle would still NOT have prevented or mitigated the scope of the Blackout.
The current 200 kV threshold ensures that vegetation management efforts are focused
on the critical bulk power transfer lines and that TVM efforts are not diluted by including
additional lower voltage lines. In practicality, the RRO designation process provides the
necessary flexibility to the Regions to address localized areas where bulk power system
reliability may be compromised by lower voltage vegetation outages. To note as well,
Northeast Blackout related vegetation outages which initiated the cascade occurred on
lines that operate at 345 kV, well above the current threshold.
The FRCC supported the development of Clearance 2, as established in the current
standard, as this was a consensus selection by not only the subject matter experts, but
many industry participants. Picking the ANSI Z133.1 Table 1 or 2 as the NOPR
suggests, could immediately place thousands of miles of transmission lines out of
compliance even though operating data indicates that the lines have performed
satisfactorily for years. The concern would be, the resulting dilution of valuable industry
and regulator resources.
The SAR includes the following stakeholder comment: "Too weak on compliance" .
We caution that we feel the compliance section does need refining, but that in a world of
limited resources should focus on trends in vegetation outages and not necessarily on
single outages. For transmission owners, two outages on a radial 230 kV circuit should
not carry the same penalty as eight outages on multiple 230 kV circuits within a
network. We would recommend that compliance be refined to identify trends, relevance
and risk probability to help the industry focus their resources appropriately.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Requirement 3.2, item (1), the reporting exemption for outages occuring due to natural
disaters should be expanded to include all vegetation outages that occur as a result of
the disaster. Currently the exemption applies to vegetation from outside the ROW.
As a result of significant experience with hurricanes, our operators have found that this
distinction results in a waste of post-disaster resources. The standard currently requires
the owner to investigate and determine the original location of the vegetation that may
have caused an outage. Restoration of circuits may be delayed and often times,
determination of the original location of the vegetation is not possible .
Page 5 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Michael Spector, Transmission Planning
Organization: Central Hudson Gas & Electric
Telephone:
845-486-5469
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: The proposed revisions listed under the FERC NOPR do not provide proper
justification to alter the requirements in the current FAC-003-1 document that was
adopted one year ago.
First, "a minimum vegatation inspection cycle that allows variation in physical
difference" is already called for under the current standard. As stated in Section R1.1.
of FAC-003-1, a schedule already should be defined under the transmission vegetation
management program (TVMP). This schedule already allows for "variation in physical
difference" since the current standard states that "this schedule should be flexible
enough to adjust for changing conditions."
Secondly, under Applicability Section 4.3., the current standard already allows for lines
with lower voltage than 200kV to be "designated by the RRO as critical" and therefore
applicable to the standard. Removal of the 200kV benchmark is not needed.
And lastly, under the FERC staff report, the IEEE standard provides guidance in
clearances and has been the industry standard for many years. If FERC objects to using
this standard then they should provide clearances that can be discussed and agreed
upon by the transmission owners.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: See comments above.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Sam Stonerock
Organization: Southern California Edison
Telephone:
951-317-6149
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: There was no empirical or anecdotal evidence presented by FERC staff to
support the Commission's view that the reliability of the Bulk Power System will be
enhanced with further revisions to FAC-003-1. This standard was the subject of vigorous
industry debate in a previous SAR. Although it is far from perfect, the proposed revisions
will not improve reliability and may very well damage existing VM programs.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: The Commission's reccomendation to develop a "minimum" vegetation
inspection cycle is untimely and their proposal to revise the scope ignores plain language
contained in the standard.
In SCE’s view, the Commission's incessant need to bolt on a "widget count" requirement
(for minimum inspection cylcles) will likely lead to an increased number of tree-to-line
contacts. Unlike the static equipment located in power plants and substations, trees and
foliage in and around Transmission ROWs are subject to uncontrolable and fairly
unpredictable natural forces. Industry debate during the previous SAR and comments
submitted in the recently concluded NOPR demonstrate this approach is unsound.
Transmission Owners in neighboring states commented that their cycles and trimming
protocols vary from year to year and sometimes circuit to circuit. Instituting a minimum
inspection cycle of 3 years (for example) might appeal to certain TOs because doing so
will support a case for increased rate recovery. But for others, a mandatory 3 year
inspection cycle will offer a potential cost reduction opportunity because they are already
following a voluntary 2 year inspection cycle.
The Commission's other reccomendedation should be rejected because subsection 4.3
clearly covers transmission lines operating below 200 kV. ["….any lower voltage lines
designated by the RRO as critical to the reliabilty of the electric system in the region.”]
FAC-003-1 requires Transmission Owners to - “define a schedule for and the type
(aerial, ground) of ROW vegetation inspections”. Although the Commission staff would
prefer a specific time duration because it suits their "check list" style of enforcement,
the prudent thing to do is allow TOs the latitude to manage their part of the bulk system
and hold each accountable to the existing compliance measures in FAC-003-1. Similarly,
revising subsection 4.3 in deferrence to the Commission's or staff's misinterpretation of
plain text is unwarranted.
Page 4 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: Although SCE is wholly dissatisfied with the integration of IEEE 516-2003
into FAC-003-1 and looks forward to the day when qualified industry professionals and
utility arborists are provided an opportunity to develop a reasonable and scientifically
sound method for determining “minimum” tree-to-line clearances, we believe this
standard should be allowed to “soak” a bit before subjecting it to further revision.
Page 5 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Jack Gardner
Organization: Progress Energy
Telephone:
919-329-5922
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: The current standard contains appropriate levels of guidelines and penalties
to ensure the owners vegetation management program is implemented and managed to
ensure the reliability of the transmission system. Mandating inspection cycle frequencies
will not enhance nor ensure reliability by inspecting more or less frequently. The
minimum vegetation clearances at maximum operating conditions that are established
within the owner's program that are auditable by the ERO will ensure reliability. By
adding lines other than those >200KV may reduce the focus on those lines and impact
the budget dollars allocated to focus on the lines >200KV. Generally easements are
much more narrow on lower voltage lines, the impact on budget dollars would often
require more emphasis on these lines. This may have an effect on the ability to focus
clearing efforts on those lines that will have a much greater impact on the bulk power
system. The IEEE standard when used as the minimum clearance distance at maximum
operating condition will ensure reliability when these clearances are maintained by
vegetation management activities.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments:
Minimum Inspection Intervals:
Progress Energy believes that this standard provides the proper amount of flexibility
regarding vegetation inspection cycles and that the FAC-003 standard revision should
not develop minimum inspection intervals on a continent with such regional diversity in
climate and plant life.
The purpose of Requirement 1.1 of standard FAC-003-1 is to put the responsibility
for proper inspection cycles on the entity that knows the local conditions and can best
define what that inspection frequency should be, the Transmission Owner. Both NERC
and the FERC staff have recognized that various local conditions can have an affect on
the determination of adequate inspection frequencies. Establishing a mandatory
minimum inspection frequency could have two detrimental effects on the industry.
First, where a particular region is heavily forested and has heavy rainfall along with
extended or year round growing seasons, a “back stop” minimum inspection frequency
could lead transmission owners to conduct inspections less frequently than what the
local conditions require. This could result in a Transmission Owner complying with the
standard while not adequately protecting the reliability of that region’s transmission
system. This is a “lowest common denominator” approach which FERC has repeatedly
stated is inappropriate for the reliability standards.
Page 4 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Second, where a particular region is arid, sparsely forested or has a minimum
growing season, a “back stop” minimum could require a more frequent interval than is
realistically needed. This would result in increased and unnecessary costs for electric
utility customers without providing an increase in system reliability.
In its discussion of inspection intervals, FERC indicates that a “one-year vegetation
inspection cycle is reasonable.” NOPR, P 383. The Commission continues by stating “a
one-year inspection cycle is the ‘norm’ for the industry, but not the lowest common
denominator…” It follows from this observation that the industry as a whole recognizes
and follows appropriate inspection intervals without a need to change the standard.
Further, FERC also states “some variation to a continent-wide, one-year minimum
inspection cycle should be allowed due to physical differences such as climate and
species of vegetation.” NOPR, P 382. FERC’s express recognition that a “one size fits
all” approach is not appropriate further supports Progress Energy’s contention that the
existing inspection requirements in standard FAC-003 should remain unchanged.
Finally, the performance metrics of proposed standard FAC-003 require the reporting
of applicable transmission interruptions that are caused by vegetation. This process
should appropriately identify Transmission Owners’ inspection cycles that are not
adequate. In this event, the ERO has the authority to engage the Transmission Owner
in enforcement compliance actions and, therefore, can remedy any vegetation-related
outage that is attributed to the Transmission Owner’s inspection frequency.
Standard Applicability:
Progress Energy disagrees with the proposal to revise the 200 kV guidepost for
determining facilities subject to this standard.
The majority of transmission facilities below 200 kV have significantly different
design/construction/operating characteristics and have not been cited as impacting bulk
power system reliability. For example, the 2003 DOE “Blackout Report,” and all
referenced major blackouts in the Report, cited only outages which involved vegetation
at line voltages above 200 kV. The characteristics of lines below 200 kV will result in
significant documentation and reporting of items such as restrictions, mitigation plans,
off right-of-way vegetation-related outage investigation/information and other issues, all
of which dilutes the focus on lines that directly impact bulk power system reliability.
Revising the standard to use general criteria or broad language for defining "Bulk
Power System" transmission lines covered by the standard could become a “one size fits
all” approach. If that approach were taken, the standard would cover a significant
number of transmission lines that have no direct impact on bulk power system reliability
under standard planning/operating conditions, resulting in a significant increase in costs
for electric customers without improving “Bulk Power System” system reliability.
Progress Energy believes that the applicability provision of the standard should instead
focus attention of the standard only on the transmission lines below 200 kV that directly
impact “Bulk Power System” reliability, as the current version requires.
In sum, while Progress Energy recognizes some validity in the Commission’s concern,
Progress Energy recommends that the applicability provision of this standard should be
revised only if existing system design, planning or operating reliability criteria and
parameters are considered as a basis for defining the applicability of the standard. For
example, it may be appropriate to limit the applicability of the standard to all lines that
are operated at 200 kV and above and to operationally significant circuits between 100
kV and 200 KV that are elements of Interconnection Reliability Operating Limits
(“IROLs”).
IEEE Standard for Minimum Clearances:
Progress Energy disagrees with objections in the FERC staff report to the use of the IEEE
516-2003 clearance as the minimum acceptable distances for “Clearance 2”. The IEEE
Page 5 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
516-2003 tables are appropriate for defining the minimum acceptable clearances to
prevent flashover between conductors and vegetation under all rated electrical operating
conditions. Closer minimum clearances such as the minimum length of a support
insulator could have been adopted as a “lowest common denominator” clearance.
However the clearance in IEEE 516-2003 was adopted to ensure an additional margin of
reliability. FERC staff references ANSI Z-133 which is a safety standard that addresses
worker safety as well as the safety of the general public. As such, the purpose of ANSI
Z-133 is to address safety and is not focused on transmission line reliability, which is the
purpose of FAC-003-1. OSHA, NESC and other related safety standards have clearances
in excess of IEEE 516-2003. Those clearances are clearly focused on safety issues and
will still apply to other aspects of design and operation of electric facilities (such as
public and worker safety) but do not need to be referenced in a vegetation management
reliability standard. Reliability standards are not the appropriate forum for addressing
safety standards or issues, such as worker safety. The reliability standards should focus
on reliability issues.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: Standard Applicability:
The outage reporting requirement for the RRO should be deleted. Making FAC-003
applicable to the RRO is in violation of the legislation that established the ERO. This
legislation states that enforceable standards can apply only to owners, users and
opeartors of the bulk power system. Futher, in the NOPR on NERC standards, FERC
declined to approve those standards that applied to the RROs, in part because the RROs
are not owners, users or operators.
Compliance:
Progress Energy believes that FAC-003 should focus compliance on the issues that
improve system/grid reliability. The VM standard outage reporting requirements do not
focus on ensuring grid/network reliability.
Category 2 outages (“Fall-ins” from vegetation within the R/W) result in a level of noncompliance (Level 2 or 3). However, “Fall-ins”, either off-R/W or within the R/W, are
random events. They would not occur sequentially (i.e., a fall-in causing another line
section to overload resulting in another “fall-in”) and would not have the potential to
cascade into a widespread blackout. This is a customer reliability issue for that line, not
a grid reliability issue. While it may be worthwhile to report for tracking and trending, it
is not an outage that should result in non-compliance.
Category 1 “Grow-ins” include outages that result from conductor side-wing would be
reported as Category 1 outages, resulting in non-compliance (Level 3 or 4). However,
conductor side-swing outages are random occurrences. They are not the sequential
outages that would have the potential to cascade into a widespread blackout. This is a
customer reliability issue for that line, not a grid reliability issue.
These types of outages should be not be considered any different than numerous other
random events that result in transmission line outages.
Page 6 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Richard Mider
Organization: New York State Electric and Gas Corporation
Telephone:
607-762-7686
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: The current draft FAC 003 1 will provide a high level of reliability for the
transmission bulk delivery system which the public now expects. After a comprehensive
industry rewiew which included industry balloting, the current Vegetaion Management
Standard 003 1 was approved in Feburary 2006 and several sections did not go in to
effect for one year (2007). Sufficient time should be allowed so that impact of the
current standard can be monitored.
FAC 003 1 was designed to prevent cascading type outages and by establishing a
standard for 200KV lines and above catastrophic type power outages will be eliminated.
Lower volatge lines can be placed under this standard when the impact on the bulk
delivery system requires tighter management as determined by local reliability
organizations. Inspection cycles must be designed to meet regional needs based on
local conditons, and the current standard provides this flexiblity.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: The current standard FAC 003 1 should be monitored for one to two full
years after all segments have been implemented. February 14, 2007 is too soon to
determine if a revision is required.
The standard should apply to 200 KV lines and higher voltages to prevent cascading
type power outages.
The IEEE table 516 is referenced as a minimum guide for table 2 clearances. This table
provides clear and measurable distances that can used for audits and potential
compliance issues. The current standard allows enough flexibility so that the clearance
2 distance can be expanded if a utility feels that is the correct approach in a specfic
region.
The physical differences between electric systems, tree growth rates, local regulations,
climate, and geography make it important to provide a flexible standard, a "one size fits
all" approach will not be effective in the long run.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Page 4 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Comments: The Vegetation Management Standard FAC 003 1 is comprehensive, and
utilities following the established guidelines will be able to meet FERC's expecation of
preventing bulk power delivery outages by using crisp measurable guidleines that offer
limited flexiblity for varying conditions.
Page 5 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Southern Company Transmission
Lead Contact:
Roman Carter
Contact Organization:
Southern Co. Transmission
Contact Segment:
1
Contact Telephone:
205-257-6027
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Roman Carter
Southern Company Transmission
SERC
1
Steve Burns
Gulf Power Co.
SERC
1
Randall Gann
Alabama Power Co.
SERC
1
John West
Georgia Power Co.
SERC
1
Marc Butts
Southern Co. Transmission
SERC
1
JT Wood
Southern Co. Trans.
SERC
1
Jim Busbin
Southern Co. Trans.
SERC
1
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: We are not sure what you are asking? If you are asking whether we support
the standard as it exists today-Southern does! If you are asking whether Southern Co.
supports the changes being recommended in this Standard-we DON"T.
The present standard appears to be serving its intended purpose and the industry as
currently written. The standard should not be revised until it has demonstrated it is
ineffective or inadequate for ensuring the reliability of the nation's transmssion grid.
Any changes to the standard should be based on empirical data rather than the
assumption that the Standard is not serving its intended purpose. The standard has not
been in effect long enough to determine if it is ineffective.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: The scope of the SAR should be limited to formatting and changes of
wording that recognize the formation of the ERO and its procedures.
The drafting team should not attempt to re-write the present clearance requirements,
which are based on IEEE flashover distances. The clearance requirements in the orignal
standard were written through extensive evaluation and input from the industry. There
was strong industry consensus on the present language and the standard is serving its
intended purpose very well. The clearance standard should not be revised until it is
found to be ineffective or inadequate.
The drafting team should not attempt to change the applicability of the present
standard. The present standard applies to all 200 KV and higher lines, plus any other
line the Regional Entity deems critical. A change in wording to make the standard apply
to any bulk power system transmission line deemed critical by the ERO does not provide
any additional safeguard that is not already contained in the standard as presently
written.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
Page 4 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
No
Comments:
Page 5 of 5
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Ron Falsetti
Organization: IESO Ontario
Telephone:
905 855-6187
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments:
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments:
With respect to the item in the Brief Description section under FERC NOPR:
“Remove the applicability to transmission lines operated at 200 kV and above so that the
Reliability Standard applies to Bulk Power System transmission lines that have an impact
on reliability as determined by the ERO.” It is the IESO’s view that requiring the ERO to
make these determinations, is inappropriate. We believe the standard should remain
applicable to lines 200 kV and above and lines below 200 kV as determined by the
Reliability Coordinator, similar to the PRC-023 standard.
The IESO also suggests that it be made clear in the SAR that it will be a complete review
of the subject requirements: to include the addition, deletion and modification of
requirements, as agreed to by public consensus.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Mike Gentry
Organization: Salt River Project
Telephone:
602-236-6408
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments:
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments:
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Richard Dearman
Organization: Tennessee Valley Authority
Telephone:
256-519-2067
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: As worded this question is confusing however the following comments are
presented on the SAR:
The current standard contains appropriate requirements and measures to ensure that
vegetation related outages will not cause cascading transmission blackouts. Mandating
new expiicit inspection cycle frequencies will not enhance nor ensure reliability by
inspecting more or less frequently. The current minimum vegetation clearances at
maximum operating conditions that are established within the owner's program, which is
auditable by the ERO, is sufficient to prevent vegetation related cascading transmission
blackouts. Extending the requirements to a much a larger population of lines would
reduce the current focus on the most important lines (those >200 kV). The IEEE
standard when used as the minimum vegetation clearance distance at maximum
operating condition will ensure desired performance of the lines. A standard of zero
tolerance for vegetaion related outages in the ROW is not a weak standard on
compliance.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: Minimum Inspection Intervals:
FAC 003-1 provides the proper amount of flexibility regarding vegetation inspection
cycles and that the Standards Drafting Team should not impose minimum inspection
intervals on a continent with such regional diversity in climate and plant life.
Requirement 1.1 of standard FAC-003-1 places the responsibility for proper
inspection cycles on the entity that knows the local conditions and can best define what
that inspection frequency should be, the Transmission Owner. Both NERC and the FERC
staff have recognized that various local conditions can have an affect on the
determination of adequate inspection frequencies. Establishing a mandatory minimum
inspection frequency could have two detrimental effects on the industry.
First, where a particular region is heavily forested and has heavy rainfall along with
extended or year round growing seasons, a “back stop” minimum inspection frequency
could lead transmission owners to conduct inspections less frequently than required by
the local conditions. This could result in a Transmission Owner complying with the
standard while not adequately protecting the reliability of that region’s transmission
system. This is a “lowest common denominator” approach which FERC has repeatedly
stated is inappropriate for the reliability standards.
Page 4 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Second, where a particular region is arid, sparsely forested or has a minimum
growing season, a “back stop” minimum could require a more frequent interval than is
realistically needed. This would result in increased and unnecessary costs for electric
utility customers without providing an increase in system reliability.
In its discussion of inspection intervals, FERC indicates that a “one-year vegetation
inspection cycle is reasonable.” FERC NOPR, 10/20/2002 paragraph 383. The
Commission continues by stating “a one-year inspection cycle is the ‘norm’ for the
industry, but not the lowest common denominator…” It follows from this observation
that the industry as a whole recognizes and follows appropriate inspection intervals
without a need to change the standard. Further, FERC also states “some variation to a
continent-wide, one-year minimum inspection cycle should be allowed due to physical
differences such as climate and species of vegetation.” FERC NOPR 10/20/2006,
paragraph 382. FERC’s recognition that a “one size fits all” approach is not appropriate
supports maintaining the existing inspection requirements in standard FAC-003-1.
Finally, the performance metrics of FAC-003 require the reporting of applicable
transmission interruptions that are caused by vegetation. This process will identify
Transmission Owners’ inspection cycles that are not adequate. In this event, the ERO
has the authority to engage the Transmission Owner in enforcement compliance actions
and, therefore, can remedy any vegetation-related outage that is attributed to the
Transmission Owner’s inspection frequency.
Standard Applicability:
The 200 kV threshold for determining facilities subject to this standard should not be
revised.
The transmission facilities below 200 kV have not been cited as impacting bulk power
system reliability. The Final Report on the August 14, 2003 Blackout in the United
states and Canada: Causes and Recommendations April 2004 by the U.S.- Canada
Power System Outage Task Force and all referenced major blackouts(pages 103-115) in
that report, cited only outages which involved vegetation at line voltages above 200 kV.
Generally applying requirements appropriate for 200 kV lines to lines less than 200 kV
will result in significant documentation and reporting of items such as restrictions,
mitigation plans, off right-of-way vegetation-related outage investigation/information
and other issues, all of which dilutes the focus on lines that directly impact bulk power
system reliability.
Revising the standard to use general criteria or broad language for defining "Bulk
Power System" transmission lines covered by the standard could become a “one size fits
all” approach. If that approach were taken, the standard would cover a significant
number of transmission lines that have no direct impact on bulk power system reliability
under standard planning/operating conditions, resulting in a significant increase in costs
for electric customers without improving “Bulk Power System” system reliability. The
SERC VMS believes that the applicability provision of the standard should instead focus
attention of the standard only on the transmission lines below 200 kV that directly
impact “Bulk Power System” reliability, as the current version requires.
The applicability provision of this standard should be revised only if existing system
design, planning or operating reliability criteria and parameters are considered as a basis
for defining the applicability of the standard. To that end, each Regional Entity (RE)
should determine the applicability of FAC-003 to those lines within the region that are
between 100 kV and 200 KV if and only if they are identified as operationally significant
elements of Interconnection Reliability Operating Limits (“IROLs”).
IEEE Standard for Minimum Clearances:
Page 5 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
The IEEE 516-2003 should continue to be used as the minimum acceptable distances for
“Clearance 2”. The IEEE 516-2003 tables are appropriate for defining the minimum
acceptable clearances to prevent flashover between conductors and vegetation under all
rated electrical operating conditions. Closer minimum clearances such as the minimum
length of a support insulator could have been adopted as a “lowest common
denominator” clearance. However the clearance in IEEE 516-2003 was adopted to
ensure an additional margin of reliability. FERC staff references ANSI Z-133 which is a
safety standard that addresses worker safety as well as the safety of the general public.
As such, the purpose of ANSI Z-133 is to address worker safety and is not focused on
transmission line reliability, which is the purpose of FAC-003-1. OSHA, NESC and other
related safety standards have clearances in excess of IEEE 516-2003. Those clearances
are clearly focused on safety issues and will still apply to other aspects of design and
operation of electric facilities (such as public and worker safety) but do not need to be
referenced in a vegetation management reliability standard.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: Standard Applicability:
The outage reporting requirement for the RRO should be deleted. Making FAC-003
applicable to the RRO is in violation of the legislation that established the ERO. This
legislation states that enforceable standards can apply only to owners, users and
operators of the bulk power system. Futher, in the NOPR on NERC standards, FERC
declined to approve those standards that applied to the RROs, in part because the RROs
are not owners, users or operators.
Compliance:
Reporting requirements for Category 3 outages should be eliminated. These outages are
not controllable, not relevant to compliance, not related to grid reliability, not related to
cascading blackouts, and such reporting leads to unnecessarily biasing reliability related
information.
Page 6 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
SERC Vegetation Management Subcommittee
Lead Contact:
Richard Dearman
Contact Organization:
TVA
Contact Segment:
1
Contact Telephone:
256-519-2067
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Jay Farrington
Alabama Electric Coop
SERC
1
Randy Gann
Alabama Power Co.
SERC
1
Raymond Wiesehan
Ameren
SERC
1
John Neagle
Associated Electric Coop
SERC
1
Billy George
Duke Energy Carolinas
SERC
1
Ralph Hale
Entergy
SERC
1
Marc Tunstall
Fayetteville PWC
SERC
1
Jack Gardner
Progress Energy Carolinas
SERC
1
Jerry Lindler
SCE&G
SERC
1
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: The SERC VMS is unsure how to answer the question as it is worded, but
has the following comments on the SAR:
The current standard contains appropriate requirements and measures to ensure the
owners vegetation management program is implemented and managed to ensure the
reliability of the transmission system. Mandating inspection cycle frequencies will not
enhance nor ensure reliability by inspecting more or less frequently. The minimum
vegetation clearances at maximum operating conditions that are established within the
owner's program, which is auditable by the ERO, will ensure reliability. Extending the
requirements to lines other than those >200KV may reduce the focus on those lines and
may cause the allocation of resources away from lines >200KV. Generally easements
are narrower on lower voltage lines, requiring more resources and emphasis on these
lines. This may have an effect on the ability to focus clearing efforts on those lines that
will have a much greater impact on the bulk power system. The IEEE standard when
used as the minimum clearance distance at maximum operating condition will ensure
reliability when these clearances are maintained by vegetation management activities.
In addition, we do not agree that a standard of zero tolerance for vegetaion-related
outages in the ROW is weak on compliance.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: Minimum Inspection Intervals:
The SERC VMS believes that FAC 003-1 provides the proper amount of flexibility
regarding vegetation inspection cycles and that the Standards Drafting Team should not
impose minimum inspection intervals on a continent with such regional diversity in
climate and plant life.
The purpose of Requirement 1.1 of standard FAC-003-1 is to put the responsibility
for proper inspection cycles on the entity that knows the local conditions and can best
define what that inspection frequency should be, the Transmission Owner. Both NERC
and the FERC staff have recognized that various local conditions can have an affect on
the determination of adequate inspection frequencies. Establishing a mandatory
minimum inspection frequency could have two detrimental effects on the industry.
First, where a particular region is heavily forested and has heavy rainfall along with
extended or year round growing seasons, a “back stop” minimum inspection frequency
could lead transmission owners to conduct inspections less frequently than required by
the local conditions. This could result in a Transmission Owner complying with the
Page 4 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
standard while not adequately protecting the reliability of that region’s transmission
system. This is a “lowest common denominator” approach which FERC has repeatedly
stated is inappropriate for the reliability standards.
Second, where a particular region is arid, sparsely forested or has a minimum
growing season, a “back stop” minimum could require a more frequent interval than is
realistically needed. This would result in increased and unnecessary costs for electric
utility customers without providing an increase in system reliability.
In its discussion of inspection intervals, FERC indicates that a “one-year vegetation
inspection cycle is reasonable.” FERC NOPR, 10/20/2002 paragraph 383. The
Commission continues by stating “a one-year inspection cycle is the ‘norm’ for the
industry, but not the lowest common denominator…” It follows from this observation
that the industry as a whole recognizes and follows appropriate inspection intervals
without a need to change the standard. Further, FERC also states “some variation to a
continent-wide, one-year minimum inspection cycle should be allowed due to physical
differences such as climate and species of vegetation.” FERC NOPR 10/20/2006,
paragraph 382. FERC’s express recognition that a “one size fits all” approach is not
appropriate further supports the SERC VMS’s contention that the existing inspection
requirements in standard FAC-003-1 should remain unchanged.
Finally, the performance metrics of FAC-003 require the reporting of applicable
transmission interruptions that are caused by vegetation. This process should
appropriately identify Transmission Owners’ inspection cycles that are not adequate. In
this event, the ERO has the authority to engage the Transmission Owner in enforcement
compliance actions and, therefore, can remedy any vegetation-related outage that is
attributed to the Transmission Owner’s inspection frequency.
Standard Applicability:
The SERC VMS disagrees with the proposal to revise the 200 kV threshold for
determining facilities subject to this standard.
The majority of transmission facilities below 200 kV have significantly different
design/construction/operating characteristics and have not been cited as impacting bulk
power system reliability. For example, the Final Report on the August 14, 2003 Blackout
in the United states and Canada: Causes and Recommendations April 2004 by the U.S.Canada Power System Outage Task Force and all referenced major blackouts(pages 103115) in that report, cited only outages which involved vegetation at line voltages above
200 kV. Generally applying requirements appropriate for 200 kV lines to lines less than
200 kV will result in significant documentation and reporting of items such as
restrictions, mitigation plans, off right-of-way vegetation-related outage
investigation/information and other issues, all of which dilutes the focus on lines that
directly impact bulk power system reliability.
Revising the standard to use general criteria or broad language for defining "Bulk
Power System" transmission lines covered by the standard could become a “one size fits
all” approach. If that approach were taken, the standard would cover a significant
number of transmission lines that have no direct impact on bulk power system reliability
under standard planning/operating conditions, resulting in a significant increase in costs
for electric customers without improving “Bulk Power System” system reliability. The
SERC VMS believes that the applicability provision of the standard should instead focus
attention of the standard only on the transmission lines below 200 kV that directly
impact “Bulk Power System” reliability, as the current version requires.
In sum, while the SERC VMS recognizes some validity in the Commission’s concern,
the SERC VMS recommends that the applicability provision of this standard should be
revised only if existing system design, planning or operating reliability criteria and
parameters are considered as a basis for defining the applicability of the standard. To
Page 5 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
that end, the SERC VMS recommends each Regional Entity (RE) determine applicability
of FAC-003 to those lines within the region that are between 100 kV and 200 KV if and
only if they are identified as operationally significant elements of Interconnection
Reliability Operating Limits (“IROLs”).
IEEE Standard for Minimum Clearances:
The SERC VMS disagrees with objections in the FERC staff report to the use of the IEEE
516-2003 clearance as the minimum acceptable distances for “Clearance 2”. The IEEE
516-2003 tables are appropriate for defining the minimum acceptable clearances to
prevent flashover between conductors and vegetation under all rated electrical operating
conditions. Closer minimum clearances such as the minimum length of a support
insulator could have been adopted as a “lowest common denominator” clearance.
However the clearance in IEEE 516-2003 was adopted to ensure an additional margin of
reliability. FERC staff references ANSI Z-133 which is a safety standard that addresses
worker safety as well as the safety of the general public. As such, the purpose of ANSI
Z-133 is to address worker safety and is not focused on transmission line reliability,
which is the purpose of FAC-003-1. OSHA, NESC and other related safety standards
have clearances in excess of IEEE 516-2003. Those clearances are clearly focused on
safety issues and will still apply to other aspects of design and operation of electric
facilities (such as public and worker safety) but do not need to be referenced in a
vegetation management reliability standard.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: Standard Applicability:
The outage reporting requirement for the RRO should be deleted. Making FAC-003
applicable to the RRO is in violation of the legislation that established the ERO. This
legislation states that enforceable standards can apply only to owners, users and
operators of the bulk power system. Futher, in the NOPR on NERC standards, FERC
declined to approve those standards that applied to the RROs, in part because the RROs
are not owners, users or operators.
Compliance:
The SERC VMS recommends deleting reporting requirements for Category 3 outages.
These outages are not controllable, not relevant to compliance, not related to grid
reliability, not related to cascading blackouts, and such reporting leads to unnecessarily
biasing reliability related information.
Page 6 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Brian Thumm
Organization: ITC Transmission
Telephone:
248.374.7846
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: While there may be "statutory" needs to address (e.g., FERC's request to
modify particular components of the existing Standard), we do not feel there is a
reliability need to do so.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: The Standard Drafting Team should not be given lattitude to "include other
improvements to the standards deemed appropriate by the drafting team." The purpose
of the SAR is to identify the changes contemplated by the need for the Standard
Revision. If there are changes that the SAR requestor would like to make to the
Standard, they should be spelled out in the SAR. If the SAR requestor does not really
know the changes that should be made to the standard, then the SAR should be
withdrawn until the need for a SAR can be adequately justified.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: We think the Standard is fine the way it is.
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
ISO RTO Council Standards Review Committee
Lead Contact:
Charles Yeung
Contact Organization:
Southwest Power Pool
Contact Segment:
2
Contact Telephone:
832-724-6142
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Tom Bowe
PJM
RFC
2
Mike Calimano
NYISO
NPCC
2
Ron Falsetti
IESO
NPCC
2
Matt Goldberg
ISO-NE
NPCC
2
Brent Kingsford
CAISO
WECC
2
Anita Lee
AESO
WECC
2
Steve Myers
ERCOT
ERCOT
2
Bill Phillips
MISO
RFC
2
SERC
MRO
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments:
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: The SRC would suggest that the SAR be clear that it will be a complete
review of the subject requirements: to include the addition, deletion and modification of
requirements as agreed to by public consensus.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
James H. Sorrels, Jr.
Organization: American Electric Power
Telephone:
(614) 716-2370
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: American Electric Power believes that the current standard (when
thoroughly read and understood) is completely adequate to maintain a reliable
transmission system with minimum risk of vegetation-related outages.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: American Electric Power is not aware of any evidence to support a need for
revising the vegetation management standard.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: As stated in responses to questions 1 and 2, AEP believes that the current
standard is adequate and that we are not aware of evidence to support a need for
revising the current vegetation management standard.
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
John R. Kellum, Jr.
Organization: CenterPoint Energy Houston Electric, LLP
Telephone:
713-207-6036
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: CenterPoint Energy disagrees that there is a reliability-related need to
address the proposed revisions to FAC-003-1.
This SAR proposes to establish a minimum vegetation inspection cycle for transmission
facilities throughout the United States. Yet, based upon the location of each utility,
different vegetation and growth rates will be experienced throughout the country.
Placing a time specific vegetation management cycle for all regions does not address the
wide divergence of vegetation and growth rates that each utility must face.
For instance, in certain areas of the country, such as desert areas, vegetation growth
rates are exceedingly small; therefore, vegetation management cycles would likely be
for extended periods of time. Placing a required frequent cycle will unnecessarily
increase the costs to ratepayers. While in other parts of the country, vegetation can
grow rapidly, and there should be shorter periods of time for the vegetation
management cycle.
Based upon these facts, CenterPoint Energy does not believe that adopting a standard
inspection cycle that is applicable to all regions is prudent. However, CenterPoint
Energy understands and supports the concept of standard requirements applicable to all
regions where such standardization is practical and reasonable. In the specific case of
vegetation management, it may be reasonable and practical to establish a national
standard based on maximum number of allowed annual vegetation-caused outages per
100-circuit-miles of transmission. Such a standard would allow utilities flexibility to use
inspection cycles and other practices that are prudent based on each utility's
circumstances while still holding utilities accountable for the results.
The SAR also proposes to change the 200 kV threshold and use of the IEEE standard for
minimum clearances. These requirements were established by a broad consensus of
industry experts. CenterPoint Energy believes the broad industry consensus on these
matters should be respected.
CenterPoint Energy submits the following specific comments:
Minimum inspection cycle, FERC NOPR Paragraph 382CenterPoint Energy disagrees that “complete discretion left to the transmission owners
in determining inspection cycles limits the effectiveness of the Reliability Standard.” The
standard is effective because it requires the transmission owners to balance several
factors to achieve the optimum inspection cycle.
Page 4 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
It is not necessary to specify a specific inspection interval in the standard. The
inspection cycle interval is one component of several conditions to be considered in FAC003-1 Requirement R1.2.1 for establishing the required Clearance 1 of the NERC
standard. Other conditions that should be considered include operating voltage,
appropriate vegetation management techniques, fire risk, reasonably anticipated tree
and conductor movement, species types and growth rates, species failure
characteristics, local climate and rainfall patterns, line terrain and elevation, location of
the vegetation within the span, and worker approach distance requirements. It is the
growth rate of the vegetation coupled with the amount of clearance achieved at the time
of maintenance that determines the inspection cycle interval. As such, the longer the
inspection interval, the larger the clearance that must attained to achieve balance. If
the utility does not achieve balance, then it will likely not avoid vegetation-related
outages. It would not be necessary for a utility to be faulted based on its inspection
interval, rather it would be measured for compliance under FAC-003-1 D2.3.1, D2.3.2,
D2.3.3, and D2.4.1 for operational conditions regarding maintaining the minimum
clearance (Clearance 2) required under FAC-003-1 Requirement R1.2.2 and any actual
vegetation-related outages.
FERC NOPR Paragraph 383CenterPoint Energy disagrees that “a one-year vegetation inspection cycle is the “norm”
for the industry.” The reference to “76 of 161 entities surveyed conduct ground
inspections once a year” was taken from Table 3 entitled “Ground Inspection
Frequency”. The table can also be interpreted to indicate that 78 of 161 entities
surveyed conduct ground inspections on cycles other than once a year. At best, the
table shows a distribution of the varying practices of companies surveyed. The table by
itself does not indicate the level of reliability provided by each of those companies.
The table entries may also be incomplete because the original order under Docket EL0452-000 under paragraph 12c asked “how often the transmission provider inspects that
facility for vegetation management purposes” which did not specify ground or aerial
inspection. The EEI template that many respondents used did specify ground inspection
and aerial inspection separately, but the template was not used by all of the
respondents as noted in the report. Interpolation of the data collected may have
affected the accuracy of the results reported, so specific conclusions should consider the
disparity between how the data request was worded and how the data was reported. It
is important to clearly distinguish between ground inspection, aerial inspection, and
pruning cycle when soliciting and interpreting industry data. Additionally, new
technologies such as airborne laser surveys are coming to the market which may replace
or augment other types of vegetation inspections as they become cost-effective. The
industry “norm” may change as a result.
FERC NOPR Paragraph 384Although CenterPoint Energy does not agree with establishing a “one year minimum
inspection cycle”, it should be left to the discretion of the transmission owner as to what
type of inspection is employed so that the most cost-effective methods can be utilized,
depending on the system’s size and terrain. It should also be made clear that
“inspection cycle” is not intended to mean “pruning cycle”.
Remove 200kV threshold, FERC NOPR Paragraph 385-
Page 5 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
CenterPoint Energy believes the applicability of FAC-003-1 should be “to all transmission
lines operated at 200kV and above and to any lower voltage lines designated by the
regional reliability organization as critical to reliability”, because such a standard most
closely matches the vegetation management reporting requirements from Docket EL0452-000. Voltages below this threshold are not likely to impact the reliability of the Bulk
Power System. Further, regional reliability organizations have the authority to designate
lower voltages critical to reliability as appropriate. The proposed change is unnecessary.
IEEE Standard as basis for minimum clearance to prevent flashover (Clearance 2) CenterPoint Energy believes that the IEEE standard is sufficient and appropriate as a
basis to determine the specific radial clearances to be maintained between vegetation
and conductors under all rated electrical operating conditions (Clearance 2). Clearance
2 also must consider additional clearance for the dynamic movement of the transmission
conductors to avoid vegetation related outages. Thus, the minimum clearances that a
transmission owner must identify and document depend on a variety of conditions
including, but not limited to, transmisison line voltage, temperature, wind velocities, and
altitude.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: CenterPoint Energy does not agree with the scope of the SAR for the
reasons discussed in response to question 1.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 6 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Kathleen Goodman
Organization: ISO New England
Telephone:
(413) 535-4111
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments:
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: ISO New England would suggest that the SAR be clear that it will be a
complete review of the subject requirements: to include the addition, deletion and
modification of requirements as agreed to by public consensus.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Public Service Commission of South Carolina
Lead Contact:
Phil Riley
Contact Organization:
Public Service Commission of South Carolina
Contact Segment:
9
Contact Telephone:
803-896-5154
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Mignon L. Clyburn
Public Service Commission of SC
SERC
9
Elizabeth B. Fleming
Public Service Commission of SC
SERC
9
G. O'Neal Hamilton
Public Service Commission of SC
SERC
9
John E. Howard
Public Service Commission of SC
SERC
9
Randy Mitchell
Public Service Commission of SC
SERC
9
C. Robert Moseley
Public Service Commission of SC
SERC
9
David A. Wright
Public Service Commission of SC
SERC
9
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments:
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: We are concerned that lowering the applicability threshold to all lines below
200KV will divert attention and resources from the higher voltage lines which have a
higher probability of causing grid problems. The RRO and transmission owners best
know which lower voltage lines should be included under the requirements of the
standard.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Robert Coish
Organization: Manitoba Hydro
Telephone:
204-487-5479
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments:
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: The scope of the SAR is too vague on several important points. (1) There is
no definition for the phrase bulk-power system - it would be therefore unclear as to what
facilities would be covered by the standard. What guidance will the SDT have in
determining what is meant by the bulk-power system? Since this relates to the large
issue of the Bulk Electric System versus Bulk-Power System is this SAR the appropriate
vehicle to address this issue? There should be a wider discussion and resolution to this
issue for consistent application to all standards by all SDTs. (2)The concept of Mitigation
Time Horizons has not been defined and the use of Mitigation Time Horizons has not
been detailed. (3)The ERO is not the appropriate entity to determine which lines have an
impact on reliability. This should be Transmission Operators in coordination with
Reliability Coordinators. If this standard is to include the methodology to determine
which lines have a reliability impact on the bulk-power system, the the applicability of
the standard will have to include other entities besides the Transmission Owners. (4)
The SAR refers to RA, i.e., Reliability Authority. This entity no longer exists in the
Functional Model but has been replaced by Reliability Coordinator. (5) What is meant by
"Too weak on compliance"? (5) FERC objects to IEEE Standard but there is no other
guidance to the standard drafting team.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: None identified.
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Roger Champagne
Organization: Hydro-Québec TransÉnergie
Telephone:
514 289-2211; X 2766
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: We believe that it is premature to move forward with changes based on
voltage class. Applicability of the standard should only be to those portions of the
system that are part of the Bulk Power System which have been determined by a
performance based methodology.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: FERC staff report has objection to use IEEE standard. Should we understand
that another standard is recommended instead?
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 4 of 4
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Please use this form to submit comments on the Vegetation Management SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by e-mail
to [email protected] with the words “Vegetation Management” in the subject line. If you
have questions, please contact Richard Schneider at [email protected] or by
telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Group Comments (Complete this page if comments are from a group.)
Group Name:
South Carolina Electric & Gas Company
Lead Contact:
Jerry Lindler
Contact Organization:
Electric Transmission
Contact Segment:
1
Contact Telephone:
803-217-9135
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Lee Xanthakos
SCE&G
SERC
1
Clay Young
SCE&G
SERC
3
Matt Hammond
SCE&G
SERC
6
Rick Jones
SCE&G
SERC
5
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
Background Information:
FAC-003-1 is a relatively new standard that was approved in 2006. FAC-003 has some “fillin-the-blank” components to eliminate. In addition, the following comments submitted by
FERC and stakeholders need to be addressed in the refinement of the standard:
FERC NOPR
- Develop a minimum vegetation inspection cycle that allows variation for physical
differences, as discussed above; and
- Remove the applicability to transmission lines operated at 200 kV and above so that
the Reliability Standard applies to bulk power system transmission lines that have an
impact of reliability as determined by the ERO.
FERC staff report
- Objections to use of IEEE standard
Stakeholder Comments
- Reliability Coordinator vs. Regional Reliability Organization
- Too weak on compliance
- Format inconsistencies
The improvements to the standard should bring the standard’s format and elements into
conformance with the latest version of the Reliability Standards Development Procedure and
the ERO Rules of Procedure.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
Page 3 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area.
Yes
No
Comments: SCE&G is unsure how to interpret the question but would like to offer the
following comments:
The current standard contains appropriate requirements and measures to ensure the
owners vegetation management program is implemented and managed to ensure the
reliability of the transmission system. Mandating inspection cycle frequencies will not
enhance nor ensure reliability by inspecting more or less frequently. The minimum
vegetation clearances at maximum operating conditions that are established within the
owner's program, which is auditable by the ERO, will ensure reliability. Extending the
requirements to lines other than those >200KV may reduce the focus on those lines and
may cause the allocation of resources away from lines >200KV. Generally easements
are narrower on lower voltage lines, requiring more resources and emphasis on these
lines. This may have an effect on the ability to focus clearing efforts on those lines that
will have a much greater impact on the bulk power system. The IEEE standard when
used as the minimum clearance distance at maximum operating condition will ensure
reliability when these clearances are maintained by vegetation management activities.
In addition, we do not agree that a standard of zero tolerance for vegetaion-related
outages in the ROW is weak on compliance.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: Minimum Inspection Intervals:
SCE&G believes that FAC 003-1 provides the proper amount of flexibility regarding
vegetation inspection cycles and that the Standards Drafting Team should not impose
minimum inspection intervals on a continent with such regional diversity in climate and
plant life.
The purpose of Requirement 1.1 of standard FAC-003-1 is to put the responsibility
for proper inspection cycles on the entity that knows the local conditions and can best
define what that inspection frequency should be, the Transmission Owner. Both NERC
and the FERC staff have recognized that various local conditions can have an affect on
the determination of adequate inspection frequencies. Establishing a mandatory
minimum inspection frequency could have two detrimental effects on the industry.
First, where a particular region is heavily forested and has heavy rainfall along with
extended or year round growing seasons, a “back stop” minimum inspection frequency
could lead transmission owners to conduct inspections less frequently than required by
Page 4 of 6
January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
the local conditions. This could result in a Transmission Owner complying with the
standard while not adequately protecting the reliability of that region’s transmission
system. This is a “lowest common denominator” approach which FERC has repeatedly
stated is inappropriate for the reliability standards.
Second, where a particular region is arid, sparsely forested or has a minimum
growing season, a “back stop” minimum could require a more frequent interval than is
realistically needed. This would result in increased and unnecessary costs for electric
utility customers without providing an increase in system reliability.
In its discussion of inspection intervals, FERC indicates that a “one-year vegetation
inspection cycle is reasonable.” FERC NOPR, 10/20/2002 paragraph 383. The
Commission continues by stating “a one-year inspection cycle is the ‘norm’ for the
industry, but not the lowest common denominator…” It follows from this observation
that the industry as a whole recognizes and follows appropriate inspection intervals
without a need to change the standard. Further, FERC also states “some variation to a
continent-wide, one-year minimum inspection cycle should be allowed due to physical
differences such as climate and species of vegetation.” FERC NOPR 10/20/2006,
paragraph 382. FERC’s express recognition that a “one size fits all” approach is not
appropriate further supports the SERC VMS’s contention that the existing inspection
requirements in standard FAC-003-1 should remain unchanged.
Finally, the performance metrics of FAC-003 require the reporting of applicable
transmission interruptions that are caused by vegetation. This process should
appropriately identify Transmission Owners’ inspection cycles that are not adequate. In
this event, the ERO has the authority to engage the Transmission Owner in enforcement
compliance actions and, therefore, can remedy any vegetation-related outage that is
attributed to the Transmission Owner’s inspection frequency.
Standard Applicability:
SCE&G disagrees with the proposal to revise the 200 kV threshold for determining
facilities subject to this standard.
The majority of transmission facilities below 200 kV have significantly different
design/construction/operating characteristics and have not been cited as impacting bulk
power system reliability. For example, the Final Report on the August 14, 2003 Blackout
in the United states and Canada: Causes and Recommendations April 2004 by the U.S.Canada Power System Outage Task Force and all referenced major blackouts(pages 103115) in that report, cited only outages which involved vegetation at line voltages above
200 kV. Generally applying requirements appropriate for 200 kV lines to lines less than
200 kV will result in significant documentation and reporting of items such as
restrictions, mitigation plans, off right-of-way vegetation-related outage
investigation/information and other issues, all of which dilutes the focus on lines that
directly impact bulk power system reliability.
Revising the standard to use general criteria or broad language for defining "Bulk
Power System" transmission lines covered by the standard could become a “one size fits
all” approach. If that approach were taken, the standard would cover a significant
number of transmission lines that have no direct impact on bulk power system reliability
under standard planning/operating conditions, resulting in a significant increase in costs
for electric customers without improving “Bulk Power System” system reliability. SCE&G
believes that the applicability provision of the standard should instead focus attention of
the standard only on the transmission lines below 200 kV that directly impact “Bulk
Power System” reliability, as the current version requires.
In sum, while SCE&G recognizes some validity in the Commission’s concern, we
recommend that the applicability provision of this standard should be revised only if
existing system design, planning or operating reliability criteria and parameters are
considered as a basis for defining the applicability of the standard. To that end, we
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January 15, 2007
Comment Form — 1st Posting of SAR for Revisions to Vegetation
Management FAC-003-1
recommend that each Regional Entity (RE) determine applicability of FAC-003-1 to those
lines within the region that are between 100 kV and 200 KV if and only if they are
identified as operationally significant elements of Interconnection Reliability Operating
Limits (“IROLs”).
IEEE Standard for Minimum Clearances:
SCE&G disagrees with objections in the FERC staff report to the use of the IEEE 5162003 clearance as the minimum acceptable distances for “Clearance 2”. The IEEE 5162003 tables are appropriate for defining the minimum acceptable clearances to prevent
flashover between conductors and vegetation under all rated electrical operating
conditions. Closer minimum clearances such as the minimum length of a support
insulator could have been adopted as a “lowest common denominator” clearance.
However the clearance in IEEE 516-2003 was adopted to ensure an additional margin of
reliability. FERC staff references ANSI Z-133 which is a safety standard that addresses
worker safety as well as the safety of the general public. As such, the purpose of ANSI
Z-133 is to address worker safety and is not focused on transmission line reliability,
which is the purpose of FAC-003-1. OSHA, NESC and other related safety standards
have clearances in excess of IEEE 516-2003. Those clearances are clearly focused on
safety issues and will still apply to other aspects of design and operation of electric
facilities (such as public and worker safety) but do not need to be referenced in a
vegetation management reliability standard.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: Compliance:
The SERC VMS recommends deleting reporting requirements for Category 3 outages.
These outages are not controllable, not relevant to compliance, not related to grid
reliability, not related to cascading blackouts, and such reporting leads to unnecessarily
biasing reliability related information.
Page 6 of 6
January 15, 2007
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
The Transmission Vegetation Management SAR Drafting Team thanks all commenters who
submitted comments on the first draft of the Transmission Vegetation Management SAR.
This SAR was posted for a 30 day public comment period from January 15–February 14,
2007. The Standards Committee asked stakeholders to provide feedback on the standard
through a special standard Comment Form. There were 19 sets of comments, including
comments from more than 80 different people from more than 63 companies representing 7
of the 10 Industry Segments as shown in the table on the following pages.
Based on the comments received, the drafting team revised the SAR to reflect these
comments and improvements identified by the FERC in its Mandatory Reliability Standards
for the Bulk Power System Order 693.
The following major changes were made to the SAR:
Updated the Purpose to use language that matches the associated standard (e.g., where
FAC-003 is only related to the transmission system, the term, ‘bulk power system’ was
replaced with ‘transmission system’).
Added the items NERC is required to address in compliance with FERC Order 693
Added the following items to the list of items to review in refining the standard:
- Review reporting criteria for Category 3 outages in the proposed technical
reference material and may remove the reporting requirement of Category 3
outages in R.3 and R.4.
- Consider deleting requirement R.4.
- Review the reporting exemptions to include all category outages under major
disasters in Requirement R3.2.
Added a commitment to prepare a technical reference such as a “white paper” to aid in
understanding the technical basis for the standard.
The descriptions of the ‘Reliability Functions’ on page 3 of the SAR were updated to
reflect Version 3 of the Functional Model.
In this “Consideration of Comments” document stakeholder comments have been organized
so that it is easier to see the responses associated with each question. All comments
received on the standards can be viewed in their original format at:
http://www.nerc.com/~filez/standards/Vegetation-Management_Project_2007-7.html
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Director of Standards, Gerry Adamski, at
609-452-8060 or at [email protected]. In addition, there is a NERC Reliability
Standards Appeals Process.1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
-1-
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
9
1.
Anita Lee (G2)
AESO
2.
Jay Farrington (G6)
Alabama Electric Coop
9
3.
Randall Gann (G6)
Alabama Power Co.
9
4.
William J. Smith
Allegheny Power
9
5.
Ken Goldsmith (G3)
ALT
6.
Raymond Wiesehan (G6)
Ameren
9
7.
James H. Sorrels, Jr.
American Electric Power
9
8.
John Neagle (G6)
Associate Electric Coop
9
9.
William T. Rees
Baltimore Gas and Electric
9
10.
Brian Bartos
Bandera Electric Coop., Inc.
11.
Michael D. Johnson
Bonneville Power Administration
12.
Dave Rudolph (G3)
BPEC
13.
Brent Kingsford (G2)
CAISO
14.
John R. Kellum, Jr.
CenterPoint Energy Houston
Electric, LLP
9
15.
Michael Spector
Central Hudson Gas & Electric
9
16.
Alan Gale (G1)
City of Tallahassee
17.
Ed Thompson (G4)
ConEd
9
18.
John Loftis
Dominion - Electric Transmission
9
19.
Billy George (G6)
Duke Energy Carolinas
9
20.
Ralph Hale (G6)
Entergy
9
21.
Steve Myers (G2)
ERCOT
22.
Marc Tunstall (G6)
Fayetteville PWC
9
23.
Pedro Modia (G1)
Florida Power and Light Company
9
24.
Barbara Jaindl
Florida Power and Light Company
9
25.
Greg Keller
Florida Power and Light Company
9
26.
John Tamsberg
Florida Power and Light Company
9
27.
Marty Mennes
Florida Power and Light Company
9
28.
Michael Warr
Florida Power and Light Company
9
29.
Eric Senkowicz (G1)
FRCC
30.
Mark Bennett (G1)
Gainesville Regional Utilities
31.
John West (G6)
Georgia Power Co.
9
32.
Jimmy Etheridge (G6)
Georgia Transmission Corporation
9
33.
Steve Burns (G6)
Gulf Power Co.
9
34.
David Kiguel (G4) (I)
Hydro One Networks, Inc.
9
35.
George Juhn
Hydro One Networks, Inc.
9
36.
Roger Champagne (G4) (I)
Hydro-Québec TransÉnergie
9
37.
Ron Falsetti (G2) (G4) (I)
IESO Ontario
9
38.
Bill Shemley (G4)
ISO-NE
9
9
9
9
9
9
9
9
9
9
9
-2-
9
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Commenter
Organization
Industry Segment
1
2
39.
Kathleen Goodman (G4) (I)
ISO-NE
9
40.
Matt Goldberg (G2)
ISO-NE
9
41.
Brian Thumm
ITC Transmission
42.
Clark Hawkins (G1)
Lee County Electric Cooperative
43.
Eric Ruskamp (G3)
LES
44.
Don Nelson (G4)
MA Dept. of Tele. and Energy
3
4
5
6
7
8
9
10
9
9
9
9
9
9
9
9
45.
Robert Coish (G3) (I)
Manitoba Hydro
46.
Tom Mielnik (G3)
MEC
9
47.
Dick Pursley (G3)
Midwest Reliability Organization
9
48.
Bill Phillips (G2)
MISO
49.
Terry Bilke (G3)
MISO
9
50.
Carol Gerou (G3)
MP
9
51.
Joe Knight (G3)
MRO
9
9
52.
Richard Mider
New York State Electric and Gas
Corporation
9
53.
Herb Schrayshuen (G4)
NGRID
9
54.
Murale Gopinathan (G4)
Northeast Utilities
9
55.
Brian Hogue (G4)
NPCC
9
56.
Guy V. Zito (G4)
NPCC
9
57.
Alan Boesch (G3)
NPPD
9
58.
Jerad Barnhart (G4)
NSTAR
59.
Greg Campoli (G4)
NYISO
9
60.
Mike Calimano (G2)
NYISO
9
61.
Ralph Rufrano (G4)
NYPA
62.
Todd Gosnell (G3)
OPPD
63.
Tom Bowe (G2)
PJM
9
9
9
9
9
64.
Jack Gardner (G6) (I)
Progress Energy Carolinas
65.
C. Robert Moseley (G5)
Public Service Commission of SC
9
66.
David A. Wright (G5)
Public Service Commission of SC
9
67.
Elizabeth B. Fleming (G5)
Public Service Commission of SC
9
68.
G. O'Neal Hamilton (G5)
Public Service Commission of SC
9
69.
John E. Howard (G5)
Public Service Commission of SC
9
70.
Mignon L. Clyburn (G5)
Public Service Commission of SC
9
71.
Phil Riley (G5)
Public Service Commission of SC
9
72.
Randy Mitchell (G5)
Public Service Commission of SC
9
73.
Mike Gentry
Salt River Project
9
74.
Jerry Lindler (G6)
SCE&G
9
75.
John Wolfmeyer (G6)
SERC Vegetation Management
Subcommittee
76.
Sam Stonerock
Southern California Edison
9
77.
Jim Busbin (G7)
Southern Company Transmission
9
-3-
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
78.
JT Wood (G7)
Southern Company Transmission
9
79.
Marc Butts (G7)
Southern Company Transmission
9
80.
Roman Carter
Southern Company Transmission
9
81.
Charles Yeung (G2)
SPP
82.
Richard Dearman (G6) (I)
TVA
83.
Jim Haigh (G3)
WAPA
9
84.
Neal Balu (G3)
WPSR
9
85.
Pam Oreschnick (G3)
XEL
9
9
9
G1 – FRCC
G2 - ISO/RTO Council Standards Review Committee
G3 - Midwest Reliability Organization
G4 - NPCC CP9 - Reliability Standards Working Group
G5 – Public Service Commission of South Carolina
G6 - SERC Vegetation Management Subcommittee
G7 – Southern Company Transmission
I – Individual comments were submitted in addition to comments as part of a group
-4-
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Index to Questions, Comments, and Responses
1. Do you agree that there is a reliability-related need to address the proposed revisions to
FAC-003-1 — Transmission Vegetation Management? If not, please explain in the
comment area. ................................................................................................... 6
2. Do you agree with the scope of the SAR? If not, please explain in the comment area. .18
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project? ............................................................35
-5-
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
1. Do you agree that there is a reliability-related need to address the proposed revisions to FAC-003-1 — Transmission
Vegetation Management? If not, please explain in the comment area.
Summary Consideration: Most commenters indicated that they do not believe there is a reliability need to revise the
technical aspects of this standard. The SAR Drafting Team agrees with commenters who indicated that the original was SAR
vague, and the drafting team modified the SAR to clarify that the proposed changes to this standard will address procedural
updates to bring the standard into conformance with the latest version of NERC’s Reliability Standards Development
Procedure and the Sanctions Guidelines in the ERO Rules of Procedure, and will also address the issues raised in the FERC’s
March 16, 2007 Order 693 - Mandatory Reliability Standards for the Bulk Power System.
Question #1
Commenter
Bonneville Power
Administration
Yes
No
;
Comment
Ok, Yes and No. The first FERC NOPR bullet needs to be addressed.
The second bullet is clearly discribed in the standard. A. 4.4.3. The reader must
read the statement in context. It meets the Standard Review Guidelines.
Response:
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to <200kV is necessary.
The Drafting Team does not agree that the Standard Review Guidelines have been met. For example the guidelines calls for ‘time
horizons’ to be assigned to each requirement, and the standard currently does not have these. The standard also needs to replace
its ‘levels of non-compliance’ with ‘violation severity levels’ to support the latest version of the Sanctions Guidelines.
Bandera Electric Coop.
;
The items listed as potential revisions are vague and do not provide sufficient
justification to alter the current requirements of this standard which has been in
effect less than 1 year. The current standard allows for the region to determine
which transmission lines are critical to reliability and should be included in a
Transmission Owner's Transmission Vegetation Management Plan regardless of
voltage classification. The current standard also allows each TO the flexibility to
develop its plan in accordance with its specific geography and operating
environment. There is no need to be more prescriptive.
Response:
The Drafting Team agrees that the first SAR draft was vague. The Drafting Team believes a revised standard is justified because it
needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to <200kV is necessary.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
-6-
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
Standards for the Bulk Power System.
ITC Transmission
While there may be "statutory" needs to address (e.g., FERC's request to modify
;
particular components of the existing Standard), we do not feel there is a reliability
need to do so.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
Hydro One Networks, Inc.
We believe that at this time it is premature to move forward with changes to the
;
standard that are based on voltage class issues. The Standard, as developed,
applies to the BES which have been determined by a performance based
methodology. NERC should wait until the BES vs. BPS issue is resolved.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
We believe that it is premature to move forward with changes based on voltage
Hydro-Québec TransÉnergie
;
class. Applicability of the standard should only be to those portions of the system
that are part of the Bulk Power System which have been determined by a
performance based methodology.
Response:
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to <200kV is necessary.
Northeast Power
NPCC participating members believe that it is premature to move forward with
Coordinating Council
changes based on voltage class. Applicability of the standard should only be to
;
those portions of the system that are part of the Bulk Power System which have
been determined by a performance based methodology.
Response:
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to <200kV is necessary.
American Electric Power
American Electric Power believes that the current standard (when thoroughly read
;
and understood) is completely adequate to maintain a reliable transmission system
with minimum risk of vegetation-related outages.
-7-
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following NEW procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
The current draft FAC 003 1 will provide a high level of reliability for the
New York State Electric and
Gas Corporation
transmission bulk delivery system which the public now expects. After a
;
comprehensive industry review which included industry balloting, the current
Vegetation Management Standard 003 1 was approved in Feburary 2006 and
several sections did not go in to effect for one year (2007). Sufficient time should
be allowed so that impact of the current standard can be monitored.
FAC 003 1 was designed to prevent cascading type outages and by establishing a
standard for 200KV lines and above catastrophic type power outages will be
eliminated. Lower volatge lines can be placed under this standard when the impact
on the bulk delivery system requires tighter management as determined by local
reliability organizations. Inspection cycles must be designed to meet regional
needs based on local conditons, and the current standard provides this flexiblity.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following NEW procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to <200kV is necessary.
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
SERC Reliability Corporation
The SERC VMS is unsure how to answer the question as it is worded, but has the
; ;
following comments on the SAR:
The current standard contains appropriate requirements and measures to ensure
the owners vegetation management program is implemented and managed to
ensure the reliability of the transmission system. Mandating inspection cycle
-8-
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
frequencies will not enhance nor ensure reliability by inspecting more or less
frequently. The minimum vegetation clearances at maximum operating conditions
that are established within the owner's program, which is auditable by the ERO, will
ensure reliability. Extending the requirements to lines other than those >200KV
may reduce the focus on those lines and may cause the allocation of resources
away from lines >200KV. Generally easements are narrower on lower voltage lines,
requiring more resources and emphasis on these lines. This may have an effect on
the ability to focus clearing efforts on those lines that will have a much greater
impact on the bulk power system. The IEEE standard when used as the minimum
clearance distance at maximum operating condition will ensure reliability when
these clearances are maintained by vegetation management activities. In addition,
we do not agree that a standard of zero tolerance for vegetaion-related outages in
the ROW is weak on compliance.
Response:
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team agrees with the commenter and recognizes that the IEEE standard is applicable.
The Drafting Team modified the SAR to eliminate the comment that the standard is weak on compliance as this comment was
satisfied when Version 1 of the standard was developed.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
The current standard contains appropriate levels of guidelines and penalties to
Progress Energy
;
ensure the owners vegetation management program is implemented and managed
to ensure the reliability of the transmission system. Mandating inspection cycle
frequencies will not enhance nor ensure reliability by inspecting more or less
frequently. The minimum vegetation clearances at maximum operating conditions
that are established within the owner's program that are auditable by the ERO will
ensure reliability. By adding lines other than those >200KV may reduce the focus
on those lines and impact the budget dollars allocated to focus on the lines
>200KV. Generally easements are much more narrow on lower voltage lines, the
impact on budget dollars would often require more emphasis on these lines. This
may have an effect on the ability to focus clearing efforts on those lines that will
have a much greater impact on the bulk power system. The IEEE standard when
used as the minimum clearance distance at maximum operating condition will
ensure reliability when these clearances are maintained by vegetation management
activities.
-9-
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
Response:
The current version of the standard does not include ‘time horizons’ and uses ‘levels of non-compliance’ rather than ‘violation
severity levels’ - ‘time horizons’ and ‘violation severity levels’ are needed to conform to the latest version of the Sanctions
Guidelines included in the ERO Rules of Procedure.
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team agrees with the commenter and recognizes that the IEEE standard is applicable.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
CenterPoint Energy disagrees that there is a reliability-related need to address the
CenterPoint Energy Houston
Electric, LLP
proposed revisions to FAC-003-1.
;
This SAR proposes to establish a minimum vegetation inspection cycle for
transmission facilities throughout the United States. Yet, based upon the location
of each utility, different vegetation and growth rates will be experienced
throughout the country. Placing a time specific vegetation management cycle for
all regions does not address the wide divergence of vegetation and growth rates
that each utility must face.
For instance, in certain areas of the country, such as desert areas, vegetation
growth rates are exceedingly small; therefore, vegetation management cycles
would likely be for extended periods of time. Placing a required frequent cycle will
unnecessarily increase the costs to ratepayers. While in other parts of the country,
vegetation can grow rapidly, and there should be shorter periods of time for the
vegetation management cycle.
Based upon these facts, CenterPoint Energy does not believe that adopting a
standard inspection cycle that is applicable to all regions is prudent. However,
CenterPoint Energy understands and supports the concept of standard
requirements applicable to all regions where such standardization is practical and
reasonable. In the specific case of vegetation management, it may be reasonable
and practical to establish a national standard based on maximum number of
allowed annual vegetation-caused outages per 100-circuit-miles of transmission.
Such a standard would allow utilities flexibility to use inspection cycles and other
practices that are prudent based on each utility's circumstances while still holding
utilities accountable for the results.
- 10 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
The SAR also proposes to change the 200 kV threshold and use of the IEEE
standard for minimum clearances. These requirements were established by a
broad consensus of industry experts. CenterPoint Energy believes the broad
industry consensus on these matters should be respected.
CenterPoint Energy submits the following specific comments:
Minimum inspection cycle, FERC NOPR Paragraph 382CenterPoint Energy disagrees that “complete discretion left to the transmission
owners in determining inspection cycles limits the effectiveness of the Reliability
Standard.” The standard is effective because it requires the transmission owners
to balance several factors to achieve the optimum inspection cycle.
It is not necessary to specify a specific inspection interval in the standard. The
inspection cycle interval is one component of several conditions to be considered in
FAC-003-1 Requirement R1.2.1 for establishing the required Clearance 1 of the
NERC standard. Other conditions that should be considered include operating
voltage, appropriate vegetation management techniques, fire risk, reasonably
anticipated tree and conductor movement, species types and growth rates, species
failure characteristics, local climate and rainfall patterns, line terrain and elevation,
location of the vegetation within the span, and worker approach distance
requirements. It is the growth rate of the vegetation coupled with the amount of
clearance achieved at the time of maintenance that determines the inspection cycle
interval. As such, the longer the inspection interval, the larger the clearance that
must attained to achieve balance. If the utility does not achieve balance, then it
will likely not avoid vegetation-related outages. It would not be necessary for a
utility to be faulted based on its inspection interval, rather it would be measured
for compliance under FAC-003-1 D2.3.1, D2.3.2, D2.3.3, and D2.4.1 for
operational conditions regarding maintaining the minimum clearance (Clearance 2)
required under FAC-003-1 Requirement R1.2.2 and any actual vegetation-related
outages.
FERC NOPR Paragraph 383-
- 11 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
CenterPoint Energy disagrees that “a one-year vegetation inspection cycle is the
“norm” for the industry.” The reference to “76 of 161 entities surveyed conduct
ground inspections once a year” was taken from Table 3 entitled “Ground
Inspection Frequency”. The table can also be interpreted to indicate that 78 of 161
entities surveyed conduct ground inspections on cycles other than once a year. At
best, the table shows a distribution of the varying practices of companies surveyed.
The table by itself does not indicate the level of reliability provided by each of those
companies.
The table entries may also be incomplete because the original order under Docket
EL04-52-000 under paragraph 12c asked “how often the transmission provider
inspects that facility for vegetation management purposes” which did not specify
ground or aerial inspection. The EEI template that many respondents used did
specify ground inspection and aerial inspection separately, but the template was
not used by all of the respondents as noted in the report. Interpolation of the data
collected may have affected the accuracy of the results reported, so specific
conclusions should consider the disparity between how the data request was
worded and how the data was reported. It is important to clearly distinguish
between ground inspection, aerial inspection, and pruning cycle when soliciting and
interpreting industry data. Additionally, new technologies such as airborne laser
surveys are coming to the market which may replace or augment other types of
vegetation inspections as they become cost-effective. The industry “norm” may
change as a result.
FERC NOPR Paragraph 384Although CenterPoint Energy does not agree with establishing a “one year
minimum inspection cycle”, it should be left to the discretion of the transmission
owner as to what type of inspection is employed so that the most cost-effective
methods can be utilized, depending on the system’s size and terrain. It should also
be made clear that “inspection cycle” is not intended to mean “pruning cycle”.
Remove 200kV threshold, FERC NOPR Paragraph 385CenterPoint Energy believes the applicability of FAC-003-1 should be “to all
transmission lines operated at 200kV and above and to any lower voltage lines
- 12 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
designated by the regional reliability organization as critical to reliability”, because
such a standard most closely matches the vegetation management reporting
requirements from Docket EL04-52-000. Voltages below this threshold are not
likely to impact the reliability of the Bulk Power System. Further, regional
reliability organizations have the authority to designate lower voltages critical to
reliability as appropriate. The proposed change is unnecessary.
IEEE Standard as basis for minimum clearance to prevent flashover (Clearance 2) CenterPoint Energy believes that the IEEE standard is sufficient and appropriate as
a basis to determine the specific radial clearances to be maintained between
vegetation and conductors under all rated electrical operating conditions (Clearance
2). Clearance 2 also must consider additional clearance for the dynamic movement
of the transmission conductors to avoid vegetation related outages. Thus, the
minimum clearances that a transmission owner must identify and document
depend on a variety of conditions including, but not limited to, transmisison line
voltage, temperature, wind velocities, and altitude.
Response:
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team agrees with the commenter and recognizes that the IEEE standard is applicable.
- 13 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Central Hudson Gas &
Electric
Yes
No
Comment
;
The proposed revisions listed under the FERC NOPR do not provide proper
justification to alter the requirements in the current FAC-003-1 document that was
adopted one year ago.
First, "a minimum vegetation inspection cycle that allows variation in physical
difference" is already called for under the current standard. As stated in Section
R1.1. of FAC-003-1, a schedule already should be defined under the transmission
vegetation management program (TVMP). This schedule already allows for
"variation in physical difference" since the current standard states that "this
schedule should be flexible enough to adjust for changing conditions."
Secondly, under Applicability Section 4.3., the current standard already allows for
lines with lower voltage than 200kV to be "designated by the RRO as critical" and
therefore applicable to the standard. Removal of the 200kV benchmark is not
needed.
And lastly, under the FERC staff report, the IEEE standard provides guidance in
clearances and has been the industry standard for many years. If FERC objects to
using this standard then they should provide clearances that can be discussed and
agreed upon by the transmission owners.
Response:
The FERC is no indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team agrees with the commenter and recognizes that the IEEE standard is applicable.
There was no empirical or anecdotal evidence presented by FERC staff to support
Southern California Edison
;
the Commission's view that the reliability of the Bulk Power System will be
enhanced with further revisions to FAC-003-1. This standard was the subject of
vigorous industry debate in a previous SAR. Although it is far from perfect, the
proposed revisions will not improve reliability and may very well damage existing
VM programs.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following NEW procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
- 14 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
The revisions listed in the NOPR and FERC Staff Report do not provide the
Baltimore Gas and Electric
;
necessary justification to alter the requirements in the current FAC-003-1
document. The existing requirements already allow for each utility to specify the
inspection requirements. There is no need to more prescriptive. The existing
requirements already allow for the ERO to designate critical lines less than 200 kV
so removal of the 200 kV benchmark is unecessary. The IEEE Standard is
worthwhile to keep as a benchmark without which there would be no solid guidance
for minimum clearances.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following NEW procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
The FERC is no indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team agrees with the commenter and recognizes that the IEEE standard is applicable.
We are not sure what you are asking? If you are asking whether we support the
Southern Company
Transmission
standard as it exists today-Southern does! If you are asking whether Southern Co.
; ;
supports the changes being recommended in this Standard-we DON"T.
The present standard appears to be serving its intended purpose and the industry
as currently written. The standard should not be revised until it has demonstrated
it is ineffective or inadequate for ensuring the reliability of the nation's transmission
grid.
Any changes to the standard should be based on empirical data rather than the
assumption that the Standard is not serving its intended purpose. The standard
has not been in effect long enough to determine if it is ineffective.
Response:
- 15 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
The Drafting Team agrees that the first SAR draft was vague. The Drafting Team believes a revised standard is justified because it
needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
As worded this question is confusing however the following comments are
TVA
; ;
presented on the SAR:
The current standard contains appropriate requirements and measures to ensure
that vegetation related outages will not cause cascading transmission blackouts.
Mandating new explicit inspection cycle frequencies will not enhance nor ensure
reliability by inspecting more or less frequently. The current minimum vegetation
clearances at maximum operating conditions that are established within the
owner's program, which is auditable by the ERO, is sufficient to prevent vegetation
related cascading transmission
blackouts. Extending the requirements to a much a larger population of lines would
reduce the current focus on the most important lines (those >200 kV). The IEEE
standard when used as the minimum vegetation clearance distance at maximum
operating condition will ensure desired performance of the lines. A standard of zero
tolerance for vegetation related outages in the ROW is not a weak standard on
compliance.
Response:
The Drafting Team agrees that the first SAR draft was vague. The Drafting Team believes a revised standard is justified because it
needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
The FERC is no indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team agrees with the commenter and recognizes that the IEEE standard is applicable.
- 16 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #1
Commenter
Yes
No
Comment
FPL recognizes the need to address the concerns outlined in the NOPR and by the
Florida Power and Light
Company
FERC Staff.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
Public Service Commission of
South Carolina
;
Manitoba Hydro
IESO Ontario
Salt River Project
ISO New England
Dominion - Electric
Transmission
Midwest Reliability
Organization
ISO/RTO Council Standards
Review Committee
Allegheny Power
;
;
;
;
;
;
;
;
;
- 17 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Summary Consideration: Many commenters indicated there is no need to change the applicability of the requirements in
this standard. The FERC indicated that the Standard Drafting Team should review and consider whether a change to the
applicability to voltage <200kV is necessary.
Furthermore, some commenters expressed support for the IEEE standard’s use in the FAC-003-1 Standard while the FERC
declines to endorse the use of the IEEE standard as the ‘only’ minimum clearance. The SAR was revised to indicate that the
Standard Drafting Team will seek to clarify the rationale for the use of the IEEE standard in supplemental reference material
to be prepared as part of the scope of this SAR.
Question #2
Commenter
Bonneville Power
Administration
Yes
No
;
Comment
Since this posting is for comment it would have been nice to provide more
information as to why the FERC staff objects to the IEEE standard (since it meets
the guidelines for as a North America standard. Also, why are stakeholders
concerned with Reliability Coordinators vs. RRO?
Response:
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
The Drafting Team believes a revised standard is justified because it needs to include the following NEW procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity. Making FAC-003 applicable to the RRO is in
violation of the legislation that established the ERO. This legislation states that enforceable standards can apply only to
owners, users and operators of the bulk power system.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
Bandera Electric Coop.
;
;
As submitted, the SAR appears to completely re-open this standard negating many
months of work and industry comment to reach the consensus reflected in the
current FAC-003.
Response:
The ERO Rules of Procedure include the latest versions of the Reliability Standards Development Procedure Manual and the Sanctions
Guidelines. These documents were approved following the approval of FAC-003-1. FAC-003-1 will need to be revised to bring the
standard into conformance with these documents.
Northeast Power
See response to question 1, above.
Coordinating Council
Response: See the drafting team’s response to your comments on question 1.
CenterPoint Energy does not agree with the scope of the SAR for the reasons
CenterPoint Energy Houston
Electric, LLP
discussed in response to question 1.
;
;
- 18 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Response: See the drafting team’s response to
Central Hudson Gas &
Electric
Response: See the drafting team’s response to
American Electric Power
;
;
Comment
your comments on question 1.
See comments above.
your comments on question 1.
American Electric Power is not aware of any evidence to support a need for revising
the vegetation management standard.
Response:
The ERO Rules of Procedure include the latest versions of the Reliability Standards Development Procedure Manual and the Sanctions
Guidelines. These documents were approved following the approval of FAC-003-1. FAC-003-1 will need to be revised to bring the
standard into conformance with these documents.
FRCC
As stated in this SAR comment form, the improvements should be made to bring
;
the standard into conformance with the Reliability Standards Development
Procedure which at this time is version 6.0, adopted by NERC BOT, 11/1/2006. The
SAR scope via the attached Standard Review Guidelines includes two areas not
defined within the procedure. The Mitigation Time Horizons and definitions for the
violation severity levels (VSLs), Lower, Moderate, High and Severe.
We understand the description of Mitigation Time Horizons and definitions for VSLs
are included in the SAR (the concept of Violation Time Horizons is included in the
Sanctions Guidelines, appendix 4B, NERC Compliance Filing to FERC dated October
18th, 2006), but these discrepancies are part of a broader policy issue and since
their use is not clearly stipulated in the NERC Reliability Standards Development
Procedure, including them in the scope of the SAR is premature and will cause
unnecessary confusion to stakeholders and regulators.
The process is requesting the industry to comment on a scope that is defined
outside the reliability standards process and as such is subject to revisions and
interpretations outside the process as well. This appears inappropriate and at the
extreme will lead to inconsistent understanding, measurement and enforcement of
compliance actions.
The Mitigation Time Horizons and VSL levels should be defined in the Reliability
Standards Development Procedure prior to inclusion in the scope of a SAR.
Specific Items Within Current SAR Scope:
- 19 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
The establishment of minimum inspection cycles has been addressed previously, in
the development of the current standard and was found very problematic given the
large variety of vegetative conditions throughout North America. The vegetation
that was identified as a contributing cause to the 2003 Northeast Blackout had
already been identified by previous inspection activities. It was the failure to take
action on the known site conditions that contributed to the event. Therefore, a
minimum inspection cycle would still NOT have prevented or mitigated the scope of
the Blackout.
The current 200 kV threshold ensures that vegetation management efforts are
focused on the critical bulk power transfer lines and that TVM efforts are not diluted
by including additional lower voltage lines. In practicality, the RRO designation
process provides the necessary flexibility to the Regions to address localized areas
where bulk power system reliability may be compromised by lower voltage
vegetation outages. To note as well, Northeast Blackout related vegetation outages
which initiated the cascade occurred on lines that operate at 345 kV, well above the
current threshold.
The FRCC supported the development of Clearance 2, as established in the current
standard, as this was a consensus selection by not only the subject matter experts,
but many industry participants. Picking the ANSI Z133.1 Table 1 or 2 as the NOPR
suggests, could immediately place thousands of miles of transmission lines out of
compliance even though operating data indicates that the lines have performed
satisfactorily for years. The concern would be, the resulting dilution of valuable
industry and regulator resources.
The SAR includes the following stakeholder comment: "Too weak on compliance" .
We caution that we feel the compliance section does need refining, but that in a
world of limited resources should focus on trends in vegetation outages and not
necessarily on single outages. For transmission owners, two outages on a radial
230 kV circuit should not carry the same penalty as eight outages on multiple 230
kV circuits within a network. We would recommend that compliance be refined to
identify trends, relevance and risk probability to help the industry focus their
resources appropriately.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
- 20 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to <200kV is necessary.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability Standards
for the Bulk Power System.
ITC Transmission
The Standard Drafting Team should not be given lattitude to "include other
;
improvements to the standards deemed appropriate by the drafting team." The
purpose of the SAR is to identify the changes contemplated by the need for the
Standard Revision. If there are changes that the SAR requestor would like to make
to the Standard, they should be spelled out in the SAR. If the SAR requestor does
not really know the changes that should be made to the standard, then the SAR
should be withdrawn until the need for a SAR can be adequately justified.
Response:
The Drafting Team agrees and has removed the paragraph in the brief description of the SAR that opened the scope to other
improvements.
ISO/RTO Council Standards
The SRC (ISO-NE) would suggest that the SAR be clear that it will be a complete
Review Committee
review of the subject requirements: to include the addition, deletion and
;
modification of
requirements as agreed to by public consensus.
ISO New England
Response:
The Drafting Team removed the paragraph in the brief description of the SAR that opened the scope to other improvements. The
Drafting Team concurs with consensus of the commenters that the technical elements of this standard are complete. The intent of the
SAR modification is to address FERC issues and to conform to updates in the Reliability Standards Development Procedure and
Sanctions Guidelines.
FERC staff report has objection to use IEEE standard. Should we understand that
Hydro-Québec TransÉnergie
;
;
another standard is recommended instead?
Response:
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
Hydro One Networks, Inc.
To address FERC's objection to use the IEEE standard, it is necessary to clarify the
;
objective of the Vegetation Management Standard. As we understand it, the focus
of the FAC-003-1 standard is system reliability and as such, the responsibility and
authority on defining and applying the safety margins is rightly assigned to the
transmission owner. We request clarification on how employing safety factors will
address reliability and how prescribing minimum clearances within the standard will
- 21 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
improve reliability.
Please note that the Canadian Standards Association is revising standard C22.3 No.
1 - Overhead Systems. The new version will include clearances to vegetation and
the proposed minimum clearances are in alignment with FAC-003-1.
Response:
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
SERC Reliability Corporation
Minimum Inspection Intervals:
;
Progress Energy
;
The SERC VMS (Progress Energy) believes that FAC 003-1 provides the proper
amount of flexibility regarding vegetation inspection cycles and that the Standards
Drafting Team should not impose minimum inspection intervals on a continent with
such regional diversity in climate and plant life.
The purpose of Requirement 1.1 of standard FAC-003-1 is to put the responsibility
for proper inspection cycles on the entity that knows the local conditions and can
best define what that inspection frequency should be, the Transmission Owner.
Both NERC and the FERC staff have recognized that various local conditions can
have an affect on the determination of adequate inspection frequencies.
Establishing a mandatory minimum inspection frequency could have two
detrimental effects on the industry.
First, where a particular region is heavily forested and has heavy rainfall along with
extended or year round growing seasons, a “back stop” minimum inspection
frequency could lead transmission owners to conduct inspections less frequently
than required by the local conditions. This could result in a Transmission Owner
complying with the standard while not adequately protecting the reliability of that
region’s transmission system. This is a “lowest common denominator” approach
which FERC has repeatedly stated is inappropriate for the reliability standards.
Second, where a particular region is arid, sparsely forested or has a minimum
growing season, a “back stop” minimum could require a more frequent interval than
is realistically needed. This would result in increased and unnecessary costs for
electric utility customers without providing an increase in system reliability.
In its discussion of inspection intervals, FERC indicates that a “one-year vegetation
- 22 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
inspection cycle is reasonable.” FERC NOPR, 10/20/2002 paragraph 383. The
Commission continues by stating “a one-year inspection cycle is the ‘norm’ for the
industry, but not the lowest common denominator…” It follows from this
observation that the industry as a whole recognizes and follows appropriate
inspection intervals without a need to change the standard. Further, FERC also
states “some variation to a continent-wide, one-year minimum inspection cycle
should be allowed due to physical differences such as climate and species of
vegetation.” FERC NOPR 10/20/2006, paragraph 382. FERC’s express recognition
that a “one size fits all” approach is not appropriate further supports the SERC
VMS’s contention that the existing inspection requirements in standard FAC-003-1
should remain unchanged.
Finally, the performance metrics of FAC-003 require the reporting of applicable
transmission interruptions that are caused by vegetation. This process should
appropriately identify Transmission Owners’ inspection cycles that are not
adequate. In this event, the ERO has the authority to engage the Transmission
Owner in enforcement compliance actions and, therefore, can remedy any
vegetation-related outage that is attributed to the Transmission Owner’s inspection
frequency.
Standard Applicability:
The SERC VMS disagrees with the proposal to revise the 200 kV threshold for
determining facilities subject to this standard.
The majority of transmission facilities below 200 kV have significantly different
design/construction/operating characteristics and have not been cited as impacting
bulk power system reliability. For example, the Final Report on the August 14,
2003 Blackout in the United states and Canada: Causes and Recommendations
April 2004 by the U.S.- Canada Power System Outage Task Force and all referenced
major blackouts(pages 103-115) in that report, cited only outages which involved
vegetation at line voltages above 200 kV. Generally applying requirements
appropriate for 200 kV lines to lines less than 200 kV will result in significant
documentation and reporting of items such as restrictions, mitigation plans, off
right-of-way vegetation-related outage investigation/information and other issues,
all of which dilutes the focus on lines that directly impact bulk power system
reliability.
- 23 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
Revising the standard to use general criteria or broad language for defining "Bulk
Power System" transmission lines covered by the standard could become a “one
size fits all” approach. If that approach were taken, the standard would cover a
significant number of transmission lines that have no direct impact on bulk power
system reliability under standard planning/operating conditions, resulting in a
significant increase in costs for electric customers without improving “Bulk Power
System” system reliability. The SERC VMS believes that the applicability provision
of the standard should instead focus attention of the standard only on the
transmission lines below 200 kV that directly impact “Bulk Power System”
reliability, as the current version requires.
In sum, while the SERC VMS (Progress Energy) recognizes some validity in the
Commission’s concern, the SERC VMS (Progress Energy) recommends that the
applicability provision of this standard should be revised only if existing system
design, planning or operating reliability criteria and parameters are considered as a
basis for defining the applicability of the standard. To that end, the SERC VMS
recommends each Regional Entity (RE) determine applicability of FAC-003 to those
lines within the region that are between 100 kV and 200 KV if and only if they are
identified as operationally significant elements of Interconnection Reliability
Operating Limits (“IROLs”).
IEEE Standard for Minimum Clearances:
The SERC VMS disagrees with objections in the FERC staff report to the use of the
IEEE 516-2003 clearance as the minimum acceptable distances for “Clearance 2”.
The IEEE 516-2003 tables are appropriate for defining the minimum acceptable
clearances to prevent flashover between conductors and vegetation under all rated
electrical operating conditions. Closer minimum clearances such as the minimum
length of a support insulator could have been adopted as a “lowest common
denominator” clearance. However the clearance in IEEE 516-2003 was adopted to
ensure an additional margin of reliability. FERC staff references ANSI Z-133 which
is a safety standard that addresses worker safety as well as the safety of the
general public. As such, the purpose of ANSI Z-133 is to address worker safety and
is not focused on transmission line reliability, which is the purpose of FAC-003-1.
OSHA, NESC and other related safety standards have clearances in excess of IEEE
516-2003. Those clearances are clearly focused on safety issues and will still apply
- 24 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
to other aspects of design and operation of electric facilities (such as public and
worker safety) but do not need to be referenced in a vegetation management
reliability standard.
Response:
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
Minimum Inspection Intervals:
TVA
;
FAC 003-1 provides the proper amount of flexibility regarding vegetation inspection
cycles and that the Standards Drafting Team should not impose minimum
inspection intervals on a continent with such regional diversity in climate and plant
life.
Requirement 1.1 of standard FAC-003-1 places the responsibility for proper
inspection cycles on the entity that knows the local conditions and can best define
what that inspection frequency should be, the Transmission Owner. Both NERC and
the FERC staff have recognized that various local conditions can have an affect on
the determination of adequate inspection frequencies. Establishing a mandatory
minimum inspection frequency could have two detrimental effects on the industry.
First, where a particular region is heavily forested and has heavy rainfall along with
extended or year round growing seasons, a “back stop” minimum inspection
frequency
could lead transmission owners to conduct inspections less frequently than required
by the local conditions. This could result in a Transmission Owner complying with
the standard while not adequately protecting the reliability of that region’s
transmission
system. This is a “lowest common denominator” approach which FERC has
repeatedly stated is inappropriate for the reliability standards.
Page 5 of 6 January 15, 2007
Second, where a particular region is arid, sparsely forested or has a minimum
growing season, a “back stop” minimum could require a more frequent interval than
is realistically needed. This would result in increased and unnecessary costs for
electric utility customers without providing an increase in system reliability. In its
- 25 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
discussion of inspection intervals, FERC indicates that a “one-year vegetation
inspection cycle is reasonable.” FERC NOPR, 10/20/2002 paragraph 383. The
Commission continues by stating “a one-year inspection cycle is the ‘norm’ for the
industry, but not the lowest common denominator…” It follows from this
observation that the industry as a whole recognizes and follows appropriate
inspection intervals
without a need to change the standard. Further, FERC also states “some variation
to a continent-wide, one-year minimum inspection cycle should be allowed due to
physical differences such as climate and species of vegetation.” FERC NOPR
10/20/2006, paragraph 382. FERC’s recognition that a “one size fits all” approach is
not appropriate supports maintaining the existing inspection requirements in
standard FAC-003-1. Finally, the performance metrics of FAC-003 require the
reporting of applicable
transmission interruptions that are caused by vegetation. This process will identify
Transmission Owners’ inspection cycles that are not adequate. In this event, the
ERO has the authority to engage the Transmission Owner in enforcement
compliance actions and, therefore, can remedy any vegetation-related outage that
is attributed to the Transmission Owner’s inspection frequency.
Standard Applicability:
The 200 kV threshold for determining facilities subject to this standard should not
be revised. The transmission facilities below 200 kV have not been cited as
impacting bulk power system reliability. The Final Report on the August 14, 2003
Blackout in the United
states and Canada: Causes and Recommendations April 2004 by the U.S.- Canada
Power System Outage Task Force and all referenced major blackouts(pages 103115) in that report, cited only outages which involved vegetation at line voltages
above 200 kV. Generally applying requirements appropriate for 200 kV lines to lines
less than 200 kV will result in significant documentation and reporting of items such
as restrictions, mitigation plans, off right-of-way vegetation-related outage
investigation/information and other issues, all of which dilutes the focus on lines
that directly impact bulk power
system reliability. Revising the standard to use general criteria or broad language
for defining "Bulk Power System" transmission lines covered by the standard could
become a “one size fits all” approach. If that approach were taken, the standard
would cover a significant
- 26 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
number of transmission lines that have no direct impact on bulk power system
reliability under standard planning/operating conditions, resulting in a significant
increase in costs for electric customers without improving “Bulk Power System”
system reliability.
The SERC VMS believes that the applicability provision of the standard should
instead focus attention of the standard only on the transmission lines below 200 kV
that directly impact “Bulk Power System” reliability, as the current version requires.
The applicability provision of this standard should be revised only if existing system
design, planning or operating reliability criteria and parameters are considered as a
basis for defining the applicability of the standard. To that end, each Regional Entity
(RE) should determine the applicability of FAC-003 to those lines within the region
that are
between 100 kV and 200 KV if and only if they are identified as operationally
significant elements of Interconnection Reliability Operating Limits (“IROLs”).
IEEE Standard for Minimum Clearances:
Page 6 of 6 January 15, 2007
The IEEE 516-2003 should continue to be used as the minimum acceptable
distances for “Clearance 2”. The IEEE 516-2003 tables are appropriate for defining
the minimum acceptable clearances to prevent flashover between conductors and
vegetation under all
rated electrical operating conditions. Closer minimum clearances such as the
minimum length of a support insulator could have been adopted as a “lowest
common denominator” clearance. However the clearance in IEEE 516-2003 was
adopted to ensure an additional margin of reliability. FERC staff references ANSI Z133 which is a
safety standard that addresses worker safety as well as the safety of the general
public. As such, the purpose of ANSI Z-133 is to address worker safety and is not
focused on transmission line reliability, which is the purpose of FAC-003-1. OSHA,
NESC and other
related safety standards have clearances in excess of IEEE 516-2003. Those
clearances are clearly focused on safety issues and will still apply to other aspects
of design and operation of electric facilities (such as public and worker safety) but
do not need to be
referenced in a vegetation management reliability standard.
Response:
- 27 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
The scope of this SAR would have been better defined if the complete Standard
Midwest Reliability
Organization
Review Form for the Vegetation Management Standard had been included as an
;
;
attachment to the SAR. Several issues in the Standard Review Form for this SAR
were excluded with this posted SAR. For example, issues related to R3.1 and R3.2.
The MRO is also not clear on the scope of the instruction to the SDrafting Team to
"Expand the applicability to include transmission lines operated at 200 kV and
above and other facilities as determined by the ERO so that the Reliability Standard
applies to Bulk-Power System transmission lines that have an impact on reliability"
It is not clear to the MRO what is meant by "as determined by the ERO". What
process will the ERO use? The ERO should use stakeholder input to make this
determination. The current standard is applicable to all transmission lines 200 kV
and above and to any lower voltage lines designated by the RRO as critical to the
electric system in the region. Will the ERO be in a position to assume the
assessment of the criticality of lines less than 200 kV without input from the entities
that have historically operated in each region?
Also, the MRO is not clear on what is included in the term Bulk-Power System.
What guidance will the SDrafting Team have in determining what is meant by the
Bulk-Power System? Since this relates to the large issue of the Bulk Electric
System versus Bulk-Power System is this SAR the appropriate vehicle to address
this issue? There should be a wider discussion and resolution to this issue for
consistent application to all standards by all SDrafting Teams.
Response:
The comments on R3.1 and R3.2 were developed by NERC staff in a previous version of this SAR and these have been deleted from
the revised SAR. Instead, the Standard Drafting Team will apply the Standard Review Guidelines to the Standard.
The comments from the FERC NOPR were removed from the revised SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
Establishing minimum inspection cycles is a very problematic given the large
Florida Power and Light
Company
variety of vegetative conditions throughout North America. In reality most lines are
;
inspected annually for all failure modes including vegetation. The trees that played
a part of the North East Blackout were known and on the radar screen. The utility
- 28 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
failed to take action. The inspection did not prevent the outage from occurring. The
failure to take action on the known site condition was the contributing factor to the
Blackout.
We do not understand the need to establish separate criteria other than the RRO’s
critical designation. A transmission line is either necessary to the system to prevent
an overload situation or it is not. To add lines that might not be critical to the
system would dilute the effort needed to insure that the critical lines are properly
maintained. Since system stability is the focus of the standard, what criteria would
be used to bring additional lower voltage lines under the standard.
When developing Clearance 2, the committee needed to determine a distance at
which a Transmission Owner could be out of compliance even though no
interruption has occurred. In a sense this is the maximum ‘speed limit’ at which the
utility would be in violation. Their criteria was “How close can a tree be and not
cause an outage?” The engineers on the team reviewed scientific data and current
standards. The IEEE MAID standard was the consensus selection of the sub
committee. All parties need to understand that this is one of the building blocks
that would be used in determining the width of an easement or ROW. Picking the
ANSI Z133.1 Table 1 or 2 as the NOPR suggests could immediately place thousands
of miles of transmission lines out of compliance that have performed satisfactorily
for years. The ANSI tables are phase to phase safety calculations when grow-in tree
interruptions are phase to ground situations.
Response:
The FERCis no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
We are concerned that lowering the applicability threshold to all lines below 200KV
Public Service Commission of
South Carolina
will divert attention and resources from the higher voltage lines which have a
;
higher probability of causing grid problems. The RRO and transmission owners best
know which lower voltage lines should be included under the requirements of the
- 29 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
standard.
Response:
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
With respect to the item in the Brief Description section under FERC NOPR:
IESO Ontario
;
“Remove the applicability to transmission lines operated at 200 kV and above so
that the Reliability Standard applies to Bulk Power System transmission lines that
have an impact on reliability as determined by the ERO.” It is the IESO’s view that
requiring the ERO to make these determinations, is inappropriate. We believe the
standard should remain applicable to lines 200 kV and above and lines below 200
kV as determined by the Reliability Coordinator, similar to the PRC-023 standard.
The IESO also suggests that it be made clear in the SAR that it will be a complete
review of the subject requirements: to include the addition, deletion and
modification of requirements, as agreed to by public consensus.
Response:
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to transmission voltage class
<200kV is necessary.
The Drafting Team removed the paragraph in the brief description of the SAR that opened the scope to other improvements. The
Drafting Team concurs with consensus of the commenters that the technical elements of this standard are complete. The intent of the
SAR modification is to address FERC issues and to conform to updates in the Reliability Standards Development Procedure and
Sanctions Guidelines.
We disagree with the proposal from FERC NOPR regarding removing applicability to
Dominion - Electric
Transmission
transmission lines >200kv. The proposal to apply the Standard to lines the ERO
;
deems to have an impact on reliability can create inconsistency between regions
and is a "fill in the blank" requirement. It is not clear whether the proposed change
would increase or decrease the number of transmission lines which are subject to
reportable outages. In addition, we support the Standard's existing language that
limits reporting to locked out lines only.
Response:
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Commission's reccomendation to develop a "minimum" vegetation inspection
Southern California Edison
;
cycle is untimely and their proposal to revise the scope ignores plain language
contained in the standard.
In SCE’s view, the Commission's incessant need to bolt on a "widget count"
requirement (for minimum inspection cylcles) will likely lead to an increased
number of tree-to-line contacts. Unlike the static equipment located in power plants
- 30 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
and substations, trees and foliage in and around Transmission ROWs are subject to
uncontrolable and fairly unpredictable natural forces. Industry debate during the
previous SAR and comments submitted in the recently concluded NOPR
demonstrate this approach is unsound. Transmission Owners in neighboring states
commented that their cycles and trimming protocols vary from year to year and
sometimes circuit to circuit. Instituting a minimum inspection cycle of 3 years (for
example) might appeal to certain TOs because doing so will support a case for
increased rate recovery. But for others, a mandatory 3 year inspection cycle will
offer a potential cost reduction opportunity because they are already following a
voluntary 2 year inspection cycle.
The Commission's other reccomendedation should be rejected because subsection
4.3 clearly covers transmission lines operating below 200 kV. ["….any lower voltage
lines designated by the RRO as critical to the reliabilty of the electric system in the
region.”]
FAC-003-1 requires Transmission Owners to - “define a schedule for and the type
(aerial, ground) of ROW vegetation inspections”. Although the Commission staff
would prefer a specific time duration because it suits their "check list" style of
enforcement, the prudent thing to do is allow TOs the latitude to manage their part
of the bulk system and hold each accountable to the existing compliance measures
in FAC-003-1. Similarly, revising subsection 4.3 in deferrence to the Commission's
or staff's misinterpretation of plain text is unwarranted.
Response:
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle in its March 16, 2007 Order 693 and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The current standard FAC 003 1 should be monitored for one to two full years after
New York State Electric and
Gas Corporation
all segments have been implemented. February 14, 2007 is too soon to determine
;
if a revision is required.
The standard should apply to 200 KV lines and higher voltages to prevent cascading
type power outages.
The IEEE table 516 is referenced as a minimum guide for table 2 clearances. This
table provides clear and measurable distances that can used for audits and
- 31 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
potential compliance issues. The current standard allows enough flexibility so that
the clearance 2 distance can be expanded if a utility feels that is the correct
approach in a specfic region.
The physical differences between electric systems, tree growth rates, local
regulations, climate, and geography make it important to provide a flexible
standard, a "one size fits all" approach will not be effective in the long run.
Response:
The ERO Rules of Procedure include the latest versions of the Reliability Standards Development Procedure Manual and the Sanctions
Guidelines. These documents were approved following the approval of FAC-003-1. FAC-003-1 will need to be revised to bring the
standard into conformance with these documents.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693) and
stakeholders indicated they did not support this change, so it was removed from the SAR.
The scope of the SAR is too vague on several important points.
Manitoba Hydro
;
(1) There is no definition for the phrase bulk-power system - it would be therefore
unclear as to what facilities would be covered by the standard. What guidance will
the SDrafting Team have in determining what is meant by the bulk-power system?
Since this relates to the large issue of the Bulk Electric System versus Bulk-Power
System is this SAR the appropriate vehicle to address this issue? There should be a
wider discussion and resolution to this issue for consistent application to all
standards by all SDrafting Teams.
(2)The concept of Mitigation Time Horizons has not been defined and the use of
Mitigation Time Horizons has not been detailed.
(3)The ERO is not the appropriate entity to determine which lines have an impact
on reliability. This should be Transmission Operators in coordination with Reliability
Coordinators. If this standard is to include the methodology to determine which
lines have a reliability impact on the bulk-power system, the the applicability of the
- 32 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
standard will have to include other entities besides the Transmission Owners.
(4) The SAR refers to RA, i.e., Reliability Authority. This entity no longer exists in
the Functional Model but has been replaced by Reliability Coordinator.
(5) What is meant by "Too weak on compliance"?
(5) FERC objects to IEEE Standard but there is no other guidance to the standard
drafting team.
Response:
The comments regarding Bulk Power System in the FERC NOPR comments were removed from the revised SAR.
The ERO Rules of Procedure require the inclusion of time horizons for each standard – these are defined in the Sanctions Guidelines
and are used to help determine the size of a sanction.
The revised SAR does not include the language proposing that the ERO determine which lines have an impact on reliability.
The reference to Reliability Authority (RA) was removed from the revised SAR.
The reference, ‘Too weak on compliance’ was removed from the revised SAR as it was addressed with the development of Version 1 of
this standard.
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
The scope of the SAR should be limited to formatting and changes of wording that
Southern Company
Transmission
recognize the formation of the ERO and its procedures.
;
The drafting team should not attempt to re-write the present clearance
requirements, which are based on IEEE flashover distances. The clearance
requirements in the orignal standard were written through extensive evaluation and
input from the industry. There was strong industry consensus on the present
language and the standard is serving its intended purpose very well. The clearance
standard should not be revised until it is found to be ineffective or inadequate.
The drafting team should not attempt to change the applicability of the present
standard. The present standard applies to all 200 KV and higher lines, plus any
other line the Regional Entity deems critical. A change in wording to make the
standard apply to any bulk power system transmission line deemed critical by the
ERO does not provide any additional safeguard that is not already contained in the
standard as presently written.
Response:
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
- 33 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #2
Commenter
Yes
No
Comment
standard and the Drafting Team agreed to address their questions and concerns.
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
As noted above.
Baltimore Gas and Electric
;
Response: See response to your question #1 comment above.
Salt River Project
Allegheny Power
;
;
- 34 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
3. Are there additional revisions, beyond those identified in the SAR that should be addressed within the scope of this project?
Summary Consideration: Commenters suggested a number of additional revisions to the SAR related to:
Applicability
Right of Way (ROW) definition
Compliance
Clearance requirements
Others
The SAR Drafting Team revised the SAR to consider these suggested revisions.
Question #3
Commenter
Bonneville Power
Administration
Yes
;
No
Comment
It is not clear if categroy 1 and 2 refer only to occupied ROW, or also to unoccupied
area reserved by the Transmission Owner for future expansion.
Response:
o Category 1 outages refer to “grow-ins” inside or outside the right-of-way regardless; while a Category 2 outage applies to “fall-ins”
on land that is inside the legal bounds of the right-or-way whether occupied or not.
The FERC has directed the ERO to address the definition of ROW in its Order 693.
As part of the SAR, the SAR Drafting Team commits the Standard Drafting Team to prepare technical reference material such as a
“white paper” to aid in understanding the technical basis for the standard and, unless the requirements in the standard are modified
to add more clarity, the SAR Drafting Team will recommend that the white paper include a discussion of the differences between
category 1 and category 2 to address your concern.
FRCC
Requirement 3.2, item (1), the reporting exemption for outages occuring due to
;
natural disaters should be expanded to include all vegetation outages that occur as
a result of the disaster. Currently the exemption applies to vegetation from outside
the ROW.
As a result of significant experience with hurricanes, our operators have found that
this distinction results in a waste of post-disaster resources. The standard currently
requires the owner to investigate and determine the original location of the
vegetation that may have caused an outage. Restoration of circuits may be
delayed and often times, determination of the original location of the vegetation is
not possible.
Response:
The SAR Drafting Team will review the reporting exemptions to all category outages under major disasters in Requirement R3.2.
Northeast Power
Only if the Bulk Power System is determined as an impact based performance
Coordinating Council
based methodology.
;
Response:
- 35 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #3
Commenter
Yes
No
Comment
The FERC looks to the Standard Drafting Team to determine whether a change to the applicability to voltage <200kV is necessary.
The comments regarding Bulk Power System in the FERC NOPR comments were removed from the revised SAR
SERC Reliability Corporation
;
Standard Applicability:
The outage reporting requirement for the RRO should be deleted. Making FAC-003
applicable to the RRO is in violation of the legislation that established the ERO. This
legislation states that enforceable standards can apply only to owners, users and
operators of the bulk power system. Futher, in the NOPR on NERC standards, FERC
declined to approve those standards that applied to the RROs, in part because the
RROs are not owners, users or operators.
Compliance:
The SERC VMS recommends deleting reporting requirements for Category 3
outages. These outages are not controllable, not relevant to compliance, not
related to grid reliability, not related to cascading blackouts, and such reporting
leads to unnecessarily biasing reliability related information.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team intends to review reporting criteria for Category 3 outages in the proposed technical reference material
and may review the reporting requirement of Category 3 outages in R.3 and R.4.
Standard Applicability:
Progress Energy
;
The outage reporting requirement for the RRO should be deleted. Making FAC-003
applicable to the RRO is in violation of the legislation that established the ERO. This
legislation states that enforceable standards can apply only to owners, users and
opeartors of the bulk power system. Futher, in the NOPR on NERC standards, FERC
declined to approve those standards that applied to the RROs, in part because the
RROs are not owners, users or operators.
Compliance:
Progress Energy believes that FAC-003 should focus compliance on the issues that
improve system/grid reliability. The VM standard outage reporting requirements do
not focus on ensuring grid/network reliability.
- 36 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #3
Commenter
Yes
No
Comment
Category 2 outages (“Fall-ins” from vegetation within the R/W) result in a level of
non-compliance (Level 2 or 3). However, “Fall-ins”, either off-R/W or within the
R/W, are random events. They would not occur sequentially (i.e., a fall-in causing
another line section to overload resulting in another “fall-in”) and would not have
the potential to cascade into a widespread blackout. This is a customer reliability
issue for that line, not a grid reliability issue. While it may be worthwhile to report
for tracking and trending, it is not an outage that should result in non-compliance.
Category 1 “Grow-ins” include outages that result from conductor side-wing would
be reported as Category 1 outages, resulting in non-compliance (Level 3 or 4).
However, conductor side-swing outages are random occurrences. They are not the
sequential outages that would have the potential to cascade into a widespread
blackout. This is a customer reliability issue for that line, not a grid reliability issue.
These types of outages should be not be considered any different than numerous
other random events that result in transmission line outages.
Response:
The SAR Drafting Team understands the distinction between grow-in and fall-in related outages and the prediction challenges with
fall-in related outages. Modifying the compliance section is included in the scope of the SAR.
Requirement 3.2 exempts reporting of outages from outside the ROW when natural
Florida Power and Light
Company
disasters such as tornados or hurricanes occur. Our experience with numerous
;
hurricanes indicates that all outages during these types of events should be
exempt. The focus in these situations is to get the lines back in service and restore
customers. There is insufficient manpower to adequately complete the forensics
necessary to determine an accurate root cause. It is not uncommon to find
vegetation debris in the lines or downed trees on the ROW in this situation. In most
cases it is not possible to determine the original location of these trees.
In the compliance section of the document a transmission owner becomes non
compliant with a single category 1 or 2 outage. This occurs regardless of the
circumstances. A non compliant penalty for a single outage in a situation where no
customers were affected and the system could not have been compromised is not
reasonable. It is also not an indicator of a poorly maintained system. We agree that
several Category 1 or 2 interruptions could be an indicator of neglect but one is not.
We recommend that The compliance section be reviewed with this in mind.
Response:
The Standard Drafting Team will review the reporting exemptions to all category outages under major disasters in Requirement
- 37 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #3
Commenter
Yes
No
Comment
R3.2.
Modifying the compliance section is included in the scope of the SAR.
Since the IEEE standard does not appear to be a favorable clearance requirement,
Midwest Reliability
Organization
minimum clearance requirements should be tied to legal documents such as
;
easments, state statute, or permits. This will help Transmission Owners to
maintain their ROWs based on their agreements with the land owners and not rely
on historical ROW management practices. It would also provide flexibility in
clearance requirements based on geopraphical and climatological factors that
influence different regions because landowner agreements will be different
depending on local influences.
Response:
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
TVA
Standard Applicability:
;
The outage reporting requirement for the RRO should be deleted. Making FAC-003
applicable to the RRO is in violation of the legislation that established the ERO. This
legislation states that enforceable standards can apply only to owners, users and
operators of the bulk power system. Further, in the NOPR on NERC standards, FERC
declined to approve those standards that applied to the RROs, in part because the
RROs are not owners, users or operators.
Compliance:
Reporting requirements for Category 3 outages should be eliminated. These
outages are
not controllable, not relevant to compliance, not related to grid reliability, not
related to cascading blackouts, and such reporting leads to unnecessarily biasing
reliability related information.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
The Standard Drafting Team intends to review reporting criteria for Category 3 outages in the proposed technical reference material
and may review the reporting requirement of Category 3 outages in R.3 and R.4.
- 38 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #3
Commenter
Bandera Electric Coop.
Yes
No
;
Response: See response to Comment #2.
ITC Transmission
;
Comment
See Comment #2
We think the Standard is fine the way it is.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
American Electric Power
As stated in responses to questions 1 and 2, AEP believes that the current standard
;
is adequate and that we are not aware of evidence to support a need for revising
the current vegetation management standard.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will address improvements identified by the FERC in its Order 693 - Mandatory Reliability Standards for
the Bulk Power System.
Although SCE is wholly dissatisfied with the integration of IEEE 516-2003 into FACSouthern California Edison
;
003-1 and looks forward to the day when qualified industry professionals and utility
arborists are provided an opportunity to develop a reasonable and scientifically
sound method for determining “minimum” tree-to-line clearances, we believe this
standard should be allowed to “soak” a bit before subjecting it to further revision.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels.
The Standard Drafting Team will address improvements identified by the FERC in its Order 693 - Mandatory Reliability Standards for
the Bulk Power System.
The Drafting Team recognizes that the IEEE standard is applicable. The FERC staff has questioned the applicability of the IEEE
standard and the Drafting Team agreed to address their questions and concerns.
- 39 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
Question #3
Commenter
New York State Electric and
Gas Corporation
Yes
No
;
Comment
The Vegetation Management Standard FAC 003 1 is comprehensive, and utilities
following the established guidelines will be able to meet FERC's expecation of
preventing bulk power delivery outages by using crisp measurable guidleines that
offer limited flexiblity for varying conditions.
Response:
The Drafting Team believes a revised standard is justified because it needs to include the following procedural changes:
o Re-format FAC-003-1 to conform to the current Standards Development Procedure.
o Remove references to RRO in the standard and substitute a responsible entity.
o Add the compliance elements needed to support the Sanctions Guidelines, including time horizons, and violation severity
levels, etc.
The Standard Drafting Team will also address improvements identified by the FERC in its Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
ISO/RTO Council Standards
Review Committee
Hydro One Networks, Inc.
Allegheny Power
Dominion - Electric
Transmission
CenterPoint Energy Houston
Electric, LLP
ISO New England
Central Hudson Gas &
Electric
Public Service Commission of
South Carolina
Hydro-Québec TransÉnergie
Southern Company
Transmission
IESO Ontario
Salt River Project
Baltimore Gas and Electric
;
;
;
;
;
;
;
;
;
;
;
;
;
- 40 -
Consideration of Comments on Transmission Vegetation Management SAR
(FAC-003-1)
- 41 -
Nomination Form —Transmission Vegetation Management SAR Drafting Team
— Modify Standard FAC-003-1
Please return this form to [email protected] by January 29, 2007. For questions, please
contact Richard Schneider at 609-452-8060 or [email protected].
The drafting team will likely meet the end of February to respond to comments on the SAR.
The complete meeting schedule has not been determined yet. It is expected the teams will
meet several times in 2007 including face-to-face meetings, as well as meetings facilitated
through various remote meeting technologies. All candidates should be prepared to
participate actively at these meetings.
Name:
Organization:
Address:
Office
Telephone:
E-mail:
Please briefly describe your experience and qualifications to serve on the
Transmission Vegetation Management SAR Drafting Team. Candidates should
have expertise in one or more of the following areas: transmission line rights-ofway (ROW) vegetation management or ROW maintenance; transmission line
design and ratings; regulatory or legal considerations in ROW maintenance; or
existing codes and good practices in vegetation management. Previous
experience developing or applying NERC or IEEE standards is beneficial, but not a
requirement.
I represent the
following NERC
Reliability
Region(s) (check
all that apply):
I represent the following Industry Segment (check one):
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, and Provincial Regulatory or other
Government Entities
-1-
10 – Regional Reliability Organizations and Regional Entities
Which of the following Function(s) do you have expertise or responsibilities:
Reliability Coordinator
Transmission Service Provider
Balancing Authority
Transmission Owner
Interchange Authority
Load Serving Entity
Planning Authority or Coordinator
Distribution Provider
Transmission Operator
Purchasing-selling Entity
Generator Operator
Generator Owner
Transmission Planner
Resource Planner
Compliance Monitor
Market Operator
Provide the names and contact information for two references who could attest
to your technical qualifications and your ability to work well in a group.
Name:
Office
Telephone:
Organization:
E-mail:
Name:
Office
Telephone:
Organization:
E-mail:
-2-
Standards Authorization Request Form
Standard Authorization Request Form
Revisions to FAC-003-1 Transmission Vegetation Management Program Project 2007-07
Request Date
January 9, 2007
Revised Date
April 2, 2007
SAR Type (Check a box for each one
that applies.)
SAR Requestor Information
Name Richard Dearman
New Standard
Primary Contact
Revision to existing Standard
Telephone
Richard Dearman
(256) 851-3523
Withdrawal of existing Standard
[email protected]
Urgent Action
Fax
E-mail
Purpose/Industry Need (Describe the purpose of the standard — what the standard will
achieve in support of reliability.)
The purpose of revising this standard is to:
1. Provide an adequate level of reliability for the North American electric transmission
system – by verifying that the standard is complete and that its requirements are set at
an appropriate level to ensure reliability.
2. Incorporate other general improvements described in the attached Standard Review
Guidelines to bring it into conformance with the latest version of the Reliability Standard
Development Procedure and the ERO Sanctions Guidelines.
3. Consider comments received from ERO regulatory authorities and stakeholders, as noted
in the attached review sheets.
4. Satisfy the standards procedure requirement for five-year review of the standards.
SAR- 1
Standards Authorization Request Form
Detailed Description
This is a new standard that was approved in 2006. It has some ‘fill-in-the-blank’ components to eliminate.
In addition, the following comments submitted by FERC and stakeholders need to be addressed in the
refinement of the standard:
FERC Order 693 items
1. To address the issue regarding applicability:
The Standard DT shall work with the reliability entities and the ERO to collect and make
available to the FERC, a list of critical lower voltage transmission lines. (Refer to
Applicability 4.3 section of the standard.)
o The standard DT may consider other criteria in determining applicability of the
standard to sub 200kV lines.
2. To address the issue of clearances for lines on both federal and non-federal lands:
o The standard drafting team shall collect and analyze outage data then consider
defining clearances needed to avoid sustained vegetation-related outages that
would apply to transmission lines crossing both federal and non-federal land.
3. To consider revising the definition of right of way to encompass required clearance areas.
4. To review the suitability of IEEE 516-2003 standard for minimum vegetation clearance.
Procedural items
5. Re-format standard to bring it into conformance with the latest version of the Reliability
Standard Development Procedure and the ERO Sanctions Guidelines.
6. Remove references to RRO in the standard and substitute a responsible entity.
7. Add compliance elements such as time horizons, and violation severity levels.
Stakeholder items
8. The Standard DT shall prepare technical reference material such as a “white paper” to aid in
understanding the technical basis for the standard.
9. The Standard DT shall review reporting criteria for Category 3 outages in the proposed
technical reference material and may remove the reporting requirement of Category 3
outages in R.3 and R.4.
10. The Standard DT shall consider deleting requirement R.4.
11. The Standard DT will review the reporting exemptions to include all category outages under
major disasters in Requirement R3.2.
SAR- 2
Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports interconnection frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced Interchange Schedules between Balancing Authority
Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator
Area..
Resource Planner
Develops a (>one year) plan for the resource adequacy of specific
loads within a Planning Coordinator Area.
Transmission
Planner
Develops a (>one year) plan for the reliability of the
interconnected Bulk Electric System within its portion of the
Planning Coordinator Area.
Transmission
Service Provider
Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).
Transmission Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator Owner
Owns and maintains generation facilities.
Generator Operator
Operates generation unit(s) to provide real and reactive power.
Purchasing-Selling
Entity
Purchases or sells energy, capacity, and all necessary reliabilityrelated services as required.
Market Operator
Interface point for reliability functions with commercial functions.
Load-Serving Entity
Secures energy and transmission (and related reliability-related
services) to serve the End-use Customer.
SAR- 3
Standards Authorization Request Form
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk electric systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk electric systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk electric
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk electric
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk electric systems.
6. Personnel responsible for planning and operating interconnected bulk electric
systems shall be trained, qualified, and have the responsibility and authority to
implement actions.
7. The security of the interconnected bulk electric systems shall be assessed,
monitored and maintained on a wide area basis.
Does the proposed Standard comply with all the following Market Interface
Principles? (Select “yes” or “no” from the drop-down box.)
1. The planning and operation of bulk electric systems shall recognize that reliability is an
essential requirement of a robust North American economy. Yes
2. An Organization Standard shall not give any market participant an unfair competitive
advantage.Yes
3. An Organization Standard shall neither mandate nor prohibit any specific market structure.
Yes
4. An Organization Standard shall not preclude market solutions to achieving compliance with
that Standard. Yes
5. An Organization Standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes
SAR- 4
Standards Authorization Request Form
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Explanation
Regional Differences
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
SAR- 5
Standard Review Guidelines
Standard Review Guidelines
Applicability
Does this reliability standard clearly identify the functional classes of entities responsible for
complying with the reliability standard, with any specific additions or exceptions noted? Where
multiple functional classes are identified is there a clear line of responsibility for each
requirement identifying the functional class and entity to be held accountable for compliance?
Does the requirement allow overlapping responsibilities between Registered Entities possibly
creating confusion for who is ultimately accountable for compliance?
Does this reliability standard identify the geographic applicability of the standard, such as the
entire North American bulk power system, an interconnection, or within a regional entity area?
If no geographic limitations are identified, the default is that the standard applies throughout
North America.
Does this reliability standard identify any limitations on the applicability of the standard based
on electric facility characteristics, such as generators with a nameplate rating of 20 MW or
greater, or transmission facilities energized at 200 kV or greater or some other criteria? If no
functional entity limitations are identified, the default is that the standard applies to all identified
functional entities.
Purpose
Does this reliability standard have a clear statement of purpose that describes how the standard
contributes to the reliability of the bulk power system? Each purpose statement should include a
value statement.
Performance Requirements
Does this reliability standard state one or more performance requirements, which if achieved by
the applicable entities, will provide for a reliable bulk power system, consistent with good utility
practices and the public interest?
Does each requirement identify who shall do what under what conditions and to what outcome?
Measurability
Is each performance requirement stated so as to be objectively measurable by a third party with
knowledge or expertise in the area addressed by that requirement?
Does each performance requirement have one or more associated measures used to objectively
evaluate compliance with the requirement?
If performance results can be practically measured quantitatively, are metrics provided within the
requirement to indicate satisfactory performance?
Technical Basis in Engineering and Operations
Is this reliability standard based upon sound engineering and operating judgment, analysis, or
experience, as determined by expert practitioners in that particular field?
Page 1 of 4
April 2, 2006
Standard Review Guidelines
Completeness
Is this reliability standard complete and self-contained? Does the standard depend on external
information to determine the required level of performance?
Consequences for Noncompliance
In combination with guidelines for penalties and sanctions, as well as other ERO and regional
entity compliance documents, are the consequences of violating a standard clearly known to the
responsible entities?
Clear Language
Is the reliability standard stated using clear and unambiguous language? Can responsible
entities, using reasonable judgment and in keeping with good utility practices, arrive at a
consistent interpretation of the required performance?
Practicality
Does this reliability standard establish requirements that can be practically implemented by the
assigned responsible entities within the specified effective date and thereafter?
Capability Requirements versus Performance Requirements
In general, requirements for entities to have ‘capabilities’ (this would include facilities for
communication, agreements with other entities, etc.) should be located in the standards for
certification. The certification requirements should indicate that entities have a responsibility to
‘maintain’ their capabilities.
Consistent Terminology
To the extent possible, does this reliability standard use a set of standard terms and definitions
that are approved through the NERC reliability standards development process?
If the standard uses terms that are included in the NERC Glossary of Terms Used in Reliability
Standards, then the term must be capitalized when it is used in the standard. New terms should
not be added unless they have a ‘unique’ definition when used in a NERC reliability standard.
Common terms that could be found in a college dictionary should not be defined and added to
the NERC Glossary.
Are the verbs on the ‘verb list’ from the DT Guidelines? If not – do new verbs need to be added
to the guidelines or could you use one of the verbs from the verb list?
Violation Risk Factors (Risk Factor)
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures;
or a requirement in a planning time frame that, if violated, could, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of
Page 2 of 4
April 2, 2006
Standard Review Guidelines
failures, or could place the bulk electric system at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of
the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of a medium risk requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures;
or a requirement in a planning time frame that, if violated, could, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly and adversely
affect the electrical state or capability of the bulk electric system, or the ability to
effectively monitor, control, or restore the bulk electric system. However, violation of a
medium risk requirement is unlikely, under emergency, abnormal, or restoration
conditions anticipated by the preparations, to lead to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the bulk electric system, or the ability to effectively monitor and
control the bulk electric system. A requirement that is administrative in nature;
or a requirement in a planning time frame that, if violated, would not, under the
emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system,
or the ability to effectively monitor, control, or restore the bulk electric system. A
planning requirement that is administrative in nature.
Time Horizon
The drafting team should also indicate the time horizon available for mitigating a violation to the
requirement using the following definitions:
•
Long-term Planning — a planning horizon of one year or longer.
•
Operations Planning — operating and resource plans from day-ahead up to and including
seasonal.
•
Same-day Operations — routine actions required within the timeframe of a day, but not
real-time.
•
Real-time Operations — actions required within one hour or less to preserve the
reliability of the bulk electric system.
•
Operations Assessment — follow-up evaluations and reporting of real time operations.
Violation Severity Levels
The drafting team should indicate a set of violation severity levels that can be applied for the
requirements within a standard. (‘Violation severity levels’ replace existing ‘levels of noncompliance.’) The violation severity levels may be applied for each requirement or combined to
cover multiple requirements, as long as it is clear which requirements are included.
Page 3 of 4
April 2, 2006
Standard Review Guidelines
The violation severity levels should be based on the following definitions:
•
Lower: mostly compliant with minor exceptions — The responsible entity is mostly
compliant with and meets the intent of the requirement but is deficient with respect to one
or more minor details. Equivalent score: 95% to 99% compliant.
•
Moderate: mostly compliant with significant exceptions — The responsible entity is
mostly compliant with and meets the intent of the requirement but is deficient with
respect to one or more significant elements. Equivalent score: 85% to 94% compliant.
•
High: marginal performance or results — The responsible entity has only partially
achieved the reliability objective of the requirement and is missing one or more
significant elements. Equivalent score: 70% to 84% compliant.
•
Severe: poor performance or results — The responsible entity has failed to meet the
reliability objective of the requirement. Equivalent score: less than 70% compliant.
Compliance Monitor
Replace, ‘Regional Reliability Organization’ with ‘Regional Entity’.
Fill-in-the-blank Requirements
Do not include any ‘fill-in-the-blank’ requirements. These are requirements that assign one
entity responsibility for developing some performance measures without requiring that the
performance measures be included in the body of a standard – then require another entity to
comply with those requirements.
Every reliability objective can be met, at least at a threshold level, by a North American
standard. If we need regions to develop regional standards, such as in under-frequency load
shedding, we can always write a uniform North American standard for the applicable functional
entities as a means of encouraging development of the regional standards.
Requirements for Regional Reliability Organization
Do not write any requirements for the Regional Reliability Organization. Any requirements
currently assigned to the RRO should be re-assigned to the applicable functional entity.
Effective Dates
Must be 1st day of 1st quarter after entities are expected to be compliant – must include time to
file with regulatory authorities and provide notice to responsible entities of the obligation to
comply. If the standard is to be actively monitored, time for the Compliance Monitoring and
Enforcement Program to develop reporting instructions and modify the Compliance Data
Management System(s) both at NERC and Regional Entities must be provided in the
implementation plan.
Associated Documents
If there are standards that are referenced within a standard, list the full name and number of the
standard under the section called, ‘Associated Documents’.
Page 4 of 4
April 2, 2006
Standard Review Guidelines
Functional Model Version 3
Review the requirements against the latest descriptions of the responsibilities and tasks assigned
to functional entities as provided in pages 13 through 53 of the draft Functional Model Version
3.
Page 5 of 4
April 2, 2006
Standards Authorization Request Form
Standard Authorization Request Form
Title of Proposed Standard
Program Project 2007-07
Revisions to FAC-003-1 Transmission Vegetation Management
Request Date
January 9, 2007
Revised Date
April 2, 2007
SAR Type (Check a box for each one
that applies.)
SAR Requestor Information
Name Richard Schneider (To be
replaced by SAR DT Chair when the SAR DT is
appointed)Dearman
New Standard
Primary Contact
Revision to existing Standard
Telephone
Richard SchneiderDearman
609-452-8060(256) 851-3523
Withdrawal of existing Standard
[email protected]
[email protected]
Urgent Action
Fax
E-mail
Purpose/Industry Need (Describe the purpose of the standard — what the standard will
achieve in support of reliability.)
The purpose of revising this standard is to:
1. Provide an adequate level of reliability for the North American bulk power systems -electric
transmission system – by verifying that the standard is complete and thethat its requirements are set at
an appropriate level to ensure reliability.
2.Ensure it is enforceable as a mandatory reliability standard with financial penalties - the applicability to
bulk power system owners, operators, and users, and as appropriate particular classes of facilities, is
clearly defined; the purpose, requirements, and measures are results-focused and unambiguous; the
consequences of violating the requirements are clear.
2. Incorporate other general improvements described in the attached Standard Review Guidelines to
bring it into conformance with the latest version of the Reliability Standard Development Procedure
and the ERO Sanctions Guidelines.
3. Consider comments received from ERO regulatory authorities and stakeholders, as noted in the
attached review sheets.
4. Satisfy the standards procedure requirement for five-year review of the standards.
SAR- 1
Standards Authorization Request Form
BriefDetailed Description
This is a new standard that was approved in 2006. It has some ‘fill-in-the-blank’ components to eliminate.
In addition, the following comments submitted by FERC and stakeholders need to be addressed in the
refinement of the standard:
FERC NOPROrder 693 items
-Develop a minimum vegetation inspection cycle that allows variation for physical differences, as
discussed above; and
-Remove the applicability to transmission lines operated at 200 kV and above so that the Reliability
Standard applies to Bulk-Power System transmission lines that have an impact of reliability as
determined by the ERO.
FERC staff report
-Objections to use of IEEE standard
Stakeholder Comments
-RA vs. RRO
-Too weak on compliance
-Format inconsistencies
1. The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.To
address the issue regarding applicability:
The Standard DT shall work with the reliability entities and the ERO to collect and make
available to the FERC, a list of critical lower voltage transmission lines. (Refer to
Applicability 4.3 section of the standard.)
o The standard DT may consider other criteria in determining applicability of the
standard to sub 200kV lines.
2. To address the issue of clearances for lines on both federal and non-federal lands:
o The standard drafting team shall collect and analyze outage data then consider
defining clearances needed to avoid sustained vegetation-related outages that
would apply to transmission lines crossing both federal and non-federal land.
3. To consider revising the definition of right of way to encompass required clearance areas.
4. To review the suitability of IEEE 516-2003 standard for minimum vegetation clearance.
Procedural items
5. Re-format standard to bring it into conformance with the latest version of the Reliability
Standard Development Procedure and the ERO Sanctions Guidelines.
6. Remove references to RRO in the standard and substitute a responsible entity.
7. Add compliance elements such as time horizons, and violation severity levels.
Stakeholder items
8. The Standard DT shall prepare technical reference material such as a “white paper” to aid in
understanding the technical basis for the standard.
9. The Standard DT shall review reporting criteria for Category 3 outages in the proposed
technical reference material and may remove the reporting requirement of Category 3
outages in R.3 and R.4.
10. The Standard DT shall consider deleting requirement R.4.
11. The Standard DT will review the reporting exemptions to include all category outages under
major disasters in Requirement R3.2.
SAR- 2
Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Coordinator
EnsuresResponsible for the real-time operating reliability of the
bulk transmission system within its Reliability Coordinator Area in
coordination with its neighboring Reliability Coordinator’s wide
area. This is the highest reliability authority. view.
Balancing Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within its metered boundarya
Balancing Authority Area and supports systeminterconnection
frequency in real time.
Interchange
Authority
AuthorizesEnsures communication of interchange transactions for
reliability evaluation purposes and coordinates implementation of
valid and balanced Interchange Schedules. between Balancing
Authority Areas.
Planning
AuthorityCoordinato
r
Plans the Bulk Electric System.Assesses the longer-term reliability
of its Planning Coordinator Area..
Resource Planner
Develops a long-term (>one year) plan for the resource adequacy
of specific loads within a Planning Authority area.Coordinator
Area.
Transmission
Planner
Develops a long-term (>one year) plan for the reliability of
transmission systemsthe interconnected Bulk Electric System
within its portion of the Planning Authority area.Coordinator Area.
Transmission
Service Provider
ProvidesAdministers the transmission tariff and provides
transmission services to qualified market participants under
applicable transmission service agreements (e.g., the pro forma
tariff).
Transmission Owner
Owns and maintains transmission facilities.
Transmission
Operator
Operates and maintains the transmission facilities, and executes
switching orders.Ensures the real-time operating reliability of the
transmission assets within a Transmission Operator Area.
Distribution
Provider
Provides and operates the “wires” between the transmission
system and the customer.Delivers electrical energy to the Enduse customer.
Generator Owner
Owns and maintains generation unit(s).facilities.
Generator Operator
Operates generation unit(s) to provide real and performs the
functions of supplying energy and Interconnected Operations
Services.reactive power.
Purchasing-Selling
Entity
The function of purchasingPurchases or sellingsells energy,
capacity, and all necessary Interconnected Operations
Servicesreliability-related services as required.
Market Operator
Integrates energy, capacity, balancing, and transmission
resources to achieve an economic, reliability-constrained
dispatch.Interface point for reliability functions with commercial
functions.
SAR- 3
Standards Authorization Request Form
Load-Serving Entity
Secures energy and transmission (and related
generationreliability-related services) to serve the end user.Enduse Customer.
SAR- 4
Standards Authorization Request Form
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk electric systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk electric systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk electric
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk electric
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk electric systems.
6. Personnel responsible for planning and operating interconnected bulk electric
systems shall be trained, qualified, and have the responsibility and authority to
implement actions.
7. The security of the interconnected bulk electric systems shall be assessed,
monitored and maintained on a wide area basis.
Does the proposed Standard comply with all the following Market Interface
Principles? (Select “yes” or “no” from the drop-down box.)
1. The planning and operation of bulk electric systems shall recognize that reliability is an
essential requirement of a robust North American economy. Yes
2. An Organization Standard shall not give any market participant an unfair competitive
advantage.Yes
3. An Organization Standard shall neither mandate nor prohibit any specific market structure.
Yes
4. An Organization Standard shall not preclude market solutions to achieving compliance with
that Standard. Yes
5. An Organization Standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes
SAR- 5
Standards Authorization Request Form
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Explanation
Regional Differences
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
SAR- 6
Standard Review Guidelines
Standard Review Guidelines
Applicability
Does this reliability standard clearly identify the functional classes of entities responsible for complying
with the reliability standard, with any specific additions or exceptions noted? Where multiple functional
classes are identified is there a clear line of responsibility for each requirement identifying the functional
class and entity to be held accountable for compliance? Does the requirement allow overlapping
responsibilities between Registered Entities possibly creating confusion for who is ultimately accountable
for compliance?
Does this reliability standard identify the geographic applicability of the standard, such as the entire North
American bulk power system, an interconnection, or within a regional entity area? If no geographic
limitations are identified, the default is that the standard applies throughout North America.
Does this reliability standard identify any limitations on the applicability of the standard based on electric
facility characteristics, such as generators with a nameplate rating of 20 MW or greater, or transmission
facilities energized at 200 kV or greater or some other criteria? If no functional entity limitations are
identified, the default is that the standard applies to all identified functional entities.
Purpose
Does this reliability standard have a clear statement of purpose that describes how the standard
contributes to the reliability of the bulk power system? Each purpose statement should include a value
statement.
Performance Requirements
Does this reliability standard state one or more performance requirements, which if achieved by the
applicable entities, will provide for a reliable bulk power system, consistent with good utility practices
and the public interest?
Does each requirement identify who shall do what under what conditions and to what outcome?
Measurability
Is each performance requirement stated so as to be objectively measurable by a third party with
knowledge or expertise in the area addressed by that requirement?
Does each performance requirement have one or more associated measures used to objectively evaluate
compliance with the requirement?
If performance results can be practically measured quantitatively, are metrics provided within the
requirement to indicate satisfactory performance?
Technical Basis in Engineering and Operations
Is this reliability standard based upon sound engineering and operating judgment, analysis, or experience,
as determined by expert practitioners in that particular field?
Completeness
Is this reliability standard complete and self-contained? Does the standard depend on external
information to determine the required level of performance?
Consequences for Noncompliance
Page 1 of 4
January 9April 2, 2006
Standard Review Guidelines
In combination with guidelines for penalties and sanctions, as well as other ERO and regional entity
compliance documents, are the consequences of violating a standard clearly known to the responsible
entities?
Clear Language
Is the reliability standard stated using clear and unambiguous language? Can responsible entities, using
reasonable judgment and in keeping with good utility practices, arrive at a consistent interpretation of the
required performance?
Practicality
Does this reliability standard establish requirements that can be practically implemented by the assigned
responsible entities within the specified effective date and thereafter?
Capability Requirements versus Performance Requirements
In general, requirements for entities to have ‘capabilities’ (this would include facilities for
communication, agreements with other entities, etc.) should be located in the standards for certification.
The certification requirements should indicate that entities have a responsibility to ‘maintain’ their
capabilities.
Consistent Terminology
To the extent possible, does this reliability standard use a set of standard terms and definitions that are
approved through the NERC reliability standards development process?
If the standard uses terms that are included in the NERC Glossary of Terms Used in Reliability Standards,
then the term must be capitalized when it is used in the standard. New terms should not be added unless
they have a ‘unique’ definition when used in a NERC reliability standard. Common terms that could be
found in a college dictionary should not be defined and added to the NERC Glossary.
Are the verbs on the ‘verb list’ from the DT Guidelines? If not – do new verbs need to be added to the
guidelines or could you use one of the verbs from the verb list?
Violation Risk Factors (Risk Factor)
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures;
or a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly cause or contribute to bulk electric
system instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures, or could hinder
restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures;
Page 2 of 4
January 9April 2, 2006
Standard Review Guidelines
or a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly and adversely affect the electrical
state or capability of the bulk electric system, or the ability to effectively monitor, control, or
restore the bulk electric system. However, violation of a medium risk requirement is unlikely,
under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
bulk electric system instability, separation, or cascading failures, nor to hinder restoration to a
normal condition.
Lower Risk Requirement
A requirement that, if violated, would not be expected to adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively monitor and control the bulk
electric system. A requirement that is administrative in nature;
or a requirement in a planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely
affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. A planning requirement that is administrative
in nature.
Mitigation Time Horizon
The drafting team should also indicate the time horizon available for mitigating a violation to the
requirement using the following definitions:
•
Long-term Planning — a planning horizon of one year or longer.
•
Operations Planning — operating and resource plans from day-ahead up to and including
seasonal.
•
Same-day Operations — routine actions required within the timeframe of a day, but not realtime.
•
Real-time Operations — actions required within one hour or less to preserve the reliability of
the bulk electric system.
•
Operations Assessment — follow-up evaluations and reporting of real time operations.
Violation Severity Levels
The drafting team should indicate a set of violation severity levels that can be applied for the
requirements within a standard. (‘Violation severity levels’ replace existing ‘levels of non-compliance.’)
The violation severity levels may be applied for each requirement or combined to cover multiple
requirements, as long as it is clear which requirements are included.
The violation severity levels should be based on the following definitions:
•
Lower: mostly compliant with minor exceptions — The responsible entity is mostly compliant
with and meets the intent of the requirement but is deficient with respect to one or more minor
details. Equivalent score: 95% to 99% compliant.
•
Moderate: mostly compliant with significant exceptions — The responsible entity is mostly
compliant with and meets the intent of the requirement but is deficient with respect to one or
more significant elements. Equivalent score: 85% to 94% compliant.
Page 3 of 4
January 9April 2, 2006
Standard Review Guidelines
•
High: marginal performance or results — The responsible entity has only partially achieved
the reliability objective of the requirement and is missing one or more significant elements.
Equivalent score: 70% to 84% compliant.
•
Severe: poor performance or results — The responsible entity has failed to meet the reliability
objective of the requirement. Equivalent score: less than 70% compliant.
Compliance Monitor
Replace, ‘Regional Reliability Organization’ with ‘Electric Reliability Organization’Regional
Entity’.
Fill-in-the-blank Requirements
Do not include any ‘fill-in-the-blank’ requirements. These are requirements that assign one
entity responsibility for developing some performance measures without requiring that the
performance measures be included in the body of a standard – then require another entity to
comply with those requirements.
Every reliability objective can be met, at least at a threshold level, by a North American
standard. If we need regions to develop regional standards, such as in under-frequency load
shedding, we can always write a uniform North American standard for the applicable functional
entities as a means of encouraging development of the regional standards.
Requirements for Regional Reliability Organization
Do not write any requirements for the Regional Reliability Organization. Any requirements
currently assigned to the RRO should be re-assigned to the applicable functional entity.
Effective Dates
Must be 1st day of 1st quarter after entities are expected to be compliant – must include time to
file with regulatory authorities and provide notice to responsible entities of the obligation to
comply. If the standard is to be actively monitored, time for the Compliance Monitoring and
Enforcement Program to develop reporting instructions and modify the Compliance Data
Management System(s) both at NERC and Regional Entities must be provided in the
implementation plan.
Associated Documents
If there are standards that are referenced within a standard, list the full name and number of the
standard under the section called, ‘Associated Documents’.
Functional Model Version 3
Review the requirements against the latest descriptions of the responsibilities and tasks assigned
to functional entities as provided in pages 13 through 53 of the draft Functional Model Version
3.
Page 4 of 4
January 9April 2, 2006
Maureen E. Long
Standards Process Manager
April 10, 2007
TO:
REGISTERED BALLOT BODY
Ladies and Gentlemen:
Announcement: Comment Period Opens
The Standards Committee (SC) announces the following standards actions:
SAR for Transmission Vegetation Management (Project 2007-07) Posted for 30day Comment Period April 10–May 9, 2007
The SAR for Project 2007-07 proposes modifying the Vegetation Management Standard FAC003-1 to address concerns raised by FERC and stakeholders and to bring the standard into
conformance with the latest version of the Reliability Standards Development Procedure and the
ERO Sanctions Guidelines. Please use the comment form to provide comments on the second
draft of this SAR.
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate. If you
have any questions, please contact me at 813-468-5998 or [email protected].
Sincerely,
Maureen E. Long
cc:
Registered Ballot Body Registered Users
Standards Mailing List
NERC Roster
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 4
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 4
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments:
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments:
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments:
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments:
Page 4 of 4
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Thad K. Ness
Organization: American Electric Power
Telephone:
614-716-2053
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 4
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
Page 3 of 4
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: AEP believes that the current standard (when thoroughly read and
understood) is completely adequate to maintain a reliable transmission system with
minimum risk of vegetation-related outages.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments: Of the three regions in which AEP has transmission facilities, only one RE
has provided a listing of sub-200 kV facilities of what we consider applicable under this
standard.
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments: For Clearance 1, AEP has chosen to use the minimum approach distances
set forth in ANSI Tree Care Standard Z133.1 (rev. October 2000) for persons other
than qualified line-clearance arborists and qualified line-clearance arborist trainees. For
Clearance 2, AEP utilizes the Z133.1 minimum approach distances for qualified line
clearance arborists and qualified line-clearance arborist trainees.
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments: The SAR directs the SDT to collect and analyze outage data as part of an
effort to define clearances for transmission lines on federal and non-federal lands. AEP
believes that the analysis of outage data will be meaningless and unproductive. The
SAR directive presupposes a cause-and-effect relationship between vegetation-related
outages and federal/non-federal land status. On the contrary, AEP believes that
vegetation-related data is more indicative of the effectiveness of the utility's VM
program, in spite of onerous and inordinately expensive measures required on federal
lands.
Page 4 of 4
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Mary Hetz
Organization: Ameren
Telephone:
314-554-3633
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 7
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Ameren Vegetation Management Department
Lead Contact:
Ray Wiesehan
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 7
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments:
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments:
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments:
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments: Ameren does not agree that each of 11 items listed in the SAR are
necessary to improve reliability. The following comments are offered for each of the 11
items identified in the SAR detail description:
1. Standard Applicability:
Ameren disagrees with revising the 200 kV threshold for determining facilities subject
to this standard. Extending the requirements to lines other than those >200kV will
dilute the focus on those lines that impact grid reliability and shift attention to facilities,
<200kV. Utilities generally have an incentive to maintain reliability on lines less than
200kV. State commissions and customer expections for reliable service provide this
incentive. While many facilities above 200kV directly support customer load,
transmission lines below 200kV primarily support customer load, and interruptions to
those facilities reduces load on the grid.
The majority of transmission facilities below 200 kV also have significantly different
design/construction/operating characteristics and have not been cited as impacting bulk
power system reliability. For example, the Final Report on the August 14, 2003
Blackout in the United states and Canada: Causes and Recommendations April 2004 by
the U.S.- Canada Power System Outage Task Force and all referenced major blackouts
(pages 103-115) in that report, cited only outages which involved vegetation at line
Page 4 of 7
Comment Form — Transmission Vegetation Management SAR
voltages above 200kV. Generally applying requirements that are appropriate for
>200kV lines to lines less than 200kV will result in significant documentation and
reporting of items such as restrictions, mitigation plans, off right-of-way vegetationrelated outage investigation/ information and other issues, all of which dilutes the focus
on lines that directly impact bulk power system reliability.
Revising the standard to use general criteria or broad language for defining "Bulk Power
System" transmission lines covered by the standard is a “one size fits all” approach. If
that approach were taken, the standard would cover a significant number of
transmission lines that have no direct impact on bulk power system reliability under
standard planning/operating conditions, resulting in a significant cost burden for
electric customers without improving “grid” reliability. Ameren believes that the
applicability provision of the standard should focus attention of the standard only on
the transmission lines below 200kV that directly impact “Bulk Power System” reliability,
as the current version requires.
Ameren recognizes some validity in the Commission’s concern, Ameren recommends
that the applicability provision of this standard should be revised only if existing system
design, planning or operating reliability criteria and parameters are considered as a
basis for defining the applicability of the standard. Ameren recommends each Regional
Entity (RE) determine applicability of FAC-003 to those lines within the region that are
between 100kV and 200KV, if, and only if, they are identified as operationally
significant elements of Interconnection Reliability Operating Limits (“IROLs”). That is,
any facility below 200kV that by itself would cause an Interconnected Reliability Limit
Violation should the facility
be outaged.
2. Issue of Clearances (Federal vs Non-Federal Lands):
FAC-003-1 presently requires the transmission owner (TO) “identify and document
clearances between vegetation and any overhead, ungrounded supply conductors,
taking into consideration transmission line voltage, the effects of ambient temperature
on conductor sag under maximum design loading, and the effects of wind velocities on
conductor sway.” The intent of this requirement is to ensure adequate clearances to
prevent vegetation related outages. Ameren believes that only the TO has the
technical information required to determine the clearances that are necessary at the
time of VM work and that any “federal lands exemption” to clearances will result in
inadequate clearances for the existing conditions. Consistency in application of the
TO’s clearance requirements, not exceptions, is the only assurance in providing a
uniform and reliable electrical system to meet the nation’s current and future energy
demands.
Any exception for a case by case clearance approach to determine vegetation
management activities/clearances on Federal lands will continue to drive inconsistency
and/or delays associated with vegetation management decisions being driven by
diverse vegetation management practices/beliefs and staff changes at the local level of
Federal agencies. Vegetation-related outages have occurred on Federal lands as a
result of this case by case approach, and if “Bulk Power Transmission System” lines
continue to be addressed on a “case by case” basis on National Forest Service (or any
other Federal lands), those lines will potentially be subject to a higher risk for
vegetation-related outages, resulting in reduced reliability for the “Bulk Power System”.
Ameren believes that reliability of the “Bulk Power System” should have the same focus
on Federal and private lands and that the EEI MOU with federal agencies is the
Page 5 of 7
Comment Form — Transmission Vegetation Management SAR
appropriate vehicle for TO's to identify clearance variances on Ferderal lands, not
exemption language in the standard. The standard should not be used as a mechanism
by federal agencies to impose variances to proven vegetation management practices
and clearances.
3. Defining Right-of-Way:
Ameren agrees that it is appropriate to further address the definition of “right-of-way”.
Corridor widths beyond design clearance requirements have been acquired for a variety
of reasons in the past; future use, property line buffers, etc. Vegetation in those areas
that would normally fall outside of the area necessary for operation of the facility
should not be considered or treated different than vegetation that is outside of a
defined easement/permit area that is designed for the reliable operation of an existing
single line corridor.
4. IEEE Standard for Minimum Clearances:
Ameren disagrees with objections to the use of the IEEE 516-2003 clearance as the
minimum acceptable distances for “Clearance 2”. The IEEE 516-2003 tables are
appropriate for defining the minimum acceptable clearances to prevent flashover
between conductors and vegetation under all rated electrical operating conditions.
FERC staff references ANSI Z-133 which is a safety standard that addresses worker
safety as well as the safety of the general public. As such, the purpose of ANSI Z-133 is
to address worker safety and is not focused on transmission line reliability, which is the
purpose of FAC-003-1. OSHA, NESC and other related safety standards have
clearances in excess of IEEE 516-2003. Those clearances are clearly focused on safety
issues and will still apply to other aspects of design and operation of electric facilities
(such as public and worker safety) but are not appropriate to be referenced in a
vegetation management reliability standard.
5/6/7.
Procedural Items:
Ameren agrees that the procedural items related to formatting RRO references and
additional compliance elements should be addressed by the standard drafting team.
8. Technical Reference Materials:
Ameren agrees that a “white paper” that defines the technical basis for the standard is
appropriate to avoid the potential for differences in interpretation of the standard’s
requirements during the various region's audit processes.
9. Category 3 Outages:
Since the right to control off right-of-way vegetation is generally beyond control of the
transmission owner Ameren believes that the reporting of category 3 outages should be
removed from the requirements.
10. Requirement R4:
Ameren believes that requirement R4 should be deleted from the standard, based on
the ERO formation and the process for delegation of authority to the regional entities.
11. Reporting Exemptions:
Page 6 of 7
Comment Form — Transmission Vegetation Management SAR
Ameren believes that the reporting requirement exemptions for natural disasters should
include all categories of outages. It would, for example, be difficult, without delaying
restoration efforts, to determine if the vegetation from high winds, hurricanes,
tornadoes, etc. is from on or off the "right-of-way".
Page 7 of 7
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
John R. Kellum, Jr.
Organization: CenterPoint Energy Houston Electric, LLC (CenterPoint Energy)
Telephone:
713-207-6036
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 7
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 7
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: CenterPoint Energy does not agree that a revision to the TVM standard is
necessary from a reliability standpoint, and believes that the existing TVM standard is
adequate for that purpose.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments:
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments: CenterPoint Energy has developed a methodology to determine clearance 1
and clearance 2 as described in FAC-003-1 R1.2.1 and R1.2.2. This methodology is
included in a document titled "Specification for Transmission Vegetation Management
Program" dated February 2007. Section 5.1 of that document covers NERC Clearance
1, and Section 5.2 covers NERC Clearance 2. Text and Tables from both Sections 5.1
and 5.2 are shown below:
5.1 NERC CLEARANCE 1
5.1.1
The appropriate clearance to conductors at the time of vegetation
management work is established as Clearance 1 in accordance with NERC Standard
FAC-003-1 Requirement R1.2.1.
5.1.2
Clearance 1 is determined by considering transmission line voltage, the
effects of ambient temperature on conductor sag under maximum design loading, the
effects of wind velocities on conductor sway, and the anticipated average growth rate
of the prevalent tree species within the Company’s service area over a 5-year period.
5.1.2.1
The minimum clearance distance of IEEE Standard 516-2003 Section
4.2.2.3, Minimum Air Insulation Distances without Tools in the Air Gap, is a component
of Clearance 1.
5.1.3
Table 5.1 contains the horizontal clearance components and nominal values
for Clearance 1, and Table 5.2 contains the vertical clearance components and nominal
values for Clearance 1.
Page 4 of 7
Comment Form — Transmission Vegetation Management SAR
Table 5.1
NERC Clearance 1: Horizontal Clearance, feet
Horizontal Clearance Component, Nominal Voltage p-p
69kV 138kV 345kV
Electrical Clearance (1)
2.46
Average 5-Year Horizontal Tree Growth
Average Mid-span Conductor Sway (2)
2.95
4.40
12.00 12.00
12.00
5.98
8.13 10.04
Total
20.44
23.08 26.44
Nominal Horizontal Value (3)
20
23
26
(1) Based on IEEE 516-2003 Table 5 for 69kV & 138kV and Table 7 for 345kV
(2) Based on NESC C2-2007 Rule 233A(1)
(3) May be reduced for site specific tree species or conductor span configuration but
not less than Clearance 2.
Table 5.2
NERC Clearance 1: Vertical Clearance, feet
Vertical Clearance Component, Nominal Voltage p-p
69kV 138kV 345kV
Electrical Clearance (1)
2.46
Average 5-Year Vertical Tree Growth
Average Conductor Final Sag Increase (2)
2.95
4.40
15.75 15.75
15.75
7.52
9.01 10.24
Total
25.73
27.71 30.39
Nominal Vertical Value (3)
26
28
30
(1) Based on IEEE 516-2003 Table 5 for 69kV & 138kV and Table 7 for 345kV
(2) Based on NESC C2-2007 Rule 233A(1)
(3) May be reduced for site specific tree species or conductor span configuration but
not less than Clearance 2.
5.2 NERC CLEARANCE 2
5.2.1
The minimum radial clearance to prevent flashover between vegetation and
conductors is established as Clearance 2 in accordance with NERC Standard FAC-003-1
Requirement R1.2.2.
Page 5 of 7
Comment Form — Transmission Vegetation Management SAR
5.2.2
Clearance 2 is determined by considering transmission line voltage, the
effects of ambient temperature on conductor sag under maximum design loading, and
the effects of wind velocities on conductor sway. Clearance 2 is a radial clearance, so
the vertical component and the horizontal component are both calculated, and the
largest clearance is selected as the prevailing clearance for Clearance 2.
5.2.2.1
The minimum clearance distance of IEEE Standard 516-2003 Section
4.2.2.3, Minimum Air Insulation Distances without Tools in the Air Gap, is a component
of Clearance 2.
5.2.3
Table 5.3 contains the horizontal clearance component, Table 5.4 contains
the vertical clearance component, and Table 5.5 contains the prevailing nominal values
for Clearance 2.
Table 5.3
Horizontal Clearance Component, feet
Horizontal Clearance Component, Nominal Voltage p-p
69kV
138kV 345kV
Electrical Clearance (1)
2.46
2.95
4.40
Average Mid-span Conductor Sway (2)
5.98
8.13 10.04
Total
8.44
11.08 14.44
Nominal Horizontal Value (3)
8
11
14
(1) Based on IEEE 516-2003 Table 5 for 69kV & 138kV and Table 7 for 345kV
(2) Based on NESC C2-2007 Rule 233A(1)
(3) May be reduced for site specific tree species or conductor span configuration but
not less than Clearance 2.
Table 5.4
Vertical Clearance Component, feet
Vertical Clearance Component, Nominal Voltage p-p
69kV
Page 6 of 7
138kV 345kV
Comment Form — Transmission Vegetation Management SAR
Electrical Clearance (1)
2.46
2.95
4.40
Average Conductor Final Sag Increase (2)
7.52
9.01
10.24
9.98
10
11.96
12
14.64
15
Total
Nominal Vertical Value (3)
(1) Based on IEEE 516-2003 Table 5 for 69kV & 138kV and Table 7 for 345kV
(2) Based on NESC C2-2007 Rule 233A(1)
(3) May be reduced for site specific tree species or conductor span configuration but
not less than Clearance 2.
Table 5.5
NERC Clearance 2: Minimum Radial Clearance to Prevent Flashover, feet
Nominal Voltage p-p
69kV 138kV 345kV
10
12
15
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments:
Page 7 of 7
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Weston J Davis
Organization: Central Maine Power an Energey East Company
Telephone:
207 621 3945
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 5
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: The current Vegetation Management Standard FAC-003-1 has been crafted
in such a way as to provide crisp measurable standards that when followed will provide
a high level of power quality for the bulk power delivery system. However, clearances
between conductors and trees required to prevent tree related power outages must be
consistent with each utility’s established standards and if a transmission line passes
through federal, state or locally managed areas this line placement should not impact
the established clearances. Utilities should not be expected to negotiate clearances
with multiple land managers.
The IEEE 516 – 2003 table is an acceptable table to use as the minimum clearance to
prevent a flash over and outages. FAC-003-1 is designed to be a reliability standard
and the industry adheres to OSHA and ANSI standards to protect workers and the
public.
The IEEE 516 – 2003 table lists appropriate distances that should be used to measure
compliance. The standard should continue to provide the flexibility for utility managers
to increase “Clearance 2”.
The definition for right-of-way should be clarified to include only the area that is cleared
and included as routine maintenance.
We agree that there is a need to establish time horizons and clarify violation
levels.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments: The “Northeast Power Coordinating Council Facilities Notification List” may
not be the correct list to be used for this standard. FAC- 003-1 should set a clear
expectation the each Regional Entity will provide their transmission owners a list of
critical lines including any that may be less that 200KV. Will provide list once released
from NPCC.
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments: The clearance 2 was taken directly from IEEE Table 516 – 2003. Clearance
1 is based on “Appendix C – ISO New England Right of way Vegetation Management
Standard”.
Page 4 of 5
Comment Form — Transmission Vegetation Management SAR
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments: The standard FAC-003-1 is intended to create a frame work that will ensure
a uniform level of reliability and at the same time must allow transmission owners to
meet this objective using efficient and cost effective programs. To this end utilities
must have the ability to implement “Clearance 1” distances consistently throughout
their service areas.
The standard should remain focused only on 200 KV and above lines or lines listed as
critical by the Regional Entity.
Inspection cycles are sufficient as listed the current version and allow flexibility to meet
local variability in growth rates and other conditions. Concerns with inspection cycle
length can be addressed in the compliance area
Page 5 of 5
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
CJ Ingersoll
Organization: CECD
Telephone:
713-332-2906
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 4
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 4
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: Modifications to capture the Commissions concerns must be addressed
therefore these actions are appropriate.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments: SERC does not currently have any sub 200 kV critical transmission lines.
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments:
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments: CECD supports continuing to use the 200kV threshold for determining
applicablility of vegetation management criteria. If the standard is deemed to apply to
lower voltages these should only be critical lower voltage transmission facilities as
determined by the Regional Entities's. CECD would also encourage the drafting team to
clarify that the Vegetation Management standards are not applicable to generator
interconnection facilities. In the registration process due to the NERC functional
definitions, Generation Owners/Operators are required to register as Transmission
Owners/Operators because of step-up transformers and other associated
interconnection equipment that was not intended to be subject to the Vegetation
Management program.
Page 4 of 4
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
William T. Rees, Jr.
Organization: Baltimore Gas & Electric
Telephone:
410-291-3479
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 4
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 4
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: I'm not convinced that the elements outlined in the proposal will improve
reliability and have concerns that the proposed modifications may actually reduce the
flexibility that is necessary to promote system reliability or to comply with local
regulations. I would prefer to see more specifics in the proposal before supporting the
modifications.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments: The reason that we do not have a list of critical lines from the RRO may be
that we do not have any lines that fit the criteria.
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments:
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments: We completely disagree with the proposal to eliminate reporting or offright-of-way tree outages. In reality, off-R/W outages can cause many of the same
problems that on R/W outages do if they were to occur at the most inappropriate time.
Granted that they typically do not occur at times of peak load, but they could.
Moreover, many off-R/W tree outages are preventable and should be addressed before
they occur.
Page 4 of 4
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Gene Walton
Organization: Dominion
Telephone:
804-257-4770
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 4
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 4
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: We support reinstating the 200kv threshold for reportable events.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments:
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments:
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments: In response to Stakeholder item #11, we do not support exempting
Category 1 or Category 2 events that occur during natural disasters.
Page 4 of 4
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Greg Rowland
Organization: Duke Energy
Telephone:
704-382-5348
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 5
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: From a reliability perspective, the current standard contains appropriate
requirements and measures to ensure the Transmission Owner's vegetation
management program is implemented and managed to ensure the reliability of the
transmission system. However the standard should be revised to address nonreliability related items that are in the SAR.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments: The SERC region has not identified any lines below 200kV to be critical to
the electrical system in the region. Since no lines have been identified as critical to the
region, no list has been provided to Transmission Owners.
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments:
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments: Regarding the Order 693 items, the applicability provision of the standard
should focus attention of the standard only on the transmission lines 200kV and above,
and those lines below 200kV that directly impact “Bulk Power System” reliability, as the
current version of FAC-003 requires. Each Regional Entity (RE) must determine
applicability of FAC-003 to those lines within the region that are less than 200kV. For
example, transmission lines below 200kV should be considered within the scope of FAC003 if they are identified as operationally significant elements of Interconnection
Reliability Operating Limits (“IROLs”); i.e. an outage of the facility would cause an
Interconnection Reliability Limit Violation.
The Standard DT should address the issue of the necessity of maintaining consistent
clearances for lines on both federal and non-federal lands.
We agree with the use of the IEEE 516-2003 standard for for defining the minimum
acceptable clearances to prevent flashover between conductors and vegetation under
all rated electrical operating conditions.
Page 4 of 5
Comment Form — Transmission Vegetation Management SAR
We believe that the reporting requirement exemptions for natural disasters should
include all categories of outages.
Page 5 of 5
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Paul D. Olivier
Organization: Entergy Corporation
Telephone:
504-365-3653
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 6
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 6
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: The existing FAC-003-1 is flawed and needs revision.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments:
Yes, the Reliability Entity (SERC) has performed its duty in evaluating our transmission
system. SERC has confirmed that Entergy has no lines operating below 200kV that are
critical to system reliability. Entergy has received its "list," but the list is blank.
With respect to applicability, it is inappropriate to set a blunt voltage level criterion for
determining which transmission lines are critical to bulk system reliability. There is no
basis in engineering or in fact for voltage-based categories of applicability. Many lines
operating at 200kV and higher essentially serve only local load, and there may in fact
be some lines operating below 200kV where the standard should be applied. Many
lines of all voltages are redundant and do not even impact local load during an outage.
Therefore, the voltage criterion is overly broad.
To support this statement, Entergy supplies the following facts:
First, during the aftermath of Hurricanes Katrina and Rita, Entergy had (59) 230kV and
500kV lines out of service simultaneously. Additionally, Entergy had (85) 115kV and
161kV lines out of service simultaneously. During the aftermath of Hurricane Rita,
Entergy had (41) 230kV and 500kV lines out of service simultaneously. Additionally,
Entergy had (124) 115kV and 161kV lines out of service simultaneously. Dispite this
overwhelming combination of simultaneous outages, no system-wide cascading
blackout was initiated. Only local load was lost during restoration. This illustrates that
Standard FAC-003-1, as it currently stands placing so much focus and penalty on even
single-contingency outages, is overbroad, arbitrary and capricious.
Second, each year the Entergy transmission system (like all other large electric
utilities) suffers numerous outages from a great number of different sources: material
defects, rot and decay, animal damage, human damage, extreme wind, lightning and,
vegetation. Over the years 2001 through 2006, 927 transmission lines suffered 5,688
outages from a variety of sources. Vegetation outages accounted for 7.14% of those
outages. Each utility is unique, but these numbers are not unusual for a transmission
system comprising 15,000 miles of line. Dispite this large number of outages, no
cascading system black out has been intiated.
Finally, Entergy has had as many as 17 transmission lines outaged from a single
tornado event without even losing service to local load. Standard FAC-003-1 assigns
Page 4 of 6
Comment Form — Transmission Vegetation Management SAR
too much risk to outages in general, and too mush risk to vegetation outages in
particular.
NERC and the regional reliability entities should define performance criteria that
specifically define certain contingencies and certain undesireable outcomes that would
classify a line as truly critical to bulk system reliability. The modeling software
necessary to do this is readily available and already in use today by the Reliability
Entities and their subject utilities.
If FERC has concerns about potentially devistating (albeit rare) combinations of
multiple simultaneous line outage contingencies, the REs can define strict criteria for
multiple contingencies. With respect to lines that result in IROLs and SOLs, these lines
can also be identified with specificity, without resorting to blunt voltage distinctions.
Defining system-critical lines too broadly is actually detrimental to FERC's reliability
goals. It dilutes the resources available to maintain reliability on those lines that truly
affect system reliability. Utilities should employ a more focused and intelligent
approach to targeted reliability. Such an approach would have benefits to the users of
the transmission system and to the ratepayers that pay for it.
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments:
Entergy defines four sets of clearances for vegetation approach to transmission lines.
The first set of clearances is the Vegetation Pruning Distance. This is the clearance to
be achieved at the time of vegetation management work which vegetation
management employees and contractors complete as part of this program. This
distance varies with each line, but is set to be the EDGE OF ROW in each case. (This
clearance is referred to as “Clearance 1” in the NERC Vegetation standard FAC-003-1,
Cf B.R1.2.1).
The second set of clearances is the Vegetation Growth Alert Distance. This is the
approach distance that triggers an alert to the Asset Management vegetation
management employees that vegetation maintenance is required. Vegetation spotted
on an aerial inspection that encroaches upon this clearance is noted on the inspection
for future scheduling of pruning.
The third set of clearances is the Minimum Energized Pruning Distance. This is the
minimum approach distance vegetation can have to energized transmission lines and
still be pruned without an outage on the energized transmission line, in accordance with
OSHA safety guidelines. Any vegetation that encroaches on this minimum distance
must be pruned, and must be pruned during an outage on the associated transmission
line.
Page 5 of 6
Comment Form — Transmission Vegetation Management SAR
The fourth set of clearances is the Minimum Vegetation Approach Distance. This is the
absolute minimum radial approach distance to prevent flashover between vegetation
and overhead ungrounded supply conductors. Under this program, vegetation should
never encroach these minimum approach distances. Vegetation must be pruned prior
to reaching this distance and must be pruned with an outage on the transmission line.
(This distance is referred to as “Clearance 2” in the NERC vegetation standard, FAC003-1, Cf B.R1.2.2.) These clearance distances are based upon those set forth in the
Institute of Electrical and Electronics Engineers (IEEE) Standard 516-2003 (Guide for
Maintenance Methods on Energized Power Lines) and as specified in Table 5.
Under this program, vegetation can encroach the Vegetation Growth Alert Distance and
the Minimum Energized Pruning Distance, but it shall not encroach upon the Minimum
Vegetation Approach Distance.
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments:
The policy to increase sanctions based on a finding of an "intentional economic decision
to violate the standard" is ill-concieved:
1. Every transmission line outage that has ever occured could have been avoided if
more money had been spent on SOMETHING, SOMWHERE.
2. No utility has an unlimited budget, so decisions based on risk, cost and benefit are
made every day.
3. After the outage, the localized initiating cause will appear so trivial and inexpensive
that it would seem that it could easily have been fixed in advance.
4. Therefore, reviewers could conclude that EVERY outage (a defacto violation of the
standard), is the result of an "economic decision to violate the standard."
Economic choices are a necessary and natural part of doing business, and do not
necessarily imply the existence of malicious motives or wrong-doing.
The current policy is going to create unnecessary costs to ratepayers, even to avoid
inconsequential outages.
Page 6 of 6
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Doug Hohlbaugh
Organization: FirstEnergy Corp
Telephone:
330-384-4698
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 4
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 4
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: FirstEnergy agrees that clarification on select issues will aid the intent of
this NERC Standard.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments: ReliabilityFirst, the Reliability Entity (formerly the RRO) was requested to
provided a list of lines below 200 kV deemed as crititical transmission lines that must
comply with FAC-003-01. ReliabilityFirst responded "there are no lines below 200kV
deemed as critical infrustructure".
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments: For R1.2.1 (Clearance 1), FirstEnergy used our existing specification
requirement "for minimum clearance to be achieved at locations with an easement or
other restriction" to define the minimum exceptable clearance.
For R1.2.2 (Clearance 2), FirstEnergy uses the IEEE 516-2003 standard as the
minimum as referenced in FAC-003-01. This is the minimum clearance under all
operating conditions. FirstEnergy believes this is an appropriate definition.
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments:
The definition of Right-Of-Way requires modification to clarify it is the width required by
engineering to operate the line. This may or may not be the legal Right-of-Way. (See
previously submitted comments submitted by FE in Feb 2007 for more details).
Page 4 of 4
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
John Tamsberg
Organization: Florida Power and Light
Telephone:
(561) 694-3975
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 5
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: FPL believes the technical portion of the standard provides adequate
reliability protection to the system. FPL also recognizes the need to re-format the
standard to bring it into conformance with the latest version of the Reliability Standard
Development Procedure and the ERO Sanctions Guidelines, to remove references to
RRO in the standard and substitute a responsible entity and, add compliance elements
such as time horizons, and violation severity levels.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments:
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments:
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments: For the record FPL re-emphasixe its comments from the previous FAC 0031 SAR.
Requirement 3.2 exempts reporting of outages from outside the ROW when natural
disasters such as tornados or hurricanes occur. Our experience with numerous
hurricanes indicates that all outages during these types of events should be exempt.
The focus in these situations is to get the lines back in service and restore customers.
There is insufficient manpower to adequately complete the forensics necessary to
determine an accurate root cause. It is not uncommon to find vegetation debris in the
lines or downed trees on the ROW in this situation. In most cases it is not possible to
determine the original location of these trees.
In the compliance section of the document a transmission owner becomes non
compliant with a single category 1 or 2 outage. This occurs regardless of the
circumstances. A non compliant penalty for a single outage in a situation where no
customers were affected and the system could not have been compromised is not
Page 4 of 5
Comment Form — Transmission Vegetation Management SAR
reasonable. It is also not an indicator of a poorly maintained system. We agree that
several Category 1 or 2 interruptions could be an indicator of neglect but one is not. We
recommend that the compliance section be reviewed with this in mind.
Page 5 of 5
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Roger Champagne
Organization: Hydro-Québec TransÉnergie (HQT)
Telephone:
514 289-2211, X 2766
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
François Gauthier
HQT
NPCC
1
Charles Sarthou
HQT
NPCC
1
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 5
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: It is our belief that the Standard in its current form does provide adequate
provisions and drivers to minimize vegetation related outages and eliminate the
likelihood of reoccurence of the August 14, 2003 blackout. However, it is recognized
that the industry needs to consolidate its view on these provisions and we support the
preparation of a “white paper” that will document the rationale concerning the
requirements of the standard, as well as review certain aspects of the standard that
have come into question.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments: We consider that it should be the Planning Coordinator role to determine
the sub 200kV critical transmission lines and even for any transmission lines irrelevent
of voltage level. For that, it should follow an impact based methodology such as the
one used in NPCC.
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments: HQT clearance methodology is not specifically based on the value specified
in Clearance 1 and Clearance 2. HQT TVMP is such organized that vegetation
management work minimize costs for line clearing and brush control while preventing
outages from vegetation cause. As such, staff qualifications required to work near
energized facilities are less than under the absolute minimum as stipulated in IEEE
516-2003, and in most cases, the work is less labour and equipment intensive.
However clearances are never less than the absolute minimum stipulated in FAC-003-1
(R1.2.2).
The above provides the basic approach used at HQT. If the Standard Drafting Team
would like a copy of the HQT approach and methodology, this could be provided.
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments: Here are some general comments on the SAR:
Page 4 of 5
Comment Form — Transmission Vegetation Management SAR
1. In the purpose section of the SAR, item 1, we don't understand the substitution of
BPS by «electric transmission system»; it seems like there is a will to make the
Standards applicable to more than the BPS. It is our understanding that NERC
Standards are aimed at the reliability of the BPS. The term BPS should be retained and
instead of modifying the SAR to widen the applicability, the Standard itself should be
modified to specifically used the term BPS in item A.3.
2. In the detailed description section, item 1, sub-bullett , it is written that :``...the
SDT may consider other criteria in determining applicability of the Standard to sub 200
kV lines...``. We think that in item 4.3 (Applicability) of the existing Standard, there is
already the possibility of applying the Standard to sub 200 kV lines if determined by
RRO. This could be reworded by saying:«...as determined by a methodology to define
BPS element»; such as the one used by NPCC.
3. We noticed that most Definitions ( e.g. RC, IA, PC, RP, TP, TOp, DP, GO, GOp, PSE,
MO (not even in the Glossary), LSE) used to described the Reliability Functions in the
SAR form, are somewhat different than those used in the Glossary of Terms approved
with the Standards deposited at the FERC. For consistency, if the definition needs to be
changed, this should be done through the right process, not just casually in the SAR
Form.
4. Also, although the title in that same section of the SAR form refers to Reliability
Functions, these are in fact the Responsible Entity that performs those functions;
maybe a correction in the SAR form would be necessary.
Page 5 of 5
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
David Kiguel
Organization: Hydro One Networks Inc.
Telephone:
416-345-5313
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
George Juhn
Additional Member
Organization
Hydro One Networks Inc.
Region*
NPCC
Segment*
1
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 5
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: It is our belief that the Standard in its current form does provide adequate
provisions and drivers to minimize vegetation related outages and eliminate the
likelihood of reoccurence of the August 14, 2003 blackout. However, it is recognized
that the industry needs to consolidate its view on these provisions and we support the
preparation of a “white paper” that will document the rationale concerning the
requirements of the standard, as well as review certain aspects of the standard that
have come into question.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments:
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments: Hydro One clearance standards are based on the Ontario Health and Safety
Act (OHSA) clearances rather than the absolute minimum specified in Clearance 2.
OHSA clearances at time of work minimize costs for line clearing and brush control. By
maintaining OHSA clearances during normal working conditions, staff qualifications
required to work near energized facilities are less than under the absolute minimum as
stipulated in IEEE 515-3003, and in most cases, the work is less labour and equipment
intensive. As part of work planning, qualified staff determine the amount of vegetation
that has to be removed to achieve OHSA clearances at the time of the next scheduled
work. As well, provisions are built into the clearances at time of work to account for
conductor and tree movement during adverse weather conditions. The objective is to
provide OHSA clearances under adverse conditions, but these are not always achieved,
however clearances are never less than the absolute minimum stipulated in FAC-003-1.
The above provides a description of our planning process. If the Standard Drafting
Team would like a copy of the Hydro One standard, this can be provided.
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Page 4 of 5
Comment Form — Transmission Vegetation Management SAR
Comments: We believe from a transmission system perspective, category 3 outages
are no different than many of the other types of outages that take place on the system,
such as hardware failures, lightning damage and station equipment outages to name a
few. It is our understanding that there is no requirement to report these “other”
outages which makes one wonder why the tree related outages that originate off the
right of way need to be reported. We are not diminishing the importance of category 3
outages, but from a system cascading perspective, these outages are no more
important than other line or station outages, and are fewer in number than the “other”
random outages. To initiate system cascading as occurred during August 14, 2003, a
number of the random outages would have to coincide to cause a wide spread system
event, which in our opinion is a very low probability occurence. On the other hand, a
category 1 outage can occur as a result of any system disturbance should there be
deficiencies in clearances to vegetation, as such the importance of category 1 outages
is apparent and reporting is appropriate. We support the review concerning the need
to report category 3 outages and that the ultimate decision should be based on
reporting rules that take into consideration the broader topic of reliability, rather than
just vegetation related outages.
Page 5 of 5
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Ron Falsetti
Organization: IESO
Telephone:
905-855-6187
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
Page 3 of 5
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments:
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments:
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments:
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments:
1. The SAR indicates that a list of critical low voltage transmission lines will be
provided to FERC. We do not interpret Order 693 to direct NERC to provide this list.
Rather, we interpret that FERC asks for defining a criteria that would include low
voltage transmission lines that have impact on Bulk Power System reliability. We do not
think the list is required.
2. The SAR indicates: “The standard DT may consider other criteria in determining
applicability of the standard to sub 200kV lines…” Per Order 693, the criteria is quite
clearly stated to be the transmission lines of less than 200 kV that could impact Bulk
Power System reliability. We don't feel any other criteria would be necessary. Further,
to identify the candidates that meet these criteria, we believe they should be
determined by the Reliability Coordinator, similar to the PRC-023 standard, since the
RC has the primary responsibility and knowledge of interconnection reliability impact.
3. We do not understand why the SDT considers removing Category 3 incidents? In
our view, Category 3 outages are important information for assessing the effectiveness
of vegetation program. Since the industry started reporting vegetation related outages
about 3 years ago, data collected so far indicates that of a total of 98 reported
vegetation outages, 67 of them were category 3 outages. With this high percentage,
Page 4 of 5
Comment Form — Transmission Vegetation Management SAR
reporting of Category 3 events should be a must since the associated trends can
provide valuable information to the TOs to aid its evaluation of the vegetation
management program.
4. The white paper and field tests are a good idea and the SDT should be commended
for these, especially the white paper.
5. Item 2 under the FERC Order 693 Items in the Detailed Description Section indicates
the SDT will also collection outage data. While we understand that FERC has directed
the ERO to collect outage data for transmission outages of lines that cross both federal
and non-federal lands, we do not feel that it is the SDT's role to perform this task. We
feel that this task should be performed by the ERO line functions or a group separate
from the SDT such that the task does not add burden to the SDT which may slow down
the standard development process or result in the standard development being driven
by unanalyzed data and resulting in erroneous requirements.
6. With respect to reporting exemptions, our position during development of the
previous version of this standard was to limit them. We commend the SDT intention to
clarify the outage exemptions under major disasters, but to consider including all
category outage exemptions in the standard body is too prescriptive and will add to the
already extended list. It can end up with a very long list of outage exemptions, thereby
reducing the coverage of the standard substantially and defeating its purpose.
Page 5 of 5
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
IRC Standards Review Committee
Lead Contact:
Charles Yeung
Contact Organization:
SPP
Contact Segment:
2
Contact Telephone:
832-724-6142
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Mike Calimano
NYISO
NPCC
2
Alicia Daugherty
PJM
RFC
2
Ron Falsetti
IESO
NPCC
2
Matt Goldberg
ISO-NE
NPCC
2
Brent Kingsford
CAISO
WECC
2
Steve Myers
ERCOT
ERCT
2
Anita Lee
AESO
WECC
2
Bill Phillips
MISO
RFC+
2
MRO+
SERC
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
Page 3 of 5
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments:
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments: N/A
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments: N/A
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments:
1. The SAR indicates that a list of critical low voltage transmission lines will be
provided to FERC. We do not interpret Order 693 to direct NERC to provide this list.
Rather, we interpret that FERC asks for defining a criteria that would include low
voltage transmission lines that have impact on Bulk Power System reliaiblity. We do not
think the list is required.
2. The SAR indicates: “The standard DT may consider other criteria in determining
applicability of the standard to sub 200kV lines…” Per Order 693, the criteria is quite
clearly stated to be the transmission lines of less than 200 kV that could impact Bulk
Power System reliability. We don't feel any other criteria would be necessary. Further,
to identify the candidates that meet this criteria, we believe they should be determined
by the Reliability Coordinator, similar to the PRC-023 standard, since the RC has the
primary responsibility and knowledge of interconnection reliability impact.
3. We do not understand why the SDT considers removing Category 3 incidents? In
our view, Category 3 outages are important information for assessing the effectiveness
of vegetation program. Since the industry started reporting vegetation related outages
about 3 years ago, data collected so far indicates that of a total of 98 reported
vegetation outages, 67 of them were category 3 outages. With this high percentage,
Page 4 of 5
Comment Form — Transmission Vegetation Management SAR
reporting of Category 3 events should be a must since the associated trends can
provide valuable information to the TOs to aid its evaluation of the vegetation
management program.
4. The white paper and field tests are a good idea and the SDT should be commended
for these, especially the white paper.
5. Item 2 under the FERC Order 693 Items in the Detailed Description Section indicates
the SDT will also collect outage data. While we understand that FERC has directed the
ERO to collect outage data for transmission outages of lines that cross both federal and
non-federal lands, we do not feel that it is the SDT's role to perform this task. We feel
that this task should be performed by the ERO or a group separate from the SDT such
that the task does not add burden to the SDT which may slow down the standard
development process or result in the standard development being driven by unanalyzed
data and resulting in erroneous requirements.
6. With respect to reporting exemptions, our position during development of the
previous version of this standard was to limit them. We commend the SDT intention to
clarify the outage exemptions under major disasters, but to consider including all
category outage exemptions in the standard body is too prescriptive and will add to the
already extended list. It can end up with a very long list of outage exemptions, thereby
reducing the coverage of the standard substatively and defeating its purpose. If this list
was to be developed, they could be attached as guidelines aside of the standard.
7. The SAR DT states it will deal with "critical facilities" . The SRC suggest that the DT
not use the word "critical" and adopt another term.
There is a need to define in a single standard what the term "critical" means. Standards
FAC-014 (R5.1.1); IRO-002-1 (R6) and others use the term "critical" as in: critical
loads, critical infrastructure, critical assets. The Veg Management Team is asked to
avoid making the current situation worse.
Page 5 of 5
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Kathleen Goodman
Organization: ISO New England
Telephone:
(413) 535-4111
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
NPCC
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 5
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments:
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments:
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments:
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments:
1. The SAR indicates that a list of critical low voltage transmission lines will be
provided to FERC. We do not interpret Order 693 to direct NERC to provide this list.
Rather, we interpret that FERC asks for defining a criteria that would include low
voltage transmission lines that have impact on Bulk Power System reliaiblity. We do not
think the list is required.
2. The SAR indicates: “The standard DT may consider other criteria in determining
applicability of the standard to sub 200 kV lines…” Per Order 693, the criteria is quite
clearly stated to be the transmission lines of less than 200 kV that could impact Bulk
Power System reliability. We don't feel any other criteria would be necessary. Further,
to identify the candidates that meet this criteria, we believe they should be determined
by the Reliability Coordinator, similar to the PRC-023 standard, since the RC has the
primary responsibility and knowledge of interconnection reliability impact.
3. We do not understand why the SDT considers removing Category 3 incidents. In our
view, Category 3 outages are important information for assessing the effectiveness of a
vegetation program. Since the industry started reporting vegetation-related outages
about 3 years ago, data collected so far indicates that of a total of 98 reported
vegetation outages, 67 of them were category 3 outages. With this high percentage,
reporting of Category 3 events should be a must since the associated trends can
Page 4 of 5
Comment Form — Transmission Vegetation Management SAR
provide valuable information to the TOs to aid its evaluation of the vegetation
management program.
4. The white paper and field tests are a good idea and the SDT should be commended
for these, especially the white paper.
5. Item 2 under the FERC Order 693 Items in the Detailed Description Section indicates
the SDT will also collect outage data. While we understand that FERC has directed the
ERO to collect outage data for transmission outages of lines that cross both federal and
non-federal lands, we do not feel that it is the SDT's role to perform this task. We feel
that this task should be performed by the ERO or a group separate from the SDT such
that the task does not add burden to the SDT which may slow down the standard
development process or result in the standard development being driven by unanalyzed
data and resulting in erroneous requirements.
6. With respect to reporting exemptions, our position during development of the
previous version of this standard was to limit them. We commend the SDT's intention
to clarify the outage exemptions under major disasters, but to consider including all
category outage exemptions in the standard body is too prescriptive and will add to the
already extended list. It can end up with a very long list of outage exemptions, thereby
reducing the coverage of the standard substatively and defeating its purpose. If this list
was to be developed, they could be attached as guidelines aside of the standard.
7. The SAR DT states it will deal with "critical facilities" . The SRC suggest that the DT
not use the word "critical" and adopt another term.
There is a need to define in a single standard what the term critical means.
Standards FAC-014 (R5.1.1); IRO-002-1 (R6) and others use the term "critical" as in:
critical loads, critical infrastructure, critical assets. This Team is asked to avoid making
the current situation worse.
Page 5 of 5
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Robert Coish
Organization: Manitoba Hydro
Telephone:
1-204-487-5479
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 4
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 4
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: The definition of ROW should be clarified. The definition of a critical line
should not be kept to a particular voltage threshold. However, consideration could also
then be given to exempting non-critical lines operating at higher voltage
levels(>200kv). Electrical clearances should be consistent whether on Federal or nonFederal land.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments:
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments: Clearance 1 was developed based on the limits of approach for nonqualified people (public). At a minimum, we would clear beyond this distance during
vegetation control activities. Our cycle times and management approach are adjusted
for this distance, taking into account growth rates. The values will vary depending on
voltage class. Clearance 2 is based on internal design standards that take into account
our understanding of switching surge values for our system. The values used are more
conservative than IEEE 516-2003.
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments:
Page 4 of 4
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Thomas E. Sullivan
Organization: National Grid
Telephone:
508-389-9086
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 5
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: National Grid believes that compliance with all elements of the present
Standard will result in TO's achieving the reliability objectives set forth in the Standard.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments: The Reliability Entity has not provided a list of sub 200 kV lines subject to
compliance with FAC-003-1. The Standard became effective in February 2007, just 3
months ago. Having no list today should not imply that the RE or the Standard has
failed in any way. National Grid suggests that a revised Standard should direct the RE
to produce a list of "sub 200 kV critical transmission lines" within 6 to 12 months of
adoption.
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments: Detailed methodology is not attached. In summary, National Grid used
Table 5 IEEE Section 516 for determing clearance 2. These data for each voltage class
were rounded to the next higher whole number. Clearance 1 was determined by
adding the clearance 2 distance, conductor sag distance, and anticipated tree growth
over the maintenance cycle.
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments:
1) National Grid supports amending FAC-003-1 to bring the Standard into compliance
with "latest version of the Reliability Standard Development Procedure and the ERO
Sanctions Guidelines" as discussed in the SAR Background Information.
2) We do not support amendments to the Standard to address all of the issues raised
by FERC Order 693. We believe most of the FERC's concerns can be addressed by
developing a "white paper" to better explain the Standard and guide its
implementation.
3) National Grid does not support changing the basic approach to defining clearance
from vegetation. The clearance 1 and clearance 2 concept adopts the two management
approaches used by most TO's today and required in some state or ISO level
Page 4 of 5
Comment Form — Transmission Vegetation Management SAR
standards. National Grid supports using the reference to IEEE 516 as the basis for
clearance 2 for two reasons: 1 - there is no other definitive reference for flash over
distances to vegetation and 2- decades of experience by TO's acrosss the North
America suggest the IEEE 516 distances are more than adequate. The well known tree
caused outages in 1996 and 2003 occurred as a result of hard contact with vegetation
not flashover at distances close to those in IEEE 516. Furthermore, FERC accepted
IEEE 516 as appropriate for use in vegetation management in the October 2006, NOPR.
4) National Grid supports amending the definition of a right-of-way though we are not
clear on what is meant in the SAR language by "to encompass required clearing areas".
National Grid is concerned with the interpretation of the present definition that the
right-of-way includes uncleared fee owned or easement land reserved for future
construction. In many jurisdictions the TO may not be allowed to remove trees from
these areas. A "white paper" could better describe the definition and prevent future
compliance issues stemming from an ambiguous definition.
Page 5 of 5
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Michael Calimano
Organization: New York Indepentant System Operator
Telephone:
518-356-6129
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
Page 3 of 5
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments:
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments: N/A
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments: N/A
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments:
1. The SAR indicates that a list of critical low voltage transmission lines will be
provided to FERC. We do not interpret Order 693 to direct NERC to provide this list.
Rather, we interpret that FERC asks for defining a criteria that would include low
voltage transmission lines that have impact on Bulk Power System reliaiblity. We do not
think the list is required.
2. The SAR indicates: “The standard DT may consider other criteria in determining
applicability of the standard to sub 200kV lines…” Per Order 693, the criteria is quite
clearly stated to be the transmission lines of less than 200 kV that could impact Bulk
Power System reliability. We don't feel any other criteria would be necessary. Further,
to identify the candidates that meet this criteria, we believe they should be determined
by the Reliability Coordinator, similar to the PRC-023 standard, since the RC has the
primary responsibility and knowledge of interconnection reliability impact.
3. We do not understand why the SDT considers removing Category 3 incidents? In
our view, Category 3 outages are important information for assessing the effectiveness
of vegetation program. Since the industry started reporting vegetation related outages
about 3 years ago, data collected so far indicates that of a total of 98 reported
vegetation outages, 67 of them were category 3 outages. With this high percentage,
Page 4 of 5
Comment Form — Transmission Vegetation Management SAR
reporting of Category 3 events should be a must since the associated trends can
provide valuable information to the TOs to aid its evaluation of the vegetation
management program.
4. The white paper and field tests are a good idea and the SDT should be commended
for these, especially the white paper.
5. Item 2 under the FERC Order 693 Items in the Detailed Description Section indicates
the SDT will also collect outage data. While we understand that FERC has directed the
ERO to collect outage data for transmission outages of lines that cross both federal and
non-federal lands, we do not feel that it is the SDT's role to perform this task. We feel
that this task should be performed by the ERO or a group separate from the SDT such
that the task does not add burden to the SDT which may slow down the standard
development process or result in the standard development being driven by unanalyzed
data and resulting in erroneous requirements.
6. With respect to reporting exemptions, our position during development of the
previous version of this standard was to limit them. We commend the SDT intention to
clarify the outage exemptions under major disasters, but to consider including all
category outage exemptions in the standard body is too prescriptive and will add to the
already extended list. It can end up with a very long list of outage exemptions, thereby
reducing the coverage of the standard substatively and defeating its purpose. If this list
was to be developed, they could be attached as guidelines aside of the standard.
Page 5 of 5
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Anthony Johnson
Organization: Northeast Utilities
Telephone:
860-665-3858
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 5
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: Proposed modifications do not increase the levels of reliability above what
is already required in the current version of the Stnadard.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments: The Reliability Entity has not provided a list of facilities covered under FAC003-1. This is not a fault of the RE as there has been no direction provided as to what
factors or charateristics are required for sub-200kV lines to be included under the
Standard. It is our position that the factors that will be used to develop the list of sub200kV faciltities to be covered by the Standard be developed at the national level
(NERC) and adopted by all RE's for consistency.
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments: The methodology for determining clearance 2 is based on the requirements
of FAC-003-1. The IEEE Section 516 has been considered the base minimum limits for
clearances as provided under FAC-003-1 R.1.2.2. Clearances used for R.1.2.1 on the
NU Transmission System comply with the requirements of ISO-NE Operating Procedure
OP-3, that provides clearance levels required at the time of vegetation trimming or
clearing under the various transmission voltages.
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments: NU does not support the proposed revisions based on the issues raised by
FERC Order 693. The Standard has not been in effect long enough to determine if
there are any shortcomings with the current requirements. It is our position that the
current clearance requirements are satisfactory in that a base minimum distance as
provided under IEEE Section 516 is sufficient and there is the need for variations in the
second level of clearances base on Regional needs and conditions.
The revisions to the definition of "right-of-way" to encompass required clearance areas
canbe problematic as this could cause significant problems with current systems. There
is no detailed description on what the new defition will include or what the actual
Page 4 of 5
Comment Form — Transmission Vegetation Management SAR
impact will be to TO's. If the definition will include defined limits or widths of rights-ofway this may affect current facilities that do not meet these distances. Second, there
are areas where the company owns or possesses additional area beyond the current
maintained right-of-way widths. Is it proposed that the new definition expand the
limits of clearing or maintenance to include easemented or fee-owned areas beyond the
current maintained limits? Until the new definition can be presented - it is difficult to
support any changes at this time and we can only comment on the percevied negative
impacts.
Page 5 of 5
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Stephen Tankersley
Organization: Pacific Gas and Electric Company
Telephone:
916.408.3206
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 5
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
1
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 5
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: As stated in the SAR
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments: Provided from WECC
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments: Will be provided to the SARDT in a separate attachment
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments:
1) Applicability 4.3 of the standard - PG&E believes the RE is in the best position to
determine sub-200kV facilities are designated critical and covered under FAC-003-1.
We suggest the ERO direct the RE to provide a list of sub-200kV lines designated
critical along with methodology used to make that determination.
2) Clearances for lines on federal and non-federal lands - PG&E believes there should
be no distinction between requirements on different lands. Vegetation encroachments
have the same impact regardless of land ownership.
3) Definition of right of way - agreed
4) Suitability of IEEE 516-2003 - PG&E believes the use of IEEE 516 as the standard for
clearance requirements are adequate to ensure transmission system reliability provided
the TO has an appropriate methodology for determining clearance at time of trim and
an adequate cycle to prevent vegetation from encroaching within minimum distances.
Use of ANSI Z133.3 or FedOSHA 1910, as suggested by FERC, is not appropriate as it is
intended for worker safety and not system reliability. TO compliance with R1.2 of the
standard should address concerns FERC has with maintaining minimum clearance.
5-7) Procedural items - No comment
Page 4 of 5
Comment Form — Transmission Vegetation Management SAR
8) Preparation of technical manual (white paper) - agreed
9) PG&E believes the current reporting requirements under R3 of the standard should
be revised. Distinction is placed on fall-in's "in and out of the ROW" and may not be
the best method for determining severity for reporting purposes. PG&E believes a
better distinction is (a) green/healthy/no obvious decline and (b) dead or obvious
signs of disease, decay or decline. A key component of any TMVP should be hazard
tree mitigation regardless if in or out of the ROW. Suggested categories:
Category 1 - Any grow-in (as currently stated).
Category 2 - Any fall-in of a dead tree or one with obvious signs of disease, decay or
decline in or out of the ROW.
Category 3 - Either eliminate this category or specify healthy green tree or tree with no
obvious signs of decline (if retained, be specific about this being for reporting purposes
only)
PG&E recognizes that tree failures, even if dead or diseased, are not necessarily an
indicator of problematic VM program and the severity level should be reflected as such.
Tree density along with other factors make 100% identification not possible. However,
multiple occurrences could be an indicator of substandard performance and the current
standard does remains silent in respect to hazard trees other than if in or out of the
ROW.
Page 5 of 5
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Jack Gardner/John Pinney
Organization: Progress Energy Carolinas/Progress Energy Florida
Telephone:
919-329-5922/727-372-5112
E-mail:
[email protected] and [email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 7
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 7
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: Progress Energy Carolinas and Progress Energy Florida are providing an
answer to the question as it relates to the reliability need. The current standard
contains appropriate requirements and measures to ensure the Transmission Owner's
vegetation management program is implemented and managed to ensure the reliability
of the transmission system. In addition, we do not believe that a standard with a zero
tolerance for vegetation-related outages in the ROW is in need of reliability-based
revisions.
However, we do recognize the need for a revision of the standard to address nonreliability related items that are in the SAR. Procedural items such as formatting and
clarifications, such as the definition of right-of-way, need to be, and should be,
addressed.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments: The SERC and FRCC regions have not identified any lines below 200kV to
be critical to the electrical system in the region. Since no lines have been identified as
critical to the region, no list has been provided to Progress Energy Carolinas and
Progress Energy Florida. (please note our comments on this issue in question #4)
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments: Progress Energy has an individual on the Drafting Team and will share the
Progress Energy Florida clearance Tables with the team.
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments: Progress Energy Carolinas (PEC) and Progress Energy Florida (PEF) do not
agree that each of 11 items listed in the SAR are necessary to improve reliability. The
following comments are offered for each of the 11 items identified in the SAR detail
description:
1. Standard Applicability:
Page 4 of 7
Comment Form — Transmission Vegetation Management SAR
PEC and PEF believe that the current standard wording for determining facilities subject
to this standard should not be revised. The standard as it is written provides for lines
below 200kV, that are determined to impact the grid, to be subject to the standard.
Extending the requirements to a bright line below 200kV, such as 100kV, will dilute the
focus on those lines that impact grid reliability, lines >200kV, and shift attention to
facilities, those <200kV, that do not necessarily impact grid reliability. Customer
reliability is an issue that impacts customer satisfaction and is generally driven by state
utility commissions. While some facilities above 200kV directly support customer load,
transmission lines below 200kV primarily support customer load, and interruptions to
those facilities generally reduce load on the grid.
The majority of transmission facilities below 200 kV also have significantly different
design/construction/operating characteristics and have not been cited as impacting bulk
power system reliability. For example, the Final Report on the August 14, 2003
Blackout in the United states and Canada: Causes and Recommendations April 2004 by
the U.S.- Canada Power System Outage Task Force and all referenced major blackouts
(pages 103-115) in that report, cited only outages which involved vegetation at line
voltages above 200kV. Generally applying requirements that are appropriate for
>200kV lines to lines less than 200kV will result in significant documentation and
reporting of items such as restrictions, mitigation plans, off right-of-way vegetationrelated outage investigation/ information and other issues, all of which dilutes the focus
on lines that directly impact bulk power system reliability.
Revising the standard to use general criteria or broad language for defining "Bulk Power
System" transmission lines covered by the standard is a “one size fits all” approach. If
that approach were taken, the standard would cover a significant number of
transmission lines that have no direct impact on bulk power system reliability under
standard planning/operating conditions, resulting in a significant cost burden for
electric customers without improving “grid” reliability. PEC and PEF believe that the
applicability provision of the standard should instead focus attention of the standard
only on the transmission lines below 200kV that directly impact “Bulk Power System”
reliability, as the current version requires.
While PEC and PEF recognize some validity in the Commission’s concern, PEC and PEF
recommend that the applicability provision of this standard should be revised only if
existing system design, planning or operating reliability criteria and parameters are
considered as a basis for defining the applicability of the standard. To that end, PEC
and PEF recommend each Regional Entity (RE) determine applicability of FAC-003 to
those lines within the region that are between 100kV and 200KV, if, and only if, they
are identified as operationally significant elements of Interconnection Reliability
Operating Limits (“IROLs”). That is, any facility below 200kV that, by itself, would
cause an Interconnected Reliability Limit Violation should the facility be outaged.
2. Issue of Clearances (Federal vs Non-Federal Lands):
FAC-003-1 presently requires the transmission owner (TO) “identify and document
clearances between vegetation and any overhead, ungrounded supply conductors,
taking into consideration transmission line voltage, the effects of ambient temperature
on conductor sag under maximum design loading, and the effects of wind velocities on
conductor sway.” The intent of this requirement is to ensure adequate clearances to
prevent vegetation related outages. PEC and PEF believe that only the TO has the
Page 5 of 7
Comment Form — Transmission Vegetation Management SAR
technical information required to determine the clearances that are necessary at the
time of VM work and that any “federal lands exemption” to clearances will result in
inadequate clearances for the existing conditions. Consistency in application of the
TO’s clearance requirements, not exceptions, is the only assurance in providing a
uniform and reliable electrical system to meet the nation’s current and future energy
demands.
Any exception for a case by case clearance approach to determine vegetation
management activities/clearances on Federal lands will continue to drive inconsistency
and/or delays associated with TO vegetation management decisions being driven by
diverse vegetation management practices/beliefs and staff changes at the local level of
Federal agencies. Vegetation-related outages have occurred on Federal lands as a
result of this case by case approach, and if “Bulk Power Transmission System” lines
continue to be addressed on a “case by case” basis on National Forest Service (or any
other Federal lands), those lines will potentially be subject to a higher risk for
vegetation-related outages, resulting in reduced reliability for the “Bulk Power System”.
PEC and PEF believe that reliability of the “Bulk Power System” should have the same
focus on Federal and private lands and that the EEI MOU with federal agencies is an
appropriate avenue for TO's to identify clearances on Federal lands, not an exemption
in the language of a reliability standard.
3. Defining Right-of-Way:
PEC and PEF agree that it is appropriate to further address the definition of “right-ofway”. Corridor widths that exceed the design clearance requirements have been
acquired for a variety of reasons in the past; future use, property line buffers, etc.
Vegetation in those areas that would normally be outside of the corridor width
necessary for reliable operation of the facility, but within an expanded easement area,
should not be considered, or treated, different than vegetation that is outside of a
defined easement/permit right-of-way corridor that was designed and acquired
specifically for the reliable operation of a single line.
4. IEEE Standard for Minimum Clearances:
PEC and PEF believe that the IEEE 516-2003 tables are appropriate for defining the
minimum acceptable clearances to prevent flashover between conductors and
vegetation under all rated electrical operating conditions. Closer minimum clearances
such as the minimum length of a support insulator could have been adopted as a
“lowest common denominator” clearance. However the clearance in IEEE 516-2003 was
adopted to ensure an additional margin of reliability. FERC staff has made references
to the use of ANSI Z-133 which is a safety standard that addresses worker safety as
well as the safety of the general public. The purpose of ANSI Z-133 is to address
worker safety and is not focused on transmission line reliability, which is the purpose of
FAC-003-1. OSHA, NESC and other related safety standards have clearances in excess
of IEEE 516-2003. Those clearances are clearly focused on safety issues and will still
apply to other aspects of design and operation of electric facilities (such as public and
worker safety) but are not appropriate to be referenced in a vegetation management
reliability standard as a flashover clearance.
5/6/7.
Procedural Items:
Page 6 of 7
Comment Form — Transmission Vegetation Management SAR
PEC and PEF agree that the procedural items related to formatting RRO references and
revising the compliance elements to meet the new standard format should be
addressed by the standard drafting team.
8. Technical Reference Materials:
PEC and PEF agree that a “white paper” that defines the technical basis for the
standard is appropriate. This type of document, if crafted by the drafting team, should
help to avoid the potential for differences in interpretation of the standard’s
requirements by the various regions during the audit process.
9. Category 3 Outages:
Since control off right-of-way vegetation is generally beyond control of the TO and
since "fall-in" outages are random events that do not threaten grid reliability, PEC and
PEF believe that the reporting of category 3 outages should be removed from the
requirements.
10. Requirement R4:
PEC and PEF believe that requirement R4 should be deleted from the standard, since
the ERO formation provides for delegation of authority to the regional entities.
11. Reporting Exemptions:
PEC and PEF believe that the reporting requirement exemptions for natural disasters
should include all categories of outages. For example, with outages caused by high
winds, hurricanes, tornadoes, etc., it would be difficult (or practically impossible in
some cases) to determine if the vegetation came from on, or off, the "right-of-way". In
addition, the effort and time necessary to make that determination would result in
delaying outage restoration efforts.
Page 7 of 7
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 4
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Public Service Commission of South Carolina
Lead Contact:
Philip Riley
Contact Organization:
Public Service Commission of South Carolina
Contact Segment:
9
Contact Telephone:
803-896-5154
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Mignon L. Clyburn
Public Service Commission of SC
SERC
9
Elizabeth B. "Lib" Fleming
Public Service Commission of SC
SERC
9
G. O'Neal Hamilton
Public Service Commission of SC
SERC
9
John E. "Butch" Howard
Public Service Commission of SC
SERC
9
Randy Mitchell
Public Service Commission of SC
SERC
9
C. Robert "Bob" Moseley
Public Service Commission of SC
SERC
9
David A. Wright
Public Service Commission of SC
SERC
9
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 4
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments:
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments:
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments:
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments:
Page 4 of 4
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 8
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
SERC Vegetation Management Subcommittee
Lead Contact:
Richard Dearman
Contact Organization:
Subcommittee
SERC Engineering Committee, Vegetation Management
Contact Segment:
1
Contact Telephone:
(256) 519-2067
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Jay Farrington
Alabama Electric Cooperative, I.
SERC
1
Randy Gann
Alabama Power Co.
SERC
1
Raymond Wiesehan
Ameren
SERC
1
John Neagle
Associated Electric Coop
SERC
1
Billy George
Duke Energy, Carolinas
SERC
1
Ralph Hale
Entergy
SERC
1
Marc Tunstall
Fayetteville Public Works Comm
SERC
1
Jack Gardner
Progress Energy Carolinas
SERC
1
Jerry Lindler
South Carolina Electric & Gas
SERC
1
John Wolfmeyer
SERC Reliability Corporation
SERC
10
Page 2 of 8
Comment Form — Transmission Vegetation Management SAR
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 3 of 8
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 4 of 8
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: The SERC VMS is providing an answer to the question as it relates to the
reliability need. The current standard contains appropriate requirements and measures
to ensure the Transmission Owner's vegetation management program is implemented
and managed to ensure the reliability of the transmission system. In addition, we do
not believe that a standard with a zero tolerance for vegetation-related outages in the
ROW is in need of reliability-based revisions.
However the SERC VMS recognizes the need for a revision of the standard to address
non-reliability related items that are in the SAR. Procedural items such as formatting
and clarifications, such as the definition of right-of-way, need to be, and should be,
addressed.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments: The SERC region has not identified any lines below 200kV to be critical to
the electrical system in the region. Since no lines have been identified as critical to the
region, no list has been provided to Transmission Owners. (please note the
subcommittee's comments on this issue in question #4)
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments: This question does not apply to the SERC EC Vegetation Mangement
Subcommittee.
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments: The SERC VMS does not agree that each of 11 items listed in the SAR are
necessary to improve reliability. The following comments are offered for each of the 11
items identified in the SAR detail description:
1. Standard Applicability:
Page 5 of 8
Comment Form — Transmission Vegetation Management SAR
The SERC VMS disagrees with revising the 200 kV threshold for determining facilities
subject to this standard. Extending the requirements to lines other than those >200kV
will dilute the focus on those lines that impact grid reliability and shift attention to
facilities, those <200kV. The reliability of lower voltage lines involves local customers'
reliability and satisfaction hence that reliability should be addressed by local and state
utility commissions. The majority of the >200kV lines are solely elements of the grid
and and interruptions to those lines negatively impact grid reliability. The majority of
the <200kV lines primarily support customer load, and interruptions to those facilities
actually reduces load on the grid.
The majority of transmission facilities below 200 kV also have significantly different
design/construction/operating characteristics and have not been cited as impacting bulk
power system reliability. For example, the Final Report on the August 14, 2003
Blackout in the United states and Canada: Causes and Recommendations April 2004 by
the U.S.- Canada Power System Outage Task Force and all referenced major blackouts
(pages 103-115) in that report, cited only outages which involved vegetation at line
voltages above 200kV. Generally applying requirements that are appropriate for
>200kV lines to lines less than 200kV will result in significant documentation and
reporting of items such as restrictions, mitigation plans, off right-of-way vegetationrelated outage investigation/ information and other issues, all of which dilutes the focus
on lines that directly impact bulk power system reliability.
Revising the standard to use general criteria or broad language for defining "Bulk Power
System" transmission lines covered by the standard is a “one size fits all” approach. If
that approach were taken, the standard would cover a significant number of
transmission lines that have no direct impact on bulk power system reliability under
standard planning/operating conditions, resulting in a significant cost burden for
electric customers without improving “grid” reliability. The SERC VMS believes that the
applicability provision of the standard should instead focus attention of the standard
only on the transmission lines below 200kV that directly impact “Bulk Power System”
reliability, as the current version requires.
In sum, while the SERC VMS recognizes some validity in the Commission’s concern, the
SERC VMS recommends that the applicability provision of this standard should be
revised only if existing system design, planning or operating reliability criteria and
parameters are considered as a basis for defining the applicability of the standard. To
that end, the SERC VMS recommends each Regional Entity (RE) determine applicability
of FAC-003 to those lines within the region that are between 100kV and 200KV, if, and
only if, they are identified as operationally significant elements of Interconnection
Reliability Operating Limits (“IROLs”). That is, any facility below 200kV that by itself
would cause an Interconnected Reliability Limit Violation should the facility
be outaged.
2. Issue of Clearances (Federal vs Non-Federal Lands):
FAC-003-1 presently requires the transmission owner (TO) “identify and document
clearances between vegetation and any overhead, ungrounded supply conductors,
taking into consideration transmission line voltage, the effects of ambient temperature
on conductor sag under maximum design loading, and the effects of wind velocities on
conductor sway.” The intent of this requirement is to ensure adequate clearances to
prevent vegetation related outages. The SERC VMS believes that only the TO has the
technical information required to determine the clearances that are necessary at the
time of VM work and that any “federal lands exemption” to clearances will result in
Page 6 of 8
Comment Form — Transmission Vegetation Management SAR
inadequate clearances for the existing conditions. Consistency in application of the
TO’s clearance requirements, not exceptions, is the only assurance in providing a
uniform and reliable electrical system to meet the nation’s current and future energy
demands.
Any exception for a case by case clearance approach to determine vegetation
management activities/clearances on Federal lands will continue to drive inconsistency
and/or delays associated with TO vegetation management decisions being driven by
diverse vegetation management practices/beliefs and staff changes at the local level of
Federal agencies. Vegetation-related outages have occurred on Federal lands as a
result of this case by case approach, and if “Bulk Power Transmission System” lines
continue to be addressed on a “case by case” basis on National Forest Service (or any
other Federal lands), those lines will potentially be subject to a higher risk for
vegetation-related outages, resulting in reduced reliability for the “Bulk Power System”.
The SERC VMS believes that reliability of the “Bulk Power System” should have the
same focus on Federal and private lands and that the EEI MOU with federal agencies is
the appropriate vehicle for TO's to identify clearance variances on Ferderal lands, not
exemption language in the standard.
3. Defining Right-of-Way:
The SERC VMS agrees that it is appropriate to further address the definition of “rightof-way”. Corridor widths beyond design clearance requirements have been acquired for
a variety of reasons in the past; future use, property line buffers, etc. Vegetation in
those areas that would normally fall outside of the area necessary for operation of the
facility should not be considered or treated different than vegetation that is outside of a
defined easement/permit area that is designed for the reliable operation of an existing
single line corridor.
4. IEEE Standard for Minimum Clearances:
The SERC VMS disagrees with objections to the use of the IEEE 516-2003 clearance as
the minimum acceptable distances for “Clearance 2”. The IEEE 516-2003 tables are
appropriate for defining the minimum acceptable clearances to prevent flashover
between conductors and vegetation under all rated electrical operating conditions.
Closer minimum clearances such as the minimum length of a support insulator could
have been adopted as a “lowest common denominator” clearance. However the
clearance in IEEE 516-2003 was adopted to ensure an additional margin of reliability.
FERC staff references ANSI Z-133 which is a safety standard that addresses worker
safety as well as the safety of the general public. As such, the purpose of ANSI Z-133 is
to address worker safety and is not focused on transmission line reliability, which is the
purpose of FAC-003-1. OSHA, NESC and other related safety standards have
clearances in excess of IEEE 516-2003. Those clearances are clearly focused on safety
issues and will still apply to other aspects of design and operation of electric facilities
(such as public and worker safety) but are not appropriate to be referenced in a
vegetation management reliability standard.
5/6/7.
Procedural Items:
The SERC VMS agrees that the procedural items related to formatting RRO references
and additional compliance elements should be addressed by the standard drafting
team.
Page 7 of 8
Comment Form — Transmission Vegetation Management SAR
8. Technical Reference Materials:
The SERC VMS agrees that a “white paper” that defines the technical basis for the
standard is appropriate to avoid the potential for differences in interpretation of the
standard’s requirements during the various region's audit processes.
9. Category 3 Outages:
Since the right to control off right-of-way vegetation is generally beyond control of the
TO, the SERC VMS believes that the reporting of category 3 outages should be removed
from the requirements.
10. Requirement R4:
The SERC VMS believes that requirement R4 should be deleted from the standard,
based on the ERO formation and the process for delegation of authority to the regional
entities.
11. Reporting Exemptions:
The SERC VMS believes that the reporting requirement exemptions for natural disasters
should include all categories of outages. It would, for example, be difficult, without
delaying restoration efforts, to determine if the vegetation from high winds, hurricanes,
tornadoes, etc. is from on or off the "right-of-way".
Page 8 of 8
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 4
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Southern Company Transmission
Lead Contact:
Roman Carter
Contact Organization:
Southern Company Transmission
Contact Segment:
1
Contact Telephone:
205.257.6027
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Steve Burns
Gulf Power Co.
SERC
1
Randall Gann
Alabama Power Co.
SERC
1
Steve Craig
Mississippi Power Co.
SERC
1
Ron Reinike
Mississippi Power Co.
SERC
1
Ken Trump
Gulf Power Co.
SERC
1
Nancy Huddleston
Georgia Power Co.
SERC
1
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 4
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: We do not feel there is a reliability need for modifying the standard.
However, we do agree certain modifications are needed to clarify procedural issues
such as the amount of time allowed for taking corrective action when items are found
to be out of compliance.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments: We are not really sure how to answer this question. The Regional Entity
has not sent us a list, but they have advised us that we do not have any sub 200 kv
critical transmisison lines that must comply with FAC-003-1.
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments: IEEE 516-2003, Section 4.2.2.3 was adopted as the minimum allowable
distance for Clearance 2, with the expectation that work would normally occur prior to
Clearance 2 reaching the minimum allowable distance. Clearance 1 was determined by
using the Clearance 2 value and adding a growth buffer. Sagging of conductors and
their movement in wind was then considered to ensure the growth buffer is adequate.
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments: We appreciate the efforts of the SAR Drafting Team.
Page 4 of 4
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Richard Dearman
Organization: TVA
Telephone:
256-851-3523
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 4
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 4
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments: The primary needs for mocdifications to this standard are in areas to
address clarifications and formatting not reliability related issues.
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments: We detemined that there are no TVA lines below 200kv that must comply
to this standard due to their criticial needs in SERC.
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments: We utilize a clearance 2 based on IEEE 516 2003 Table 5 criteria. Our
Clearance 1 is a greater amount to allow for growth between clearing and next
inspection or clearance activities. We will provide our tables is requested.
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments: We feel that the reporting of Category 3 outages should be eliminated.
We agree with the need for a "white paper" to expand on definitions and intent. We
feel that a defined maintainable width of right of way is more appropriate than the
actual easement widths because easement widhts are not purchased or operated
exclusively with or for vegetation manitenance activies. We will be pleased to share
greater details on this concern if requested.
Page 4 of 4
Comment Form — Transmission Vegetation Management SAR
Please use this form to submit comments on the draft Transmission Vegetation
Management SAR. Comments must be submitted by May 9, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Vegetation
Management SAR” in the subject line. If you have questions please contact Harry Tom
at [email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Jeffrey S. Disorda
Organization: Vermont Electric Power Company, Inc.
Telephone:
802-770-6240
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations and Regional Entities
Page 1 of 4
Comment Form — Transmission Vegetation Management SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
Comment Form — Transmission Vegetation Management SAR
Background Information:
The SAR drafting team considered the comments submitted in response to the first posting
of the SAR as well as the FERC Order 693 in preparing the revised SAR to modify FAC-0031 — Transmission Vegetation Management.
The SAR drafting team modified the SAR to state more specifically that the revisions to the
standard need to incorporate the compliance program elements of time horizons and
violation severity levels to bring FAC-003-1 into conformance with the latest version of the
Reliability Standard Development Procedure and the ERO Sanctions Guidelines.
The FERC has urged further industry consideration of a number of issues and these have
been listed in the revised SAR as items to address during using standards development
process to refine FAC-003-1. The SAR drafting team consensus is that a modification to
FAC-003-1 to address the aforementioned items is warranted.
Please review the changes made to the Vegetation Management SAR and then respond to
the questions on the following pages. Please e-mail your comments to [email protected]
with the subject “Vegetation Management SAR” by May 9, 2007.
You need not answer all questions. Insert a “check” mark in the appropriate
boxes by double-clicking the gray areas.
The SAR drafting team considered stakeholder comments on the first draft of this SAR
and the FERC Order 693 in preparing the second draft of the SAR to modify FAC-003-1
— Transmission Vegetation Management.
The SAR drafting team modified the SAR to clarify that FAC-003-1 needs to add time
horizons and violation severity levels to bring the standard into conformance with the
latest version of the Reliability Standards Development Procedure and the ERO
Sanctions Guidelines. (Time Horizons and Violation Severity Levels are both elements
used to determine an appropriate sanction for violation of a standard.)
The SAR drafting team also modified the SAR to clarify that the scope of revisions to this
standard will include addressing the issues raised by FERC in Order 693, including the
following:
- Consideration of minimum clearances needed to avoid sustained vegetationrelated outages that would apply to transmission lines crossing both federal
land and non-federal land
- Revisions to the definition of ‘right of way’ to encompass required clearance
areas
- Review of the suitability of IEEE Standard 516-2003 for minimum vegetation
clearance
Several commenters indicated that the reporting requirements may need revision and
the SAR was revised to include consideration of modifications to the reporting
requirements.
The SAR drafting team consensus is that modification of FAC-003-1 to address the
aforementioned items is needed to ensure reliability of the bulk power system.
Page 3 of 4
Comment Form — Transmission Vegetation Management SAR
1. Do you agree there is a reliability need for the proposed modifications and
review of the standard?
Yes
No
Comments:
2. If you are a transmission owner, have you been provided a list from a
Reliability Entity (formerly RRO) of sub 200kV critical transmission lines that
must comply with FAC-003-1?
Yes
No
Comments: VELCO has not been provided a specific list of critical lines below 200kV
from the RE that need to be in compliance with FAC-003-1. VELCO suggests changing
the wording in the standard to indentify those lines affected as 200 kV and great or
those defined as Bulk Power System facilities.
3. If you are a transmission owner would you provide your methodology for
determining clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1
and R1.2.2) If so, please attach.
Yes
No
Comments: VELCO has defined Clearance 1 as the maximum allowed vegetation
heights (12ft high) at time of maintenance. This maximum height has evolved from
experience with regional growth rates and other factors. VELCO's Clearance 2 is
determined by the New England ISO's Operating Procedure 3, which is slightly more
stringent than IEEE 516.
4. Are there any other comments regarding the standard, its possible
modifications or the SAR?
Yes
No
Comments:
Page 4 of 4
Consideration of Comments on Second Draft of Vegetation Management SAR
(Project 2007-07)
The Vegetation Management SAR drafting team thanks all commenters who submitted
comments on Draft 2 of the SAR. This SAR was posted for a 30-day public comment period
from April 20 through May 9, 2007. The drafting team asked stakeholders to provide feedback
on the SAR through a special SAR Comment Form. There were 27 sets of comments, including
comments from 65 different people from more than 50 companies representing 7 of the 10
Industry Segments as shown in the table on the following pages.
Based on the comments received, the drafting team recommends that the Standards
Committee advance this SAR to the standard drafting step of the standard development
process. The drafting team made only one minor modification to the SAR to clarify (on page
2) that it is the ERO that will collect vegetation-related transmission outage data, not the SDT.
In this “Consideration of Comments” document stakeholder comments have been organized so
that it is easier to see the responses associated with each question. All comments received on
the standards can be viewed in their original format at:
http://www.nerc.com/~filez/standards/Vegetation-Management_Project_2007-7.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal
is to give every comment serious consideration in this process! If you feel there has been an
error or omission, you can contact the Director of Standards, Gerry Adamski, at 609-452-8060
or at [email protected]. In addition, there is a NERC Reliability Standards Appeals
Process.1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
Consideration of Comments on Second Draft of Vegetation Management SAR (Project 2007-07)
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 – Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
1.
Anita Lee (G1)
AESO
2.
Jay Farrington (G5)
Alabama Electric Coop.
9
3.
Randy Gann (G5) (G6)
Alabama Power
9
4.
Ken Goldsmith (G6)
ALT
5.
Mary Hetz
Ameren
9
6.
Raymond Wiesehan
(G5)
Ameren
9
7.
Thad Ness
American Electric Power
9
8.
John Neagle (G5)
Associated Electric Coop.
9
9.
William T. Rees, Jr.
Baltimore Gas & Electric
10.
Dave Rudolph (G6)
Basin Electric Power
Coop.
11.
Brent Kingsford (G1)
CAISO
12.
John R. Kellum, Jr.
CenterPoint Energy
9
13.
Weston J. Davis
Central Maine Power
9
14.
CJ Ingersoll
Constellation (CEDC)
15.
Gene Walton
Dominion
9
16.
Gregory Rowland
Duke Energy
9
17.
Billy George (G5)
Duke Energy, Carolinas
9
18.
Ralph Hale (G5)
Entergy
9
19.
Paul D. Olivier
Entergy Corporation
9
20.
Steve Myers (G1)
ERCOT
21.
Marc Tunstall (G5)
Fayetteville Public Works
Comm.
9
22.
Doug Hohlbaugh
FirstEnergy Corp.
9
23.
John Tamsberg
Florida Power & Light Co.
9
24.
Nancy Huddleston
(G6)
Georgia Power Co.
9
25.
Joe Knight (G6)
Great River Energy
26.
Steve Burns (G6)
Gulf Power Co.
2
3
4
5
6
7
8
9
10
9
9
9
9
9
9
9
9
9
9
9
Page 2 of 53
9
9
June 22, 2007
Consideration of Comments on Second Draft of Vegetation Management SAR (Project 2007-07)
Commenter
Organization
Industry Segment
1
2
3
4
5
6
9
9
7
8
9
10
27.
Ken Trump (G6)
Gulf Power Co.
9
28.
David Kiguel
Hydro One Networks Inc.
9
29.
George Juhn
Hydro One Networks Inc.
9
30.
Roger Champagne
Hydro-Québec
TransÉnergie (HQT)
9
31.
Ron Falsetti (I) (G1)
Independent Electricity
SO
9
32.
Matt Goldberg (G1)
ISO-NE
9
33.
Kathleen Goodman (I)
G2)
ISO-NE
9
34.
Robert Coish (I) (G6)
Manitoba Hydro
35.
Terry Bilke (G6)
Midwest ISO
9
36.
Mike Brytowski (G6)
Midwest Reliability
Organization
9
37.
Carol Gerou (G6)
Minnesota Power
9
38.
Bill Phillips (G1)
MISO
39.
Steve Craig (G6)
Mississippi Power Co.
9
40.
Ron Reinike (G6)
Mississippi Power Co.
9
41.
Thomas E. Sullivan
National Grid
9
42.
Anthony Johnson
Northeast Utilities
9
43.
Mike Calimano (I)
(G1)
NYISO
9
44.
Todd Gosnell (G6)
OPPD
45.
Stephen Tankersley
Pacific Gas and Electric
Co. (PGE)
46.
Alicia Daugherty (G1)
PJM
47.
Jack Gardner (G3)
(G5)
Progress Energy
Carolinas
9
48.
John Pinney (G3)
Progress Energy Florida
9
49.
Philip Riley (G4)
Public Service
Commission SC
9
50.
Mignon L. Clyburn
(G4)
Public Service
Commission SC
9
51.
Elizabeth B. Fleming
(G4)
Public Service
Commission SC
9
52.
G. O’Neal Hamilton
(G4)
Public Service
Commission SC
9
53.
John E. Howard (G4)
Public Service
Commission SC
9
54.
Randy Mitchell (G4)
Public Service
Commission SC
9
55.
C. Robert Moseley
(G4)
Public Service
Commission SC
9
9
9
9
9
9
9
Page 3 of 53
June 22, 2007
Consideration of Comments on Second Draft of Vegetation Management SAR (Project 2007-07)
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
56.
David A. Wright (G4)
Public Service
Commission SC
57.
John Wolfmeyer (G5)
SERC
58.
Jerry Lindler (G5)
South Carolina E&G
9
59.
Roman Carter (G6)
Southern Transmission
9
60.
Charles Yeung (G1)
SPP
61.
Richard Dearman (I)
(G5)
TVA
9
62.
Jeffrey S. Disorda
VELCO
9
63.
Jim Haigh (G6)
WAPA
9
64.
Neal Balu (G6)
WPSR
9
65.
Pam Oreschnick (G6)
Xcel Energy
9
9
9
9
I – Indicates that individual comments were submitted in addition to comments submitted as part of a
group
G1 – IRC Standards Review Committee (IRC SRC)
G2 – NPCC CP9 Reliability Standards Working Group (NPCC CP9)
G3 – Progress Energy Carolinas/Progress Energy Florida (PGN)
G4 – Public Service Company of South Carolina (PSC SC)
G5 – SERC Vegetation Management Subcommittee (SERC VMS)
G6 – Southern Company Transmission
G7– MRO Members
Page 4 of 53
June 22, 2007
Consideration of Comments on Second Draft of Vegetation Management SAR (Project 2007-07)
Index to Questions, Comments, and Responses
1.
Do you agree there is a reliability need for the proposed modifications and review of the
standard?.............................................................................................................. 6
2.
If you are a transmission owner, have you been provided a list from a Regional Entity
(formerly RRO) of sub 200 kV critical transmission lines that must comply with FAC-0031? .......................................................................................................................11
3.
If you are a transmission owner would you provide your methodology for determining
clearance 1 and clearance 2? (As described in FAC-003-1 R1.2.1 and R1.2.2) If so, please
attach..................................................................................................................16
4.
Are there any other comments regarding the standard, its possible modifications or the
SAR? ...................................................................................................................24
Page 5 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
1. Do you agree there is a reliability need for the proposed modifications and review of the standard?
Summary Consideration: Most commenters noted that while the FAC-003-1 Standard is technically adequate, they believed
that clarification in the form of a technical white paper, and review of applicability parameters is warranted. Many of these
commenters also agreed with the need to update the standard to conform to new procedural requirements and inclusion of
compliance elements. The SDT shall consider producing a white paper to aid in clarifying the intent of the standard.
Question #1
Commenter
AEP
Yes
No
Comment
AEP
believes
that
the
current
standard
(when
thoroughly read and understood) is
; completely adequate to maintain a reliable transmission
system with minimum risk of
vegetation-related outages.
Response: The team concurs that the technical elements are generally adequate and there is no reliability need to revise the
standard. However all NERC standards must be updated to comply with new procedural requirements and inclusion of
compliance elements. The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory
Reliability Standards for the Bulk Power System. The SDT shall consider producing a white paper to aid in clarifying the
intent of the standard.
Baltimore Gas &
not convinced that the elements outlined in the proposal will improve reliability and
; I'm
Electric
have concerns that the proposed modifications may actually reduce the flexibility that is
necessary to promote system reliability or to comply with local regulations. I would
prefer to see more specifics in the proposal before supporting the modifications.
Response: The team concurs that the technical elements are generally adequate and there is no reliability need to revise the
standard. However all NERC standards must be updated to comply with new procedural requirements and inclusion of
compliance elements. The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory
Reliability Standards for the Bulk Power System. The SDT shall consider producing a white paper to aid in clarifying the
intent of the standard.
CenterPoint Energy
Energy does not agree that a revision to the TVM standard is necessary from
; CenterPoint
a reliability standpoint, and believes that the existing TVM standard is adequate for that
purpose.
Response: The team concurs that the technical elements are generally adequate and there is no reliability need to revise the
standard. However all NERC standards must be updated to comply with new procedural requirements and inclusion of
compliance elements. The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory
Reliability Standards for the Bulk Power System. The SDT shall consider producing a white paper to aid in clarifying the
intent of the standard.
Central Maine Power
The current Vegetation Management Standard FAC-003-1 has been crafted in such a
; way
as to provide crisp measurable standards that when followed will provide a high
level of power quality for the bulk power delivery system. However, clearances between
Page 6 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #1
Commenter
Yes
No
Comment
conductors and trees required to prevent tree related power outages must be consistent
with each utility’s established standards and if a transmission line passes through
federal, state or locally managed areas this line placement should not impact the
established clearances. Utilities should not be expected to negotiate clearances with
multiple land managers.
The IEEE 516 – 2003 table is an acceptable table to use as the minimum clearance to
prevent a flash over and outages. FAC-003-1 is designed to be a reliability standard and
the industry adheres to OSHA and ANSI standards to protect workers and the public.
The IEEE 516 – 2003 table lists appropriate distances that should be used to measure
compliance. The standard should continue to provide the flexibility for utility managers
to increase “Clearance 2”.
The definition for right-of-way should be clarified to include only the area that is cleared
and included as routine maintenance.
We agree that there is a need to establish time horizons and clarify violation levels.
Response: The team concurs that the technical elements are generally adequate and there is no reliability need to revise the
standard. However all NERC standards must be updated to comply with new procedural requirements and inclusion of
compliance elements. The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory
Reliability Standards for the Bulk Power System, including a review of the definition for right-of-way. The SDT shall consider
producing a white paper to aid in clarifying the intent of the standard.
Duke Energy
a reliability perspective, the current standard contains appropriate requirements
; From
and measures to ensure the Transmission Owner's vegetation management program is
implemented and managed to ensure the reliability of the transmission system.
However the standard should be revised to address non-reliability related items that are
in the SAR.
Response: The SAR DT agrees and thanks you for the comment.
HQT
is our belief that the Standard in its current form does provide adequate provisions
; It
and drivers to minimize vegetation related outages and eliminate the likelihood of
reoccurence of the August 14, 2003 blackout. However, it is recognized that the
industry needs to consolidate its view on these provisions and we support the
preparation of a “white paper” that will document the rationale concerning the
requirements of the standard, as well as review certain aspects of the standard that
have come into question.
Response: The SAR DT agrees and thanks you for the comment.
Page 7 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #1
Commenter
Hydro One Networks
Yes
No
Comment
It
is
our
belief
that
the
Standard
in
its
current
form does provide adequate provisions
; and drivers to minimize vegetation related outages
and eliminate the likelihood of
reoccurence of the August 14, 2003 blackout. However, it is recognized that the
industry needs to consolidate its view on these provisions and we support the
preparation of a “white paper” that will document the rationale concerning the
requirements of the standard, as well as review certain aspects of the standard that
have come into question.
Response: The SAR DT agrees and thanks you for the comment.
National Grid
Grid believes that compliance with all elements of the present Standard will
; National
result in TO's achieving the reliability objectives set forth in the Standard.
Response: The SAR DT agrees and thanks you for the comment.
Northeast Utilities
modifications do not increase the levels of reliability above what is already
; Proposed
required in the current version of the Stnadard.
Response: The team concurs that the technical elements are generally adequate and there is no reliability need to revise the
standard. However all NERC standards must be updated to comply with new procedural requirements and inclusion of
compliance elements. The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory
Reliability Standards for the Bulk Power System. The SDT shall consider producing a white paper to aid in clarifying the
intent of the standard.
PGN
Energy Carolinas and Progress Energy Florida are providing an answer to the
; Progress
question as it relates to the reliability need. The current standard contains appropriate
requirements and measures to ensure the Transmission Owner's vegetation
management program is implemented and managed to ensure the reliability of the
transmission system. In addition, we do not believe that a standard with a zero
tolerance for vegetation-related outages in the ROW is in need of reliability-based
revisions.
However, we do recognize the need for a revision of the standard to address nonreliability related items that are in the SAR. Procedural items such as formatting and
clarifications, such as the definition of right-of-way, need to be, and should be,
addressed.
Response: The team concurs that the technical elements are generally adequate and there is no reliability need to revise the
standard. However all NERC standards must be updated to comply with new procedural requirements and inclusion of
compliance elements. The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory
Reliability Standards for the Bulk Power System. The SDT shall consider producing a white paper to aid in clarifying the
intent of the standard.
Page 8 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #1
Commenter
SERC VMS
Yes
No
;
Comment
The SERC VMS is providing an answer to the question as it relates to the reliability need.
The current standard contains appropriate requirements and measures to ensure the
Transmission Owner's vegetation management program is implemented and managed to
ensure the reliability of the transmission system. In addition, we do not believe that a
standard with a zero tolerance for vegetation-related outages in the ROW is in need of
reliability-based revisions.
However the SERC VMS recognizes the need for a revision of the standard to address
non-reliability related items that are in the SAR. Procedural items such as formatting
and clarifications, such as the definition of right-of-way, need to be, and should be,
addressed.
Response: The team concurs that the technical elements are generally adequate and there is no reliability need to revise the
standard. However all NERC standards must be updated to comply with new procedural requirements and inclusion of
compliance elements. The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory
Reliability Standards for the Bulk Power System. The SDT shall consider producing a white paper to aid in clarifying the
intent of the standard.
CECD
Modifications to capture the Commissions concerns must be addressed therefore these
;
actions are appropriate.
Response: The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory Reliability
Standards for the Bulk Power System.
Dominion
We support reinstating the 200kv threshold for reportable events.
;
Response: The Standard DT will review applicability as requested by the FERC. See also the drafting team responses to
question #2.
Entergy Corp.
The existing FAC-003-1 is flawed and needs revision.
;
Response: The SAR DT agrees that revisions of this standard are needed primarily to comply with new procedural
requirements and inclusion of compliance elements as well as address issues raised in the FERC’s March 16, 2007 Order 693
– Mandatory Reliability Standards for the Bulk Power System.
FirstEnergy Corp.
FirstEnergy agrees that clarification on select issues will aid the intent of this NERC
;
Standard.
Response: The SAR DT agrees and thanks you for the comment.
Florida Power & Light ;
FPL believes the technical portion of the standard provides adequate reliability protection
to the system. FPL also recognizes the need to re-format the standard to bring it into
conformance with the latest version of the Reliability Standard Development Procedure
and the ERO Sanctions Guidelines, to remove references to RRO in the standard and
substitute a responsible entity and, add compliance elements such as time horizons, and
Page 9 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #1
Commenter
Yes
No
Comment
violation severity levels.
Response: The SAR DT agrees and thanks you for the comment.
IESO
;
IRC SRC
ISO-NE
Manitoba Hydro
;
;
;
The definition of ROW should be clarified. The definition of a critical line should not be
kept to a particular voltage threshold. However, consideration could also then be given
to exempting non-critical lines operating at higher voltage levels (>200kv). Electrical
clearances should be consistent whether on Federal or non-Federal land.
Response: The standard DT will review the definition of ROW. The standard DT will review applicability parameters of this
standard, taking into account the comments from stakeholders such as NU, National Grid, Manitoba Hydro, First Energy, and
others. The SAR DT concurs with the commenter with respect to applying this standard to Federal and non-Federal lands. The
standard DT will evaluate the suitability of a case-by-case approach.
MRO
;
NYISO
PGE
;
;
As stated in the SAR.
Response: The SAR DT agrees and thanks you for the comment.
PSC SC
;
Southern Transm.
We do not feel there is a reliability need for modifying the standard. However, we do
agree certain modifications are needed to clarify procedural issues such as the amount of
time allowed for taking corrective action when items are found to be out of compliance.
Response: The team concurs that the technical elements are generally adequate and there is no reliability need to revise the
standard. However all NERC standards must be updated to comply with new procedural requirements and inclusion of
compliance elements. The Standard DT will address the issues raised in the FERC’s March 16, 2007 Order 693 - Mandatory
Reliability Standards for the Bulk Power System. The SDT shall consider producing a white paper to aid in clarifying the
intent of the standard.
TVA
The primary needs for mocdifications to this standard are in areas to address
;
clarifications and formatting not reliability related issues.
Response: The SAR DT agrees and thanks you for the comment.
;
Page 10 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
2. If you are a transmission owner, have you been provided a list from a Regional Entity (formerly RRO) of sub
200 kV critical transmission lines that must comply with FAC-003-1?
Summary Consideration: During the March 2007 SAR DT meeting, the FERC indicated they had not been presented any
evidence with respect to Regional Entity (RE) critical line determinations and asked whether such lists existed. This question
was posed to ascertain whether REs have determined which lines below 200 kV are critical.
Some commenters reported that their RE (SERC, FRCC, RFC) have determined there are no critical transmission lines that are
under 200 kV. Some commenters (NGrid, NU, HydroOne, HQT) indicated that a list was not provided by their RE (NPCC). A
commenter (MRO) noted that a list was submitted to NERC. A commenter responded that their RE (WECC) has provided such a
list. On the basis of this informal poll, the SAR DT’s assessment is that further specificity may be needed to aid in identifying
which <200kV transmission lines should come under the purview of this standard in an attempt to standardize this criteria..
The SDT shall take under consideration other applicability parameter criteria in addition to various stakeholder proposals.
Question #2
Commenter
Yes No
IRC SRC
NYISO
Baltimore Gas &
;
Electric
Response: The SAR DT thanks you
CECD
;
Comment
n/a
n/a
The reason that we do not have a list of critical lines from the RRO may be that we do
not have any lines that fit the criteria.
for your response.
SERC does not currently have any sub 200 kV critical transmission lines.
Response: The SAR DT thanks you for your response.
CenterPoint Energy
;
Central Maine Power
;
Duke Energy
;
The “Northeast Power Coordinating Council Facilities Notification List” may not be the
correct list to be used for this standard. FAC- 003-1 should set a clear expectation the
each Regional Entity will provide their transmission owners a list of critical lines including
any that may be less that 200KV. Will provide list once released from NPCC.
Response: The SAR DT thanks you for your response.
Dominion
;
The SERC region has not identified any lines below 200kV to be critical to the electrical
system in the region. Since no lines have been identified as critical to the region, no list
has been provided to Transmission Owners.
Response: The SAR DT thanks you for your response.
HQT
consider that it should be the Planning Coordinator role to determine the sub 200kV
; We
critical transmission lines and even for any transmission lines irrelevant of voltage level.
Page 11 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #2
Commenter
Comment
For that, it should follow an impact based methodology such as the one used in NPCC.
Response: The SAR DT thanks you for your response.
Hydro One Networks
;
Manitoba Hydro
MRO
Yes
No
;
;
The MRO We have not generated a list or criteria yet. We have submitted a draft criteria
to NERC
Response: The SAR DT thanks you for your response.
National Grid
Reliability Entity has not provided a list of sub 200 kV lines subject to compliance
; The
with FAC-003-1. The Standard became effective in February 2007, just 3 months ago.
Having no list today should not imply that the RE or the Standard has failed in any way.
National Grid suggests that a revised Standard should direct the RE to produce a list of
"sub 200 kV critical transmission lines" within 6 to 12 months of adoption.
Response: The standard DT will review applicability parameters of this standard, taking into account the comments from
stakeholders such as NU, National Grid, Manitoba Hydro, First Energy, and others.
Northeast Utilities
Reliability Entity has not provided a list of facilities covered under FAC-003-1. This
; The
is not a fault of the RE as there has been no direction provided as to what factors or
charateristics are required for sub-200kV lines to be included under the Standard. It is
our position that the factors that will be used to develop the list of sub-200kV faciltities
to be covered by the Standard be developed at the national level (NERC) and adopted by
all RE's for consistency.
Response: The standard DT will review applicability parameters of this standard, taking into account the comments from
stakeholders such as NU, National Grid, Manitoba Hydro, First Energy, and others.
PGN
SERC and FRCC regions have not identified any lines below 200kV to be critical to
; The
the electrical system in the region. Since no lines have been identified as critical to the
region, no list has been provided to Progress Energy Carolinas and Progress Energy
Florida. (Please note our comments on this issue in question #4.)
Response: The SAR DT thanks you for your response.
SERC VMS
SERC region has not identified any lines below 200kV to be critical to the electrical
; The
system in the region. Since no lines have been identified as critical to the region, no list
has been provided to Transmission Owners. (Please note the subcommittee's comments
on this issue in question #4.)
Response: The SAR DT thanks you for your response.
TVA
detemined that there are no TVA lines below 200kv that must comply to this
; We
standard due to their criticial needs in SERC.
Page 12 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #2
Commenter
Yes No
Comment
Response: The SAR DT thanks you for your response.
VELCO
has not been provided a specific list of critical lines below 200 kV from the RE
; VELCO
that need to be in compliance with FAC-003-1. VELCO suggests changing the wording in
the standard to identify those lines affected as 200 kV and great or those defined as Bulk
Power System facilities.
Response: The standard DT will review applicability parameters of this standard, taking into account the comments from
stakeholders such as NU, National Grid, Manitoba Hydro, First Energy, and others.
Entergy Corp.
Yes, the Reliability Entity (SERC) has performed its duty in evaluating our transmission
;
system. SERC has confirmed that Entergy has no lines operating below 200kV that are
critical to system reliability. Entergy has received its "list," but the list is blank.
With respect to applicability, it is inappropriate to set a blunt voltage level criterion for
determining which transmission lines are critical to bulk system reliability. There is no
basis in engineering or in fact for voltage-based categories of applicability. Many lines
operating at 200kV and higher essentially serve only local load, and there may in fact be
some lines operating below 200kV where the standard should be applied. Many lines of
all voltages are redundant and do not even impact local load during an outage.
Therefore, the voltage criterion is overly broad.
To support this statement, Entergy supplies the following facts:
First, during the aftermath of Hurricanes Katrina and Rita, Entergy had (59) 230kV and
500kV lines out of service simultaneously. Additionally, Entergy had (85) 115kV and
161kV lines out of service simultaneously. During the aftermath of Hurricane Rita,
Entergy had (41) 230kV and 500kV lines out of service simultaneously. Additionally,
Entergy had (124) 115kV and 161kV lines out of service simultaneously. Dispite this
overwhelming combination of simultaneous outages, no system-wide cascading blackout
was initiated. Only local load was lost during restoration. This illustrates that Standard
FAC-003-1, as it currently stands placing so much focus and penalty on even singlecontingency outages, is overbroad, arbitrary and capricious.
Second, each year the Entergy transmission system (like all other large electric utilities)
suffers numerous outages from a great number of different sources: material defects, rot
and decay, animal damage, human damage, extreme wind, lightning and, vegetation.
Over the years 2001 through 2006, 927 transmission lines suffered 5,688 outages from
a variety of sources. Vegetation outages accounted for 7.14% of those outages. Each
Page 13 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #2
Commenter
Yes
No
Comment
utility is unique, but these numbers are not unusual for a transmission system
comprising 15,000 miles of line. Dispite this large number of outages, no cascading
system black out has been intiated.
Finally, Entergy has had as many as 17 transmission lines outaged from a single tornado
event without even losing service to local load. Standard FAC-003-1 assigns too much
risk to outages in general, and too mush risk to vegetation outages in particular.
NERC and the regional reliability entities should define performance criteria that
specifically define certain contingencies and certain undesireable outcomes that would
classify a line as truly critical to bulk system reliability. The modeling software necessary
to do this is readily available and already in use today by the Reliability Entities and their
subject utilities.
If FERC has concerns about potentially devistating (albeit rare) combinations of multiple
simultaneous line outage contingencies, the REs can define strict criteria for multiple
contingencies. With respect to lines that result in IROLs and SOLs, these lines can also
be identified with specificity, without resorting to blunt voltage distinctions.
Defining system-critical lines too broadly is actually detrimental to FERC's reliability
goals. It dilutes the resources available to maintain reliability on those lines that truly
affect system reliability. Utilities should employ a more focused and intelligent approach
to targeted reliability. Such an approach would have benefits to the users of the
transmission system and to the ratepayers that pay for it.
Response: The standard DT will review applicability parameters of this standard, taking into account the comments from
stakeholders such as yourself and others.
Florida Power & Light ;
PGE
;
Provided from WECC
Response: The SAR DT thanks you for your response.
AEP
the three regions in which AEP has transmission facilities, only one RE has provided a
; ; Of
listing of sub-200 kV facilities of what we consider applicable under this standard.
Response: The SAR DT thanks you for your response.
FirstEnergy Corp.
the Reliability Entity (formerly the RRO) was requested to provide a list of
; ; ReliabilityFirst,
lines below 200 kV deemed as critical transmission lines that must comply with FAC-00301. ReliabilityFirst responded "there are no lines below 200kV deemed as critical
Page 14 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #2
Commenter
Yes
No
Comment
infrastructure".
Response: The SAR DT thanks you for your response.
Southern Transm.
are not really sure how to answer this question. The Regional Entity has not sent us
; ; We
a list, but they have advised us that we do not have any sub 200 kv critical transmisison
lines that must comply with FAC-003-1.
Response: The SAR DT thanks you for your response.
Page 15 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
3. If you are a transmission owner would you provide your methodology for determining clearance 1 and
clearance 2? (As described in FAC-003-1 R1.2.1 and R1.2.2) If so, please attach.
Summary Consideration: This question was posed to poll transmission owners with respect to determination of Clearance 1
and Clearance 2 requirements. This information was sought to obtain examples of how industry members determine Clearance
1 since it is a qualitative requirement. Clearance 2 information was sought to evaluate the application of components of IEEE
516.
Of the 15 respondents to this poll question, some provided summary methodology for determining their Clearance 1 and
Clearance 2, others have indicated that a methodology exists and is available upon request. On the basis of these responses to
the poll question, the SDT shall consider reviewing IEEE 516 components to affirm their suitability in this standard and this
information can assist in a white paper.
Question #3
Commenter
Yes No
IRC SRC
NYISO
SERC VMS
Response: The SAR DT thanks you
Baltimore Gas &
;
Electric
Central Maine Power
;
Comment
n/a
n/a
This question does not apply to the SERC EC Vegetation Management Subcommittee.
for your response.
The clearance 2 was taken directly from IEEE Table 516 – 2003. Clearance 1 is based on
“Appendix C – ISO New England Right of way Vegetation Management Standard”.
Response: The SAR DT thanks you for your response.
Florida Power & Light
;
National Grid
Detailed methodology is not attached. In summary, National Grid used Table 5 IEEE
Section 516 for determing clearance 2. These data for each voltage class were rounded
to the next higher whole number. Clearance 1 was determined by adding the clearance
2 distance, conductor sag distance, and anticipated tree growth over the maintenance
cycle.
Response: The SAR DT thanks you for your response.
PGN
Energy has an individual on the Drafting Team and will share the Progress
; Progress
Energy Florida clearance Tables with the team.
Response: The SAR DT thanks you for your response.
VELCO
has defined Clearance 1 as the maximum allowed vegetation heights (12ft high)
; VELCO
at time of maintenance. This maximum height has evolved from experience with regional
;
Page 16 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #3
Commenter
Yes
No
Comment
growth rates and other factors. VELCO's Clearance 2 is determined by the New England
ISO's Operating Procedure 3, which is slightly more stringent than IEEE 516.
Response: The SAR DT thanks you for your response.
AEP
For Clearance 1, AEP has chosen to use the minimum approach distances set forth in
;
ANSI Tree Care Standard Z133.1 (rev. October 2000) for persons other than qualified
line-clearance arborists and qualified line-clearance arborist trainees. For Clearance 2,
AEP utilizes the Z133.1 minimum approach distances for qualified line clearance arborists
and qualified line-clearance arborist trainees.
Response: The SAR DT thanks you for your response.
CenterPoint Energy
CenterPoint Energy has developed a methodology to determine clearance 1 and
;
clearance 2 as described in FAC-003-1 R1.2.1 and R1.2.2. This methodology is included
in a document titled "Specification for Transmission Vegetation Management Program"
dated February 2007. Section 5.1 of that document covers NERC Clearance 1, and
Section 5.2 covers NERC Clearance 2. Text and Tables from both Sections 5.1 and 5.2
are shown below:
5.1
NERC CLEARANCE 1
5.1.1 The appropriate clearance to conductors at the time of vegetation management
work is established as Clearance 1 in accordance with NERC Standard FAC-003-1
Requirement R1.2.1.
5.1.2 Clearance 1 is determined by considering transmission line voltage, the effects of
ambient temperature on conductor sag under maximum design loading, the effects of
wind velocities on conductor sway, and the anticipated average growth rate of the
prevalent tree species within the Company’s service area over a 5-year period.
5.1.2.1
The minimum clearance distance of IEEE Standard 516-2003 Section
4.2.2.3, Minimum Air Insulation Distances without Tools in the Air Gap, is a component
of Clearance 1.
5.1.3 Table 5.1 contains the horizontal clearance components and nominal values for
Clearance 1, and Table 5.2 contains the vertical clearance components and nominal
values for Clearance 1.
Table 5.1
Page 17 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #3
Commenter
Yes
No
Comment
NERC Clearance 1: Horizontal Clearance, feet
Horizontal Clearance Component, Nominal Voltage p-p
69kV 138kV 345kV
Electrical Clearance (1)
Average 5-Year Horizontal Tree Growth
2.46
2.95
12.00 12.00
12.00
Average Mid-span Conductor Sway (2)
Total
5.98
20.44
Nominal Horizontal Value (3)
4.40
8.13 10.04
23.08 26.44
20
23
26
(1) Based on IEEE 516-2003 Table 5 for 69kV & 138kV and Table 7 for 345kV
(2) Based on NESC C2-2007 Rule 233A(1)
(3) May be reduced for site specific tree species or conductor span configuration but not
less than Clearance 2.
Table 5.2
NERC Clearance 1: Vertical Clearance, feet
Vertical Clearance Component, Nominal Voltage p-p
69kV 138kV 345kV
Electrical Clearance (1)
2.46
Average 5-Year Vertical Tree Growth
Average Conductor Final Sag Increase (2)
2.95
4.40
15.75 15.75
15.75
7.52
9.01 10.24
Total
25.73
27.71 30.39
Nominal Vertical Value (3)
26
28
Page 18 of 53
30
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #3
Commenter
Yes
No
Comment
(1) Based on IEEE 516-2003 Table 5 for 69kV & 138kV and Table 7 for 345kV
(2) Based on NESC C2-2007 Rule 233A(1)
(3) May be reduced for site specific tree species or conductor span configuration but not
less than Clearance 2.
5.2
NERC CLEARANCE 2
5.2.1 The minimum radial clearance to prevent flashover between vegetation and
conductors is established as Clearance 2 in accordance with NERC Standard FAC-003-1
Requirement R1.2.2.
5.2.2 Clearance 2 is determined by considering transmission line voltage, the effects of
ambient temperature on conductor sag under maximum design loading, and the effects
of wind velocities on conductor sway. Clearance 2 is a radial clearance, so the vertical
component and the horizontal component are both calculated, and the largest clearance
is selected as the prevailing clearance for Clearance 2.
5.2.2.1
The minimum clearance distance of IEEE Standard 516-2003 Section
4.2.2.3, Minimum Air Insulation Distances without Tools in the Air Gap, is a component
of Clearance 2.
5.2.3 Table 5.3 contains the horizontal clearance component, Table 5.4 contains the
vertical clearance component, and Table 5.5 contains the prevailing nominal values for
Clearance 2.
Table 5.3
Horizontal Clearance Component, feet
Horizontal Clearance Component, Nominal Voltage p-p
69kV
138kV 345kV
Electrical Clearance (1)
2.46
2.95
Average Mid-span Conductor Sway (2)
5.98
8.13 10.04
Page 19 of 53
4.40
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #3
Commenter
Yes
No
Comment
8.44 11.08 14.44
Total
Nominal Horizontal Value (3)
8
11
14
(1) Based on IEEE 516-2003 Table 5 for 69kV & 138kV and Table 7 for 345kV
(2) Based on NESC C2-2007 Rule 233A(1)
(3) May be reduced for site specific tree species or conductor span configuration but not
less than Clearance 2.
Table 5.4
Vertical Clearance Component, feet
Vertical Clearance Component, Nominal Voltage p-p
69kV
138kV 345kV
Electrical Clearance (1)
2.46
2.95
Average Conductor Final Sag Increase (2) 7.52
9.01
10.24
11.96
12
14.64
15
Total
Nominal Vertical Value (3)
9.98
10
4.40
(1) Based on IEEE 516-2003 Table 5 for 69kV & 138kV and Table 7 for 345kV
(2) Based on NESC C2-2007 Rule 233A(1)
(3) May be reduced for site specific tree species or conductor span configuration but not
less than Clearance 2.
Table 5.5
NERC Clearance 2: Minimum Radial Clearance to Prevent Flashover, feet
Nominal Voltage p-p
69kV
138kV 345kV
10 12
15
Page 20 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #3
Commenter
Yes No
Comment
Response: The SAR DT thanks you for your response.
Entergy Corp.
Entergy defines four sets of clearances for vegetation approach to transmission lines.
;
The first set of clearances is the Vegetation Pruning Distance. This is the clearance to be
achieved at the time of vegetation management work which vegetation management
employees and contractors complete as part of this program. This distance varies with
each line, but is set to be the EDGE OF ROW in each case. (This clearance is referred to
as “Clearance 1” in the NERC Vegetation standard FAC-003-1, Cf B.R1.2.1).
The second set of clearances is the Vegetation Growth Alert Distance. This is the
approach distance that triggers an alert to the Asset Management vegetation
management employees that vegetation maintenance is required. Vegetation spotted on
an aerial inspection that encroaches upon this clearance is noted on the inspection for
future scheduling of pruning.
The third set of clearances is the Minimum Energized Pruning Distance. This is the
minimum approach distance vegetation can have to energized transmission lines and still
be pruned without an outage on the energized transmission line, in accordance with
OSHA safety guidelines. Any vegetation that encroaches on this minimum distance must
be pruned, and must be pruned during an outage on the associated transmission line.
The fourth set of clearances is the Minimum Vegetation Approach Distance. This is the
absolute minimum radial approach distance to prevent flashover between vegetation and
overhead ungrounded supply conductors. Under this program, vegetation should never
encroach these minimum approach distances. Vegetation must be pruned prior to
reaching this distance and must be pruned with an outage on the transmission line.
(This distance is referred to as “Clearance 2” in the NERC vegetation standard, FAC-0031, Cf B.R1.2.2.) These clearance distances are based upon those set forth in the Institute
of Electrical and Electronics Engineers (IEEE) Standard 516-2003 (Guide for
Maintenance Methods on Energized Power Lines) and as specified in Table 5.
Under this program, vegetation can encroach the Vegetation Growth Alert Distance and
the Minimum Energized Pruning Distance, but it shall not encroach upon the Minimum
Vegetation Approach Distance.
Response: The SAR DT thanks you for your response.
Page 21 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #3
Commenter
FirstEnergy Corp.
Yes
;
No
Comment
For R1.2.1 (Clearance 1), FirstEnergy used our existing specification requirement "for
minimum clearance to be achieved at locations with an easement or other restriction" to
define the minimum acceptable clearance.
For R1.2.2 (Clearance 2), FirstEnergy uses the IEEE 516-2003 standard as the minimum
as referenced in FAC-003-01. This is the minimum clearance under all operating
conditions. FirstEnergy believes this is an appropriate definition.
Response: The SAR DT thanks you for your response.
HQT
HQT clearance methodology is not specifically based on the value specified in Clearance
;
1 and Clearance 2. HQT TVMP is such organized that vegetation management work
minimize costs for line clearing and brush control while preventing outages from
vegetation cause. As such, staff qualifications required to work near energized facilities
are less than under the absolute minimum as stipulated in IEEE 516-2003, and in most
cases, the work is less labour and equipment intensive. However clearances are never
less than the absolute minimum stipulated in FAC-003-1 (R1.2.2).
The above provides the basic approach used at HQT. If the Standard Drafting Team
would like a copy of the HQT approach and methodology, this could be provided.
Response: The SAR DT thanks you for your response.
Hydro One Networks
Hydro One clearance standards are based on the Ontario Health and Safety Act (OHSA)
;
clearances rather than the absolute minimum specified in Clearance 2. OHSA clearances
at time of work minimize costs for line clearing and brush control. By maintaining OHSA
clearances during normal working conditions, staff qualifications required to work near
energized facilities are less than under the absolute minimum as stipulated in IEEE 5153003, and in most cases, the work is less labour and equipment intensive. As part of
work planning, qualified staff determine the amount of vegetation that has to be
removed to achieve OHSA clearances at the time of the next scheduled work. As well,
provisions are built into the clearances at time of work to account for conductor and tree
movement during adverse weather conditions. The objective is to provide OHSA
clearances under adverse conditions, but these are not always achieved, however
clearances are never less than the absolute minimum stipulated in FAC-003-1.
The above provides a description of our planning process. If the Standard Drafting Team
would like a copy of the Hydro One standard, this can be provided.
Response: The SAR DT thanks you for your response.
Page 22 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #3
Commenter
Manitoba Hydro
Yes
Northeast Utilities
;
No
Comment
Clearance
1
was
developed
based
on
the
limits of approach for non-qualified people
;
(public). At a minimum, we would clear beyond this distance during vegetation control
activities. Our cycle times and management approach are adjusted for this distance,
taking into account growth rates. The values will vary depending on voltage class.
Clearance 2 is based on internal design standards that take into account our
understanding of switching surge values for our system. The values used are more
conservative than IEEE 516-2003.
Response: The SAR DT thanks you for your response.
MRO
n/a
;
The methodology for determining clearance 2 is based on the requirements of FAC-0031. The IEEE Section 516 has been considered the base minimum limits for clearances as
provided under FAC-003-1 R.1.2.2. Clearances used for R.1.2.1 on the NU Transmission
System comply with the requirements of ISO-NE Operating Procedure OP-3, that
provides clearance levels required at the time of vegetation trimming or clearing under
the various transmission voltages.
Response: The SAR DT thanks you for your response.
PGE
Will be provided to the SARDT in a separate attachment[TH1].
;
Response: The SAR DT thanks you for your response.
Southern Transm.
IEEE 516-2003, Section 4.2.2.3 was adopted as the minimum allowable distance for
;
Clearance 2, with the expectation that work would normally occur prior to Clearance 2
reaching the minimum allowable distance. Clearance 1 was determined by using the
Clearance 2 value and adding a growth buffer. Sagging of conductors and their
movement in wind was then considered to ensure the growth buffer is adequate.
Response: The SAR DT thanks you for your response.
TVA
We utilize a clearance 2 based on IEEE 516 2003 Table 5 criteria. Our Clearance 1 is a
;
greater amount to allow for growth between clearing and next inspection or clearance
activities. We will provide our tables is requested.
Response: The SAR DT thanks you for your response.
Page 23 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
4. Are there any other comments regarding the standard, its possible modifications or the SAR?
Summary Consideration:
The comments were mixed with regard to:
• Whether reporting of Category 3 outages are necessary.
Most that commented agreed that:
• The 200kV applicability threshold could be clarified and the SAR DT deemed a review of applicability parameters is
desirable.
• A consistent approach to both federal and non federal lands is desirable.
• A review of the definition of ROW is desirable.
• Components of the IEEE 516 standard are suitable.
• The exclusion of major disaster related events is appropriate.
• The inclusion of compliance elements and other procedural updates of the standard are needed.
• The development of a technical white paper is desirable.
• The standard DT should review the need for Requirement R4.
On the whole, the comments are supportive of the SAR as written and the SAR DT have made no changes to the second draft
of the request.
Question #4
Commenter
CenterPoint Energy
Yes
;
;
;
;
Manitoba Hydro
PSC SC
Southern Transm.
AEP
No
Comment
We appreciate the efforts of the SAR Drafting Team.
The SAR directs the SDT to collect and analyze outage data as part of an effort to define
clearances for transmission lines on federal and non-federal lands. AEP believes that the
analysis of outage data will be meaningless and unproductive. The SAR directive
presupposes a cause-and-effect relationship between vegetation-related outages and
federal/non-federal land status. On the contrary, AEP believes that vegetation-related
data is more indicative of the effectiveness of the utility's VM program, in spite of
onerous and inordinately expensive measures required on federal lands.
Response: The standard DT looks to receive the results of the ERO analysis and use it in developing the standard.
;
Page 24 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Ameren
Yes
;
No
Comment
Ameren does not agree that each of 11 items listed in the SAR are necessary to improve
reliability. The following comments are offered for each of the 11 items identified in the
SAR detail description:
1. Standard Applicability:
Ameren disagrees with revising the 200 kV threshold for determining facilities subject to
this standard. Extending the requirements to lines other than those >200kV will dilute
the focus on those lines that impact grid reliability and shift attention to facilities,
<200kV. Utilities generally have an incentive to maintain reliability on lines less than
200kV. State commissions and customer expectations for reliable service provide this
incentive. While many facilities above 200kV directly support customer load,
transmission lines below 200kV primarily support customer load, and interruptions to
those facilities reduces load on the grid.
The majority of transmission facilities below 200 kV also have significantly different
design/construction/operating characteristics and have not been cited as impacting bulk
power system reliability. For example, the Final Report on the August 14, 2003 Blackout
in the United states and Canada: Causes and Recommendations April 2004 by the U.S.Canada Power System Outage Task Force and all referenced major blackouts (pages
103-115) in that report, cited only outages which involved vegetation at line voltages
above 200kV. Generally applying requirements that are appropriate for >200kV lines to
lines less than 200kV will result in significant documentation and reporting of items such
as restrictions, mitigation plans, off right-of-way vegetation-related outage investigation/
information and other issues, all of which dilutes the focus on lines that directly impact
bulk power system reliability.
Revising the standard to use general criteria or broad language for defining "Bulk Power
System" transmission lines covered by the standard is a “one size fits all” approach. If
that approach were taken, the standard would cover a significant number of
transmission lines that have no direct impact on bulk power system reliability under
standard planning/operating conditions, resulting in a significant cost burden for electric
customers without improving “grid” reliability. Ameren believes that the applicability
provision of the standard should focus attention of the standard only on the transmission
lines below 200kV that directly impact “Bulk Power System” reliability, as the current
version requires.
Page 25 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
Ameren recognizes some validity in the Commission’s concern; Ameren recommends
that the applicability provision of this standard should be revised only if existing system
design, planning or operating reliability criteria and parameters are considered as a basis
for defining the applicability of the standard. Ameren recommends each Regional Entity
(RE) determine applicability of FAC-003 to those lines within the region that are between
100kV and 200KV, if, and only if, they are identified as operationally significant elements
of Interconnection Reliability Operating Limits (“IROLs”). That is, any facility below
200kV that by itself would cause an Interconnected Reliability Limit Violation should the
facility be outaged.
2. Issue of Clearances (Federal vs Non-Federal Lands):
FAC-003-1 presently requires the transmission owner (TO) “identify and document
clearances between vegetation and any overhead, ungrounded supply conductors, taking
into consideration transmission line voltage, the effects of ambient temperature on
conductor sag under maximum design loading, and the effects of wind velocities on
conductor sway.” The intent of this requirement is to ensure adequate clearances to
prevent vegetation related outages. Ameren believes that only the TO has the technical
information required to determine the clearances that are necessary at the time of VM
work and that any “federal lands exemption” to clearances will result in inadequate
clearances for the existing conditions. Consistency in application of the TO’s clearance
requirements, not exceptions, is the only assurance in providing a uniform and reliable
electrical system to meet the nation’s current and future energy demands.
Any exception for a case by case clearance approach to determine vegetation
management activities/clearances on Federal lands will continue to drive inconsistency
and/or delays associated with vegetation management decisions being driven by diverse
vegetation management practices/beliefs and staff changes at the local level of Federal
agencies. Vegetation-related outages have occurred on Federal lands as a result of this
case by case approach, and if “Bulk Power Transmission System” lines continue to be
addressed on a “case by case” basis on National Forest Service (or any other Federal
lands), those lines will potentially be subject to a higher risk for vegetation-related
outages, resulting in reduced reliability for the “Bulk Power System”.
Ameren believes that reliability of the “Bulk Power System” should have the same focus
on Federal and private lands and that the EEI MOU with federal agencies is the
Page 26 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
appropriate vehicle for TO's to identify clearance variances on Ferderal lands, not
exemption language in the standard. The standard should not be used as a mechanism
by federal agencies to impose variances to proven vegetation management practices and
clearances.
3. Defining Right-of-Way:
Ameren agrees that it is appropriate to further address the definition of “right-of-way”.
Corridor widths beyond design clearance requirements have been acquired for a variety
of reasons in the past; future use, property line buffers, etc. Vegetation in those areas
that would normally fall outside of the area necessary for operation of the facility should
not be considered or treated different than vegetation that is outside of a defined
easement/permit area that is designed for the reliable operation of an existing single line
corridor.
4. IEEE Standard for Minimum Clearances:
Ameren disagrees with objections to the use of the IEEE 516-2003 clearance as the
minimum acceptable distances for “Clearance 2”. The IEEE 516-2003 tables are
appropriate for defining the minimum acceptable clearances to prevent flashover
between conductors and vegetation under all rated electrical operating conditions.
FERC staff references ANSI Z-133 which is a safety standard that addresses worker
safety as well as the safety of the general public. As such, the purpose of ANSI Z-133 is
to address worker safety and is not focused on transmission line reliability, which is the
purpose of FAC-003-1. OSHA, NESC and other related safety standards have clearances
in excess of IEEE 516-2003. Those clearances are clearly focused on safety issues and
will still apply to other aspects of design and operation of electric facilities (such as
public and worker safety) but are not appropriate to be referenced in a vegetation
management reliability standard.
5/6/7.
Procedural Items:
Ameren agrees that the procedural items related to formatting RRO references and
additional compliance elements should be addressed by the standard drafting team.
8. Technical Reference Materials:
Page 27 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
Ameren agrees that a “white paper” that defines the technical basis for the standard is
appropriate to avoid the potential for differences in interpretation of the standard’s
requirements during the various region's audit processes.
9. Category 3 Outages:
Since the right to control off right-of-way vegetation is generally beyond control of the
transmission owner Ameren believes that the reporting of category 3 outages should be
removed from the requirements.
10. Requirement R4:
Ameren believes that requirement R4 should be deleted from the standard, based on the
ERO formation and the process for delegation of authority to the regional entities.
11. Reporting Exemptions:
Ameren believes that the reporting requirement exemptions for natural disasters should
include all categories of outages. It would, for example, be difficult, without delaying
restoration efforts, to determine if the vegetation from high winds, hurricanes,
tornadoes, etc. is from on or off the "right-of-way".
Response:
1. The standard DT will review applicability parameters of this standard, taking into account the comments from
stakeholders such as NU, National Grid, Manitoba Hydro, First Energy, and others.
2. The SAR DT concurs with the commenter with respect to applying this standard to Federal and non-Federal lands. The
standard DT will evaluate the suitability of a case-by-case approach.
3. The standard DT will review the definition of ROW.
4. The SAR DT agrees with the commenter and recognizes that sections of IEEE 516 standard pertaining to minimum air
insulation distances are applicable in determining minimum vegetation clearances to prevent flashovers.
5. NERC standards must be updated to comply with new procedural requirements and must include compliance elements.
6. See #5
7. See #5
8. The SDT shall consider producing a white paper to aid in clarifying the intent of the standard.
9. The SAR indicates that the Standard Drafting Team will review reporting criteria for Category 3 outages and will review
the reporting requirement of Category 3 outages in R.3 and R.4.
Page 28 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes No
Comment
10. The standard DT will consider deletion of R.4.
11. The standard DT will review the reporting exemptions to include all category outages under major disasters in
Requirement R3.2.
Baltimore Gas &
We completely disagree with the proposal to eliminate reporting or off-right-of-way tree
;
Electric
outages. In reality, off-R/W outages can cause many of the same problems that on R/W
outages do if they were to occur at the most inappropriate time. Granted that they
typically do not occur at times of peak load, but they could. Moreover, many off-R/W
tree outages are preventable and should be addressed before they occur.
Response: The SAR indicates that the Standard Drafting Team will review reporting criteria for Category 3 outages and will
review the reporting requirement of Category 3 outages in R.3 and R.4.
CECD
CECD supports continuing to use the 200kV threshold for determining applicability of
vegetation management criteria. If the standard is deemed to apply to lower voltages
these should only be critical lower voltage transmission facilities as determined by the
Regional Entities's. CECD would also encourage the drafting team to clarify that the
Vegetation Management standards are not applicable to generator interconnection
facilities. In the registration process due to the NERC functional definitions, Generation
Owners/Operators are required to register as Transmission Owners/Operators because of
step-up transformers and other associated interconnection equipment that was not
intended to be subject to the Vegetation Management program.
Response: The standard DT will review applicability parameters of this standard, taking into account the comments from
stakeholders such as NU, National Grid, Manitoba Hydro, First Energy, and others.
;
As a registered transmission owner this standard is applicable. Registration matters should be referred to the NERC
organization certification program and the related regional entity.
Central Maine Power
The standard FAC-003-1 is intended to create a frame work that will ensure a uniform
;
level of reliability and at the same time must allow transmission owners to meet this
objective using efficient and cost effective programs. To this end utilities must have the
ability to implement “Clearance 1” distances consistently throughout their service areas.
The standard should remain focused only on 200 KV and above lines or lines listed as
critical by the Regional Entity.
Inspection cycles are sufficient as listed the current version and allow flexibility to meet
local variability in growth rates and other conditions. Concerns with inspection cycle
length can be addressed in the compliance area.
Page 29 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes No
Comment
Response: The SAR DT thanks you for your comments.
The standard DT will review applicability parameters of this standard, taking into account the comments from stakeholders
such as yourself and others.
The FERC is no longer indicating a need to develop a requirement for a minimum inspection cycle (March 16, 2007 Order 693)
and stakeholders indicated they did not support this change, so it was removed from the SAR.
Dominion
In response to Stakeholder item #11, we do not support exempting Category 1 or
;
Category 2 events that occur during natural disasters.
Response: A majority of the industry stakeholder comments support natural disaster exemptions.
Duke Energy
Regarding the Order 693 items, the applicability provision of the standard should focus
;
attention of the standard only on the transmission lines 200kV and above, and those
lines below 200kV that directly impact “Bulk Power System” reliability, as the current
version of FAC-003 requires. Each Regional Entity (RE) must determine applicability of
FAC-003 to those lines within the region that are less than 200kV. For example,
transmission lines below 200kV should be considered within the scope of FAC-003 if they
are identified as operationally significant elements of Interconnection Reliability
Operating Limits (“IROLs”); i.e. an outage of the facility would cause an Interconnection
Reliability Limit Violation.
The Standard DT should address the issue of the necessity of maintaining consistent
clearances for lines on both federal and non-federal lands.
We agree with the use of the IEEE 516-2003 standard for for defining the minimum
acceptable clearances to prevent flashover between conductors and vegetation under all
rated electrical operating conditions.
We believe that the reporting requirement exemptions for natural disasters should
include all categories of outages.
Response: The standard DT will review applicability parameters of this standard, taking into account the comments from
stakeholders such as NU, National Grid, Manitoba Hydro, First Energy, and others.
The SAR DT concurs with the commenter with respect to applying this standard to Federal and non-Federal lands. The
standard DT will evaluate the suitability of a case-by-case approach.
The SAR DT agrees with the commenter and recognizes that sections of IEEE 516 standard pertaining to minimum air
insulation distances are applicable in determining minimum vegetation clearances to prevent flashovers.
Page 30 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes No
Comment
The standard DT will review the reporting exemptions to include all category outages under major disasters in Requirement
R3.2.
Entergy Corp.
The policy to increase sanctions based on a finding of an "intentional economic decision
;
to violate the standard" is ill-concieved:
1. Every transmission line outage that has ever occured could have been avoided if
more money had been spent on SOMETHING, SOMWHERE.
2. No utility has an unlimited budget, so decisions based on risk, cost and benefit are
made every day.
3. After the outage, the localized initiating cause will appear so trivial and inexpensive
that it would seem that it could easily have been fixed in advance.
4. Therefore, reviewers could conclude that EVERY outage (a defacto violation of the
standard), is the result of an "economic decision to violate the standard."
Economic choices are a necessary and natural part of doing business, and do not
necessarily imply the existence of malicious motives or wrong-doing.
The current policy is going to create unnecessary costs to ratepayers, even to avoid
inconsequential outages.
Response: The compliance sanctions guideline addresses the matter of willful noncompliance. Refer to the Compliance
program with respect to this issue. However the standard DT and Compliance Elements DT will review and assign Violation
Severity Levels when modifying FAC-003-1.
FirstEnergy Corp.
The definition of Right-Of-Way requires modification to clarify it is the width required by
;
engineering to operate the line. This may or may not be the legal Right-of-Way. (See
previously submitted comments submitted by FE in Feb 2007 for more details).
Response: The standard DT will review the definition of ROW.
Florida Power & Light ;
For the record FPL re-emphasize its comments from the previous FAC 003-1 SAR.
Requirement 3.2 exempts reporting of outages from outside the ROW when natural
disasters such as tornados or hurricanes occur. Our experience with numerous
hurricanes indicates that all outages during these types of events should be exempt. The
focus in these situations is to get the lines back in service and restore customers. There
is insufficient manpower to adequately complete the forensics necessary to determine an
accurate root cause. It is not uncommon to find vegetation debris in the lines or downed
trees on the ROW in this situation. In most cases it is not possible to determine the
original location of these trees.
Page 31 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
In the compliance section of the document a transmission owner becomes non compliant
with a single category 1 or 2 outage. This occurs regardless of the circumstances. A non
compliant penalty for a single outage in a situation where no customers were affected
and the system could not have been compromised is not reasonable. It is also not an
indicator of a poorly maintained system. We agree that several Category 1 or 2
interruptions could be an indicator of neglect but one is not. We recommend that the
compliance section be reviewed with this in mind.
Response: The SDT will review the reporting exemptions to include all category outages under major disasters in
Requirement R3.2.
The SDT and Compliance Elements DT will review and assign Violation Severity Levels when modifying FAC-003-1. Note that
the levels of non-compliance that are in the approved version of FAC-003 will be replaced with violation severity levels.
HQT
Here are some general comments on the SAR:
;
1.
In the purpose section of the SAR, item 1, we don't understand the substitution of
BPS by «electric transmission system»; it seems like there is a will to make the
Standards applicable to more than the BPS. It is our understanding that NERC Standards
are aimed at the reliability of the BPS. The term BPS should be retained and instead of
modifying the SAR to widen the applicability, the Standard itself should be modified to
specifically used the term BPS in item A.3.
2.
In the detailed description section, item 1, sub-bullet, it is written that: “...the
SDT may consider other criteria in determining applicability of the Standard to sub 200
kV lines...”. We think that in item 4.3 (Applicability) of the existing Standard, there is
already the possibility of applying the Standard to sub 200 kV lines if determined by
RRO. This could be reworded by saying: “...as determined by a methodology to define
BPS element”; such as the one used by NPCC.
3.
We noticed that most Definitions ( e.g. RC, IA, PC, RP, TP, TOP, DP, GO, GOP,
PSE, MO (not even in the Glossary), LSE) used to described the Reliability Functions in
the SAR form, are somewhat different than those used in the Glossary of Terms
approved with the Standards deposited at the FERC. For consistency, if the definition
needs to be changed, this should be done through the right process, not just casually in
the SAR Form.
4.
Also, although the title in that same section of the SAR form refers to Reliability
Functions, these are in fact the Responsible Entity that performs those functions; maybe
a correction in the SAR form would be necessary.
Page 32 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes No
Comment
Response:
1. The SAR DT used ‘Bulk Electric System’ because that is the term defined in the NERC Glossary.
2. The standard DT will review applicability parameters of this standard, taking into account the comments from
stakeholders such as NU, National Grid, Manitoba Hydro, First Energy, and others. Furthermore the standard DT will
ensure that any new terms defined for use in this standard will also be added to the Glossary of Terms.
3. The standard DT will ensure that any new terms defined for use in this standard will also be added to the Glossary of
Terms. the drafting teams were directed to use the definitions for the functional model entities in the version of the
Functional Model just approved by the BOT in February, 2007. The glossary will be updated to include the revised
definitions for the functional entities.
4. Thanks for the comment.
Hydro One Networks
We believe from a transmission system perspective, category 3 outages are no different
;
than many of the other types of outages that take place on the system, such as
hardware failures, lightning damage and station equipment outages to name a few. It is
our understanding that there is no requirement to report these “other” outages, which
makes one wonder why the tree related outages that originate off the right of way need
to be reported. We are not diminishing the importance of category 3 outages, but from
a system cascading perspective, these outages are no more important than other line or
station outages, and are fewer in number than the “other” random outages. To initiate
system cascading as occurred during August 14, 2003, a number of the random outages
would have to coincide to cause a wide spread system event, which in our opinion is a
very low probability occurrence. On the other hand, a category 1 outage can occur as a
result of any system disturbance should there be deficiencies in clearances to vegetation,
as such the importance of category 1 outages is apparent and reporting is appropriate.
We support the review concerning the need to report category 3 outages and that the
ultimate decision should be based on reporting rules that take into consideration the
broader topic of reliability, rather than just vegetation related outages.
Response: The SAR indicates that the Standard Drafting Team will review reporting criteria for Category 3 outages and will
review the reporting requirement of Category 3 outages in R.3 and R.4.
IESO
;
1.
The SAR indicates that a list of critical low voltage transmission lines will be
provided to FERC. We do not interpret Order 693 to direct NERC to provide this list.
Rather, we interpret that FERC asks for defining a criteria that would include low voltage
transmission lines that have impact on Bulk Power System reliability. We do not think
the list is required.
2.
The SAR indicates: “The standard DT may consider other criteria in determining
Page 33 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
applicability of the standard to sub 200kV lines…” Per Order 693, the criteria is quite
clearly stated to be the transmission lines of less than 200 kV that could impact Bulk
Power System reliability. We don't feel any other criteria would be necessary. Further, to
identify the candidates that meet these criteria, we believe they should be determined by
the Reliability Coordinator, similar to the PRC-023 standard, since the RC has the
primary responsibility and knowledge of interconnection reliability impact.
3.
We do not understand why the SDT considers removing Category 3 incidents? In
our view, Category 3 outages are important information for assessing the effectiveness
of vegetation program. Since the industry started reporting vegetation related outages
about 3 years ago, data collected so far indicates that of a total of 98 reported
vegetation outages, 67 of them were category 3 outages. With this high percentage,
reporting of Category 3 events should be a must since the associated trends can provide
valuable information to the TOs to aid its evaluation of the vegetation management
program.
4.
The white paper and field tests are a good idea and the SDT should be
commended for these, especially the white paper.
5. Item 2 under the FERC Order 693 Items in the Detailed Description Section indicates
the SDT will also collection outage data. While we understand that FERC has directed the
ERO to collect outage data for transmission outages of lines that cross both federal and
non-federal lands, we do not feel that it is the SDT's role to perform this task. We feel
that this task should be performed by the ERO line functions or a group separate from
the SDT such that the task does not add burden to the SDT which may slow down the
standard development process or result in the standard development being driven by
unanalyzed data and resulting in erroneous requirements.
6. With respect to reporting exemptions, our position during development of the previous
version of this standard was to limit them. We commend the SDT intention to clarify the
outage exemptions under major disasters, but to consider including all category outage
exemptions in the standard body is too prescriptive and will add to the already extended
list. It can end up with a very long list of outage exemptions, thereby reducing the
coverage of the standard substantially and defeating its purpose
Response:
1. On the basis of the responses from stakeholders to Question #2 above, the SAR DT’s assessment is that further
Page 34 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes No
Comment
specificity may be needed to aid in identifying which <200kV transmission lines should come under the purview of this
standard. The SDT shall take under consideration other applicability parameter criteria, various stakeholder proposals
including IROL violation potential.
2. See # 1 above.
3. The SAR indicates that the Standard Drafting Team will review reporting criteria for Category 3 outages and will review
the reporting requirement of Category 3 outages in R.3 and R.4.
4. The SAR DT thanks you for your comment.
5. The SDT looks to receive the results of the ERO analysis and use it in developing the standard.
6. The SDT will review the reporting exemptions to include all category outages under major disasters in Requirement
R3.2.
IRC SRC
1.
The SAR indicates that a list of critical low voltage transmission lines will be
;
provided to FERC. We do not interpret Order 693 to direct NERC to provide this list.
Rather, we interpret that FERC asks for defining a criteria that would include low voltage
transmission lines that have impact on Bulk Power System reliability. We do not think
the list is required.
2.
The SAR indicates: “The standard DT may consider other criteria in determining
applicability of the standard to sub 200kV lines…” Per Order 693, the criteria is quite
clearly stated to be the transmission lines of less than 200 kV that could impact Bulk
Power System reliability. We don't feel any other criteria would be necessary. Further, to
identify the candidates that meet this criteria, we believe they should be determined by
the Reliability Coordinator, similar to the PRC-023 standard, since the RC has the
primary responsibility and knowledge of interconnection reliability impact.
3.
We do not understand why the SDT considers removing Category 3 incidents? In
our view, Category 3 outages are important information for assessing the effectiveness
of vegetation program. Since the industry started reporting vegetation related outages
about 3 years ago, data collected so far indicates that of a total of 98 reported
vegetation outages, 67 of them were category 3 outages. With this high percentage,
reporting of Category 3 events should be a must since the associated trends can provide
valuable information to the TOs to aid its evaluation of the vegetation management
program.
4.
The white paper and field tests are a good idea and the SDT should be
commended for these, especially the white paper.
Page 35 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
5. Item 2 under the FERC Order 693 Items in the Detailed Description Section indicates
the SDT will also collect outage data. While we understand that FERC has directed the
ERO to collect outage data for transmission outages of lines that cross both federal and
non-federal lands, we do not feel that it is the SDT's role to perform this task. We feel
that this task should be performed by the ERO or a group separate from the SDT such
that the task does not add burden to the SDT which may slow down the standard
development process or result in the standard development being driven by unanalyzed
data and resulting in erroneous requirements.
6. With respect to reporting exemptions, our position during development of the
previous version of this standard was to limit them. We commend the SDT intention to
clarify the outage exemptions under major disasters, but to consider including all
category outage exemptions in the standard body is too prescriptive and will add to the
already extended list. It can end up with a very long list of outage exemptions, thereby
reducing the coverage of the standard substantively and defeating its purpose. If this list
was to be developed, they could be attached as guidelines aside of the standard.
7. The SAR DT states it will deal with "critical facilities" . The SRC suggest that the DT
not use the word "critical" and adopt another term.
There is a need to define in a single standard what the term "critical" means. Standards
FAC-014 (R5.1.1); IRO-002-1 (R6) and others use the term "critical" as in: critical loads,
critical infrastructure, critical assets. The Veg Management Team is asked to avoid
making the current situation worse.
Response:
1. On the basis of the responses from stakeholders to Question #2 above, the SAR DT’s assessment is that further
specificity may be needed to aid in identifying which <200kV transmission lines should come under the purview of this
standard. The SDT shall take under consideration other applicability parameter criteria, various stakeholder proposals
including IROL violation potential.
2. The FERC Order includes the following language which indicates that FERC would support inclusion of any circuit below
200 kV that was subject to an IROL and the SAR has been written to allow this modification..
3. The SAR indicates that the Standard Drafting Team will review reporting criteria for Category 3 outages and will review
the reporting requirement of Category 3 outages in R.3 and R.4.
4. The SDT shall consider producing a white paper to aid in clarifying the intent of the standard, however a field test is
not contemplated at this time.
5. The SAR was revised to clarify that it is the ERO that will collect data and the Standard DT will receive the results of
Page 36 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes No
Comment
the ERO analysis and use it in developing the standard.
6. The standard DT will review the reporting exemptions to include all category outages under major disasters in
Requirement R3.2.
7. The FERC Order includes the following language which indicates that FERC would support inclusion of any circuit below
200 kV that was subject to an IROL and the SAR has been written to allow this modification.
ISO-NE
1.
The SAR indicates that a list of critical low voltage transmission lines will be
;
provided to FERC. We do not interpret Order 693 to direct NERC to provide this list.
Rather, we interpret that FERC asks for defining a criteria that would include low voltage
transmission lines that have impact on Bulk Power System reliability. We do not think
the list is required.
2.
The SAR indicates: “The standard DT may consider other criteria in determining
applicability of the standard to sub 200 kV lines…” Per Order 693, the criteria is quite
clearly stated to be the transmission lines of less than 200 kV that could impact Bulk
Power System reliability. We don't feel any other criteria would be necessary. Further, to
identify the candidates that meet this criteria, we believe they should be determined by
the Reliability Coordinator, similar to the PRC-023 standard, since the RC has the
primary responsibility and knowledge of interconnection reliability impact.
3.
We do not understand why the SDT considers removing Category 3 incidents. In
our view, Category 3 outages are important information for assessing the effectiveness
of a vegetation program. Since the industry started reporting vegetation-related outages
about 3 years ago, data collected so far indicates that of a total of 98 reported
vegetation outages, 67 of them were category 3 outages. With this high percentage,
reporting of Category 3 events should be a must since the associated trends can provide
valuable information to the TOs to aid its evaluation of the vegetation management
program.
4.
The white paper and field tests are a good idea and the SDT should be
commended for these, especially the white paper.
5. Item 2 under the FERC Order 693 Items in the Detailed Description Section indicates
the SDT will also collect outage data. While we understand that FERC has directed the
ERO to collect outage data for transmission outages of lines that cross both federal and
non-federal lands, we do not feel that it is the SDT's role to perform this task. We feel
that this task should be performed by the ERO or a group separate from the SDT such
Page 37 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
that the task does not add burden to the SDT which may slow down the standard
development process or result in the standard development being driven by unanalyzed
data and resulting in erroneous requirements.
6. With respect to reporting exemptions, our position during development of the previous
version of this standard was to limit them. We commend the SDT's intention to clarify
the outage exemptions under major disasters, but to consider including all category
outage exemptions in the standard body is too prescriptive and will add to the already
extended list. It can end up with a very long list of outage exemptions, thereby reducing
the coverage of the standard substantively and defeating its purpose. If this list was to
be developed, they could be attached as guidelines aside of the standard.
7. The SAR DT states it will deal with "critical facilities.” The SRC suggest that the DT not
use the word "critical" and adopt another term.
There is a need to define in a single standard what the term critical means. Standards
FAC-014 (R5.1.1); IRO-002-1 (R6) and others use the term "critical" as in: critical loads,
critical infrastructure, critical assets. This Team is asked to avoid making the current
situation worse.
Response:
1. On the basis of the responses from stakeholders to Question #2 above, the SAR DT’s assessment is that further
specificity may be needed to aid in identifying which <200kV transmission lines should come under the purview of this
standard. The SDT shall take under consideration other applicability parameter criteria, various stakeholder proposals
including IROL violation potential.
2. The FERC Order includes the following language which indicates that FERC would support inclusion of any circuit below
200 kV that was subject to an IROL and the SAR has been written to allow this modification..
3. The Standard Drafting Team intends to review reporting criteria for Category 3 outages in the proposed technical
reference material and may review the reporting requirement of Category 3 outages in R.3 and R.4.
4. The SDT shall consider producing a white paper to aid in clarifying the intent of the standard, however a field test is
not contemplated at this time.
5. The standard DT looks to receive the results of the ERO analysis and use it in developing the standard.
6. The standard DT will review the reporting exemptions to include all category outages under major disasters in
Requirement R3.2.
7. The FERC Order includes the following language which indicates that FERC would support inclusion of any circuit below
200 kV that was subject to an IROL and the SAR has been written to allow this modification.
Page 38 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
MRO
Yes
;
No
Comment
If the Regional Reliability Organization is removed as an applicable entity, what is the
Regional Entity’s responsible? How will a general consensus be formed? How do you
get people to participate in this formation?
For good planning and application of standards, methodologies need to be consistently
applied through guidelines to the drafting teams.
Specifically, this standard should provide consistent methodology that provides guidance
to the transmission owner.
In the next revision of the standard, the MRO requests that more authority be given to
the applicable entities with respect to the latitude allowed them in removing trees to the
legal limits of their agreement.
The MRO commends FERC on empowering NERC and the SAR DT via their Order 693 to
revisit the issue of clearances for lines on both Federal and non-Federal Lands. It has
come to the attention of the MRO that Federal Forest Employees as well as BLM
employees have begun the practice of chemically treating noxious weeds and invasive
species on Federal Lands. he MRO would like to have FERC, NERC, and the Standard DT
consider meeting with Federal Land Managers to discuss, on a National Level, the issue
of herbicide application by utilities on Federal Lands. At the present time there are
inconsistencies regionally on this issue that allow application in some regions but not in
others.
Response:
1. The term RRO is no longer in use and RE (or regional entity) is now the preferred term for the former Regional
Reliability Organizations. The term RE is defined in the delegation agreements between these organizations and the
ERO.
2. Such a guideline exists and is available on the NERC website entitled “Standard Drafting Team Guidelines”.
3. See answer #2 above.
4. The removal of trees within the limits stated in agreements is outside the scope of this standard.
5. The coordination of the use of herbicides is outside the scope of this standard.
National Grid
1) National Grid supports amending FAC-003-1 to bring the Standard into compliance
;
with "latest version of the Reliability Standard Development Procedure and the ERO
Sanctions Guidelines" as discussed in the SAR Background Information.
2) We do not support amendments to the Standard to address all of the issues raised by
FERC Order 693. We believe most of the FERC's concerns can be addressed by
Page 39 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
developing a "white paper" to better explain the Standard and guide its implementation.
3) National Grid does not support changing the basic approach to defining clearance from
vegetation. The clearance 1 and clearance 2 concept adopts the two management
approaches used by most TO's today and required in some state or ISO level standards.
National Grid supports using the reference to IEEE 516 as the basis for clearance 2 for
two reasons: 1 - there is no other definitive reference for flash over distances to
vegetation and 2- decades of experience by TO's acrosss the North America suggest the
IEEE 516 distances are more than adequate. The well known tree caused outages in
1996 and 2003 occurred as a result of hard contact with vegetation not flashover at
distances close to those in IEEE 516. Furthermore, FERC accepted IEEE 516 as
appropriate for use in vegetation management in the October 2006, NOPR.
4) National Grid supports amending the definition of a right-of-way though we are not
clear on what is meant in the SAR language by "to encompass required clearing areas".
National Grid is concerned with the interpretation of the present definition that the rightof-way includes uncleared fee owned or easement land reserved for future construction.
In many jurisdictions the TO may not be allowed to remove trees from these areas. A
"white paper" could better describe the definition and prevent future compliance issues
stemming from an ambiguous definition.
Response:
1. The SAR DT thanks you for your comment.
2. The SAR indicates that the SDT will produce a technical white paper to clarify intent of the standard.
3. The SAR DT agrees with the commenter not to change the basic approach and recognizes that sections of IEEE 516
standard pertaining to minimum air insulation distances are applicable in determining minimum vegetation clearances
to prevent flashovers.
4. The Standard DT will review the definition of ROW. See also answer #2 above.
Northeast Utilities
NU does not support the proposed revisions based on the issues raised by FERC Order
;
693. The Standard has not been in effect long enough to determine if there are any
shortcomings with the current requirements. It is our position that the current clearance
requirements are satisfactory in that a base minimum distance as provided under IEEE
Section 516 is sufficient and there is the need for variations in the second level of
clearances base on Regional needs and conditions.
The revisions to the definition of "right-of-way" to encompass required clearance areas
can e problematic as this could cause significant problems with current systems. There
is no detailed description on what the new definition will include or what the actual
impact will be to TO's. If the definition will include defined limits or widths of rights-of-
Page 40 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
way this may affect current facilities that do not meet these distances. Second, there
are areas where the company owns or possesses additional area beyond the current
maintained right-of-way widths. Is it proposed that the new definition expand the limits
of clearing or maintenance to include easemented or fee-owned areas beyond the
current maintained limits? Until the new definition can be presented - it is difficult to
support any changes at this time and we can only comment on the perceived negative
impacts.
Response: The SDT will review the standard to address the Commission’s determinations. The standard DT will review the
definition of ROW. Note that the ERO is required to respond to the FERC directives.
NYISO
1.
The SAR indicates that a list of critical low voltage transmission lines will be
;
provided to FERC. We do not interpret Order 693 to direct NERC to provide this list.
Rather, we interpret that FERC asks for defining a criteria that would include low voltage
transmission lines that have impact on Bulk Power System reliability. We do not think
the list is required.
2.
The SAR indicates: “The standard DT may consider other criteria in determining
applicability of the standard to sub 200kV lines…” Per Order 693, the criteria is quite
clearly stated to be the transmission lines of less than 200 kV that could impact Bulk
Power System reliability. We don't feel any other criteria would be necessary. Further, to
identify the candidates that meet this criteria, we believe they should be determined by
the Reliability Coordinator, similar to the PRC-023 standard, since the RC has the
primary responsibility and knowledge of interconnection reliability impact.
3.
We do not understand why the SDT considers removing Category 3 incidents? In
our view, Category 3 outages are important information for assessing the effectiveness
of vegetation program. Since the industry started reporting vegetation related outages
about 3 years ago, data collected so far indicates that of a total of 98 reported
vegetation outages, 67 of them were category 3 outages. With this high percentage,
reporting of Category 3 events should be a must since the associated trends can provide
valuable information to the TOs to aid its evaluation of the vegetation management
program.
4.
The white paper and field tests are a good idea and the SDT should be
commended for these, especially the white paper.
5. Item 2 under the FERC Order 693 Items in the Detailed Description Section indicates
Page 41 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
the SDT will also collect outage data. While we understand that FERC has directed the
ERO to collect outage data for transmission outages of lines that cross both federal and
non-federal lands, we do not feel that it is the SDT's role to perform this task. We feel
that this task should be performed by the ERO or a group separate from the SDT such
that the task does not add burden to the SDT which may slow down the standard
development process or result in the standard development being driven by unanalyzed
data and resulting in erroneous requirements.
6. With respect to reporting exemptions, our position during development of the previous
version of this standard was to limit them. We commend the SDT intention to clarify the
outage exemptions under major disasters, but to consider including all category outage
exemptions in the standard body is too prescriptive and will add to the already extended
list. It can end up with a very long list of outage exemptions, thereby reducing the
coverage of the standard substantively and defeating its purpose. If this list was to be
developed, they could be attached as guidelines aside of the standard.
Response:
1. On the basis of the responses from stakeholders to Question #2 above, the SAR DT’s assessment is that further
specificity may be needed to aid in identifying which <200kV transmission lines should come under the purview of this
standard. The SDT shall take under consideration other applicability parameter criteria, various stakeholder proposals
including IROL violation potential..
2. The FERC Order includes the following language which indicates that FERC would support inclusion of any circuit below
200 kV that was subject to an IROL and the SAR has been written to allow this modification..
3. The Standard Drafting Team intends to review reporting criteria for Category 3 outages in the proposed technical
reference material and may review the reporting requirement of Category 3 outages in R.3 and R.4.
4. The SAR indicates that the SDT will produce a white paper to aid in clarifying the intent of the standard, however a
field test is not contemplated at this time.
5. The SDT looks to receive the results of the ERO analysis and use it in developing the standard.
6. The SDT will review the reporting exemptions to include all category outages under major disasters in Requirement
R3.2.
PGE
1) Applicability 4.3 of the standard - PG&E believes the RE is in the best position to
;
determine sub-200kV facilities are designated critical and covered under FAC-003-1. We
suggest the ERO direct the RE to provide a list of sub-200kV lines designated critical
along with methodology used to make that determination.
2) Clearances for lines on federal and non-federal lands - PG&E believes there should be
no distinction between requirements on different lands. Vegetation encroachments have
Page 42 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
the same impact regardless of land ownership.
3) Definition of right of way - agreed
4) Suitability of IEEE 516-2003 - PG&E believes the use of IEEE 516 as the standard for
clearance requirements are adequate to ensure transmission system reliability provided
the TO has an appropriate methodology for determining clearance at time of trim and an
adequate cycle to prevent vegetation from encroaching within minimum distances. Use
of ANSI Z133.3 or FedOSHA 1910, as suggested by FERC, is not appropriate as it is
intended for worker safety and not system reliability. TO compliance with R1.2 of the
standard should address concerns FERC has with maintaining minimum clearance.
5-7) Procedural items - No comment
8) Preparation of technical manual (white paper) - agreed
9) PG&E believes the current reporting requirements under R3 of the standard should be
revised. Distinction is placed on fall-in's "in and out of the ROW" and may not be the
best method for determining severity for reporting purposes. PG&E believes a better
distinction is (a) green/healthy/no obvious decline and (b) dead or obvious signs of
disease, decay or decline. A key component of any TMVP should be hazard tree
mitigation regardless if in or out of the ROW. Suggested categories:
Category 1 - Any grow-in (as currently stated).
Category 2 - Any fall-in of a dead tree or one with obvious signs of disease, decay or
decline in or out of the ROW.
Category 3 - Either eliminate this category or specify healthy green tree or tree with no
obvious signs of decline (if retained, be specific about this being for reporting purposes
only)
PG&E recognizes that tree failures, even if dead or diseased, are not necessarily an
indicator of problematic VM program and the severity level should be reflected as such.
Tree density along with other factors make 100% identification not possible. However,
multiple occurrences could be an indicator of substandard performance and the current
standard does remains silent in respect to hazard trees other than if in or out of the
ROW.
Response:
Page 43 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes No
Comment
1. On the basis of the responses from stakeholders to Question #2 above, the SAR DT’s assessment is that further
specificity may be needed to aid in identifying which <200kV transmission lines should come under the purview of this
standard. The SDT shall take under consideration other applicability parameter criteria, various stakeholder proposals
including IROL violation potential..
2. The SAR DT concurs with the commenter with respect to applying this standard to Federal and non-Federal lands. The
standard DT will evaluate the suitability of a case-by-case approach.
3. The standard DT will review the definition of ROW.
4. The SAR DT agrees with the commenter and recognizes that sections of IEEE 516 standard pertaining to minimum air
insulation distances are applicable in determining minimum vegetation clearances to prevent flashovers.
5. n/a
6. n/a
7. n/a
8. The SAR indicates that the SDT will produce a technical white paper to clarify intent of the standard.
9. The SAR indicates that the SDT will review reporting criteria for Category 3 outages and will review the reporting
requirement of Category 3 outages in R.3 and R.4. The SDT and Compliance Elements DT will review and assign
Violation Severity Levels when modifying FAC-003-1.
PGN
Progress Energy Carolinas (PEC) and Progress Energy Florida (PEF) do not agree that
;
each of 11 items listed in the SAR are necessary to improve reliability. The following
comments are offered for each of the 11 items identified in the SAR detail description:
1. Standard Applicability:
PEC and PEF believe that the current standard wording for determining facilities subject
to this standard should not be revised. The standard as it is written provides for lines
below 200kV, that are determined to impact the grid, to be subject to the standard.
Extending the requirements to a bright line below 200kV, such as 100kV, will dilute the
focus on those lines that impact grid reliability, lines >200kV, and shift attention to
facilities, those <200kV, that do not necessarily impact grid reliability. Customer
reliability is an issue that impacts customer satisfaction and is generally driven by state
utility commissions. While some facilities above 200kV directly support customer load,
transmission lines below 200kV primarily support customer load, and interruptions to
those facilities generally reduce load on the grid.
The majority of transmission facilities below 200 kV also have significantly different
design/construction/operating characteristics and have not been cited as impacting bulk
Page 44 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
power system reliability. For example, the Final Report on the August 14, 2003 Blackout
in the United states and Canada: Causes and Recommendations April 2004 by the U.S.Canada Power System Outage Task Force and all referenced major blackouts (pages
103-115) in that report, cited only outages which involved vegetation at line voltages
above 200kV. Generally applying requirements that are appropriate for >200kV lines to
lines less than 200kV will result in significant documentation and reporting of items such
as restrictions, mitigation plans, off right-of-way vegetation-related outage investigation/
information and other issues, all of which dilutes the focus on lines that directly impact
bulk power system reliability.
Revising the standard to use general criteria or broad language for defining "Bulk Power
System" transmission lines covered by the standard is a “one size fits all” approach. If
that approach were taken, the standard would cover a significant number of transmission
lines that have no direct impact on bulk power system reliability under standard
planning/operating conditions, resulting in a significant cost burden for electric
customers without improving “grid” reliability. PEC and PEF believe that the applicability
provision of the standard should instead focus attention of the standard only on the
transmission lines below 200kV that directly impact “Bulk Power System” reliability, as
the current version requires.
While PEC and PEF recognize some validity in the Commission’s concern, PEC and PEF
recommend that the applicability provision of this standard should be revised only if
existing system design, planning or operating reliability criteria and parameters are
considered as a basis for defining the applicability of the standard. To that end, PEC and
PEF recommend each Regional Entity (RE) determine applicability of FAC-003 to those
lines within the region that are between 100kV and 200KV, if, and only if, they are
identified as operationally significant elements of Interconnection Reliability Operating
Limits (“IROLs”). That is, any facility below 200kV that, by itself, would cause an
Interconnected Reliability Limit Violation should the facility be outaged.
2. Issue of Clearances (Federal vs Non-Federal Lands):
FAC-003-1 presently requires the transmission owner (TO) “identify and document
clearances between vegetation and any overhead, ungrounded supply conductors, taking
into consideration transmission line voltage, the effects of ambient temperature on
conductor sag under maximum design loading, and the effects of wind velocities on
Page 45 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
conductor sway.” The intent of this requirement is to ensure adequate clearances to
prevent vegetation related outages. PEC and PEF believe that only the TO has the
technical information required to determine the clearances that are necessary at the time
of VM work and that any “federal lands exemption” to clearances will result in inadequate
clearances for the existing conditions. Consistency in application of the TO’s clearance
requirements, not exceptions, is the only assurance in providing a uniform and reliable
electrical system to meet the nation’s current and future energy demands.
Any exception for a case by case clearance approach to determine vegetation
management activities/clearances on Federal lands will continue to drive inconsistency
and/or delays associated with TO vegetation management decisions being driven by
diverse vegetation management practices/beliefs and staff changes at the local level of
Federal agencies. Vegetation-related outages have occurred on Federal lands as a result
of this case by case approach, and if “Bulk Power Transmission System” lines continue to
be addressed on a “case by case” basis on National Forest Service (or any other Federal
lands), those lines will potentially be subject to a higher risk for vegetation-related
outages, resulting in reduced reliability for the “Bulk Power System”.
PEC and PEF believe that reliability of the “Bulk Power System” should have the same
focus on Federal and private lands and that the EEI MOU with federal agencies is an
appropriate avenue for TO's to identify clearances on Federal lands, not an exemption in
the language of a reliability standard.
3. Defining Right-of-Way:
PEC and PEF agree that it is appropriate to further address the definition of “right-ofway”. Corridor widths that exceed the design clearance requirements have been
acquired for a variety of reasons in the past; future use, property line buffers, etc.
Vegetation in those areas that would normally be outside of the corridor width necessary
for reliable operation of the facility, but within an expanded easement area, should not
be considered, or treated, different than vegetation that is outside of a defined
easement/permit right-of-way corridor that was designed and acquired specifically for
the reliable operation of a single line.
4. IEEE Standard for Minimum Clearances:
Page 46 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
PEC and PEF believe that the IEEE 516-2003 tables are appropriate for defining the
minimum acceptable clearances to prevent flashover between conductors and vegetation
under all rated electrical operating conditions. Closer minimum clearances such as the
minimum length of a support insulator could have been adopted as a “lowest common
denominator” clearance. However the clearance in IEEE 516-2003 was adopted to ensure
an additional margin of reliability. FERC staff has made references to the use of ANSI Z133 which is a safety standard that addresses worker safety as well as the safety of the
general public. The purpose of ANSI Z-133 is to address worker safety and is not focused
on transmission line reliability, which is the purpose of FAC-003-1. OSHA, NESC and
other related safety standards have clearances in excess of IEEE 516-2003. Those
clearances are clearly focused on safety issues and will still apply to other aspects of
design and operation of electric facilities (such as public and worker safety) but are not
appropriate to be referenced in a vegetation management reliability standard as a
flashover clearance.
5/6/7.
Procedural Items:
PEC and PEF agree that the procedural items related to formatting RRO references and
revising the compliance elements to meet the new standard format should be addressed
by the standard drafting team.
8. Technical Reference Materials:
PEC and PEF agree that a “white paper” that defines the technical basis for the standard
is appropriate. This type of document, if crafted by the drafting team, should help to
avoid the potential for differences in interpretation of the standard’s requirements by the
various regions during the audit process.
9. Category 3 Outages:
Since control off right-of-way vegetation is generally beyond control of the TO and since
"fall-in" outages are random events that do not threaten grid reliability, PEC and PEF
believe that the reporting of category 3 outages should be removed from the
requirements.
10. Requirement R4:
Page 47 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
PEC and PEF believe that requirement R4 should be deleted from the standard, since the
ERO formation provides for delegation of authority to the regional entities.
11. Reporting Exemptions:
PEC and PEF believe that the reporting requirement exemptions for natural disasters
should include all categories of outages. For example, with outages caused by high
winds, hurricanes, tornadoes, etc., it would be difficult (or practically impossible in some
cases) to determine if the vegetation came from on, or off, the "right-of-way". In
addition, the effort and time necessary to make that determination would result in
delaying outage restoration efforts.
Response:
1. On the basis of the responses from stakeholders to Question #2 above, the SAR DT’s assessment is that further
specificity may be needed to aid in identifying which <200kV transmission lines should come under the purview of this
standard. The SDT shall take under consideration other applicability parameter criteria, various stakeholder proposals
including IROL violation potential..
2. The SAR DT concurs with the commenter with respect to applying this standard to Federal and non-Federal lands. The
standard DT will evaluate the suitability of a case-by-case approach.
3. The standard DT will review the definition of ROW.
4. The SAR DT agrees with the commenter and recognizes that sections of IEEE 516 standard pertaining to minimum air
insulation distances are applicable in determining minimum vegetation clearances to prevent flashovers.
5. NERC standards must be updated to comply with new procedural requirements and must include compliance elements.
6. See #5
7. See #5
8. The SAR indicates that the SDT will produce a technical white paper to clarify intent of the standard.
9. The SAR indicates that the SDT will review reporting criteria for Category 3 outages and will review the reporting
requirement of Category 3 outages in R.3 and R.4.
10. The standard DT will consider deletion of R.4.
11. The standard DT will review the reporting exemptions to include all category outages under major disasters in
Requirement R3.2.
SERC VMS
The SERC VMS does not agree that each of 11 items listed in the SAR are necessary to
;
improve reliability. The following comments are offered for each of the 11 items
identified in the SAR detail description:
1. Standard Applicability:
Page 48 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
The SERC VMS disagrees with revising the 200 kV threshold for determining facilities
subject to this standard. Extending the requirements to lines other than those >200kV
will dilute the focus on those lines that impact grid reliability and shift attention to
facilities, those <200kV. The reliability of lower voltage lines involves local customers'
reliability and satisfaction hence that reliability should be addressed by local and state
utility commissions. The majority of the >200kV lines are solely elements of the grid
and and interruptions to those lines negatively impact grid reliability. The majority of the
<200kV lines primarily support customer load, and interruptions to those facilities
actually reduces load on the grid.
The majority of transmission facilities below 200 kV also have significantly different
design/construction/operating characteristics and have not been cited as impacting bulk
power system reliability. For example, the Final Report on the August 14, 2003 Blackout
in the United states and Canada: Causes and Recommendations April 2004 by the U.S.Canada Power System Outage Task Force and all referenced major blackouts (pages
103-115) in that report, cited only outages which involved vegetation at line voltages
above 200kV. Generally applying requirements that are appropriate for >200kV lines to
lines less than 200kV will result in significant documentation and reporting of items such
as restrictions, mitigation plans, off right-of-way vegetation-related outage investigation/
information and other issues, all of which dilutes the focus on lines that directly impact
bulk power system reliability.
Revising the standard to use general criteria or broad language for defining "Bulk Power
System" transmission lines covered by the standard is a “one size fits all” approach. If
that approach were taken, the standard would cover a significant number of transmission
lines that have no direct impact on bulk power system reliability under standard
planning/operating conditions, resulting in a significant cost burden for electric
customers without improving “grid” reliability. The SERC VMS believes that the
applicability provision of the standard should instead focus attention of the standard only
on the transmission lines below 200kV that directly impact “Bulk Power System”
reliability, as the current version requires.
In sum, while the SERC VMS recognizes some validity in the Commission’s concern, the
SERC VMS recommends that the applicability provision of this standard should be revised
only if existing system design, planning or operating reliability criteria and parameters
Page 49 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
are considered as a basis for defining the applicability of the standard. To that end, the
SERC VMS recommends each Regional Entity (RE) determine applicability of FAC-003 to
those lines within the region that are between 100kV and 200KV, if, and only if, they are
identified as operationally significant elements of Interconnection Reliability Operating
Limits (“IROLs”). That is, any facility below 200kV that by itself would cause an
Interconnected Reliability Limit Violation should the facility
be outaged.
2. Issue of Clearances (Federal vs Non-Federal Lands):
FAC-003-1 presently requires the transmission owner (TO) “identify and document
clearances between vegetation and any overhead, ungrounded supply conductors, taking
into consideration transmission line voltage, the effects of ambient temperature on
conductor sag under maximum design loading, and the effects of wind velocities on
conductor sway.” The intent of this requirement is to ensure adequate clearances to
prevent vegetation related outages. The SERC VMS believes that only the TO has the
technical information required to determine the clearances that are necessary at the time
of VM work and that any “federal lands exemption” to clearances will result in inadequate
clearances for the existing conditions. Consistency in application of the TO’s clearance
requirements, not exceptions, is the only assurance in providing a uniform and reliable
electrical system to meet the nation’s current and future energy demands.
Any exception for a case by case clearance approach to determine vegetation
management activities/clearances on Federal lands will continue to drive inconsistency
and/or delays associated with TO vegetation management decisions being driven by
diverse vegetation management practices/beliefs and staff changes at the local level of
Federal agencies. Vegetation-related outages have occurred on Federal lands as a result
of this case by case approach, and if “Bulk Power Transmission System” lines continue to
be addressed on a “case by case” basis on National Forest Service (or any other Federal
lands), those lines will potentially be subject to a higher risk for vegetation-related
outages, resulting in reduced reliability for the “Bulk Power System”.
The SERC VMS believes that reliability of the “Bulk Power System” should have the same
focus on Federal and private lands and that the EEI MOU with federal agencies is the
appropriate vehicle for TO's to identify clearance variances on Ferderal lands, not
exemption language in the standard.
Page 50 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
3. Defining Right-of-Way:
The SERC VMS agrees that it is appropriate to further address the definition of “right-ofway”. Corridor widths beyond design clearance requirements have been acquired for a
variety of reasons in the past; future use, property line buffers, etc. Vegetation in those
areas that would normally fall outside of the area necessary for operation of the facility
should not be considered or treated different than vegetation that is outside of a defined
easement/permit area that is designed for the reliable operation of an existing single line
corridor.
4. IEEE Standard for Minimum Clearances:
The SERC VMS disagrees with objections to the use of the IEEE 516-2003 clearance as
the minimum acceptable distances for “Clearance 2”. The IEEE 516-2003 tables are
appropriate for defining the minimum acceptable clearances to prevent flashover
between conductors and vegetation under all rated electrical operating conditions.
Closer minimum clearances such as the minimum length of a support insulator could
have been adopted as a “lowest common denominator” clearance. However the
clearance in IEEE 516-2003 was adopted to ensure an additional margin of reliability.
FERC staff references ANSI Z-133 which is a safety standard that addresses worker
safety as well as the safety of the general public. As such, the purpose of ANSI Z-133 is
to address worker safety and is not focused on transmission line reliability, which is the
purpose of FAC-003-1. OSHA, NESC and other related safety standards have clearances
in excess of IEEE 516-2003. Those clearances are clearly focused on safety issues and
will still apply to other aspects of design and operation of electric facilities (such as public
and worker safety) but are not appropriate to be referenced in a vegetation management
reliability standard.
5/6/7.
Procedural Items:
The SERC VMS agrees that the procedural items related to formatting RRO references
and additional compliance elements should be addressed by the standard drafting team.
8. Technical Reference Materials:
The SERC VMS agrees that a “white paper” that defines the technical basis for the
Page 51 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes
No
Comment
standard is appropriate to avoid the potential for differences in interpretation of the
standard’s requirements during the various region's audit processes.
9. Category 3 Outages:
Since the right to control off right-of-way vegetation is generally beyond control of the
TO, the SERC VMS believes that the reporting of category 3 outages should be removed
from the requirements.
10. Requirement R4:
The SERC VMS believes that requirement R4 should be deleted from the standard, based
on the ERO formation and the process for delegation of authority to the regional entities.
11. Reporting Exemptions:
The SERC VMS believes that the reporting requirement exemptions for natural disasters
should include all categories of outages. It would, for example, be difficult, without
delaying restoration efforts, to determine if the vegetation from high winds, hurricanes,
tornadoes, etc. is from on or off the "right-of-way".
Response:
1. On the basis of the responses from stakeholders to Question #2 above, the SAR DT’s assessment is that further
specificity may be needed to aid in identifying which <200kV transmission lines should come under the purview of this
standard. The SDT shall take under consideration other applicability parameter criteria, various stakeholder proposals
including IROL violation potential..
2. The SAR DT concurs with the commenter with respect to applying this standard to Federal and non-Federal lands. The
standard DT will evaluate the suitability of a case-by-case approach.
3. The standard DT will review the definition of ROW.
4. The SAR DT agrees with the commenter and recognizes that sections of IEEE 516 standard pertaining to minimum air
insulation distances are applicable in determining minimum vegetation clearances to prevent flashovers.
5. NERC standards must be updated to comply with new procedural requirements and must include compliance elements.
6. See #5
7. See #5
8. The SAR indicates that the SDT will produce a technical white paper to clarify intent of the standard.
9. The SAR indicates that the SDT will review reporting criteria for Category 3 outages and will review the reporting
requirement of Category 3 outages in R.3 and R.4.
Page 52 of 53
June 22, 2007
Consideration of Comments for 2nd Draft of SAR for Vegetation Management Standard
Question #4
Commenter
Yes No
Comment
10. The standard DT will consider deletion of R.4.
11. The standard DT will review the reporting exemptions to include all category outages under major disasters in
Requirement R3.2.
TVA
We feel that the reporting of Category 3 outages should be eliminated.
;
We agree with the need for a "white paper" to expand on definitions and intent. We feel
that a defined maintainable width of right of way is more appropriate than the actual
easement widths because easement widhts are not purchased or operated exclusively
with or for vegetation manitenance activies. We will be pleased to share greater details
on this concern if requested.
Response: The SAR DT thanks you for your comments.
VELCO
;
Page 53 of 53
June 22, 2007
Standards Authorization Request Form
Standard Authorization Request Form
Revisions to FAC-003-1 Transmission Vegetation Management Program Project 2007-07
Request Date
January 9, 2007
Revised Date
April 2, 2007
SAR Type (Check a box for each one
that applies.)
SAR Requestor Information
Name Richard Dearman
New Standard
Primary Contact
Revision to existing Standard
Telephone
Richard Dearman
(256) 851-3523
Withdrawal of existing Standard
[email protected]
Urgent Action
Fax
E-mail
Purpose/Industry Need (Describe the purpose of the standard — what the standard will
achieve in support of reliability.)
The purpose of revising this standard is to:
1. Provide an adequate level of reliability for the North American electric transmission
system – by verifying that the standard is complete and that its requirements are set at
an appropriate level to ensure reliability.
2. Incorporate other general improvements described in the attached Standard Review
Guidelines to bring it into conformance with the latest version of the Reliability Standard
Development Procedure and the ERO Sanctions Guidelines.
3. Consider comments received from ERO regulatory authorities and stakeholders, as noted
in the attached review sheets.
4. Satisfy the standards procedure requirement for five-year review of the standards.
SAR- 1
Standards Authorization Request Form
Detailed Description
This is a new standard that was approved in 2006. It has some ‘fill-in-the-blank’ components to eliminate.
In addition, the following comments submitted by FERC and stakeholders need to be addressed in the
refinement of the standard:
FERC Order 693 items
1. To address the issue regarding applicability:
The Standard DT shall work with the reliability entities and the ERO to collect and make
available to the FERC, a list of critical lower voltage transmission lines. (Refer to
Applicability 4.3 section of the standard.)
o The standard DT may consider other criteria in determining applicability of the
standard to sub 200kV lines.
2. To address the issue of clearances for lines on both federal and non-federal lands:
o The standard drafting team shall collect and analyze outage data then consider
defining clearances needed to avoid sustained vegetation-related outages that
would apply to transmission lines crossing both federal and non-federal land.
3. To consider revising the definition of right of way to encompass required clearance areas.
4. To review the suitability of IEEE 516-2003 standard for minimum vegetation clearance.
Procedural items
5. Re-format standard to bring it into conformance with the latest version of the Reliability
Standard Development Procedure and the ERO Sanctions Guidelines.
6. Remove references to RRO in the standard and substitute a responsible entity.
7. Add compliance elements such as time horizons, and violation severity levels.
Stakeholder items
8. The Standard DT shall prepare technical reference material such as a “white paper” to aid in
understanding the technical basis for the standard.
9. The Standard DT shall review reporting criteria for Category 3 outages in the proposed
technical reference material and may remove the reporting requirement of Category 3
outages in R.3 and R.4.
10. The Standard DT shall consider deleting requirement R.4.
11. The Standard DT will review the reporting exemptions to include all category outages under
major disasters in Requirement R3.2.
SAR- 2
Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports interconnection frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced Interchange Schedules between Balancing Authority
Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator
Area..
Resource Planner
Develops a (>one year) plan for the resource adequacy of specific
loads within a Planning Coordinator Area.
Transmission
Planner
Develops a (>one year) plan for the reliability of the
interconnected Bulk Electric System within its portion of the
Planning Coordinator Area.
Transmission
Service Provider
Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).
Transmission Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator Owner
Owns and maintains generation facilities.
Generator Operator
Operates generation unit(s) to provide real and reactive power.
Purchasing-Selling
Entity
Purchases or sells energy, capacity, and all necessary reliabilityrelated services as required.
Market Operator
Interface point for reliability functions with commercial functions.
Load-Serving Entity
Secures energy and transmission (and related reliability-related
services) to serve the End-use Customer.
SAR- 3
Standards Authorization Request Form
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk electric systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk electric systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk electric
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk electric
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk electric systems.
6. Personnel responsible for planning and operating interconnected bulk electric
systems shall be trained, qualified, and have the responsibility and authority to
implement actions.
7. The security of the interconnected bulk electric systems shall be assessed,
monitored and maintained on a wide area basis.
Does the proposed Standard comply with all the following Market Interface
Principles? (Select “yes” or “no” from the drop-down box.)
1. The planning and operation of bulk electric systems shall recognize that reliability is an
essential requirement of a robust North American economy. Yes
2. An Organization Standard shall not give any market participant an unfair competitive
advantage.Yes
3. An Organization Standard shall neither mandate nor prohibit any specific market structure.
Yes
4. An Organization Standard shall not preclude market solutions to achieving compliance with
that Standard. Yes
5. An Organization Standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes
SAR- 4
Standards Authorization Request Form
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Explanation
Regional Differences
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
SAR- 5
Standard Review Guidelines
Standard Review Guidelines
Applicability
Does this reliability standard clearly identify the functional classes of entities responsible for
complying with the reliability standard, with any specific additions or exceptions noted? Where
multiple functional classes are identified is there a clear line of responsibility for each
requirement identifying the functional class and entity to be held accountable for compliance?
Does the requirement allow overlapping responsibilities between Registered Entities possibly
creating confusion for who is ultimately accountable for compliance?
Does this reliability standard identify the geographic applicability of the standard, such as the
entire North American bulk power system, an interconnection, or within a regional entity area?
If no geographic limitations are identified, the default is that the standard applies throughout
North America.
Does this reliability standard identify any limitations on the applicability of the standard based
on electric facility characteristics, such as generators with a nameplate rating of 20 MW or
greater, or transmission facilities energized at 200 kV or greater or some other criteria? If no
functional entity limitations are identified, the default is that the standard applies to all identified
functional entities.
Purpose
Does this reliability standard have a clear statement of purpose that describes how the standard
contributes to the reliability of the bulk power system? Each purpose statement should include a
value statement.
Performance Requirements
Does this reliability standard state one or more performance requirements, which if achieved by
the applicable entities, will provide for a reliable bulk power system, consistent with good utility
practices and the public interest?
Does each requirement identify who shall do what under what conditions and to what outcome?
Measurability
Is each performance requirement stated so as to be objectively measurable by a third party with
knowledge or expertise in the area addressed by that requirement?
Does each performance requirement have one or more associated measures used to objectively
evaluate compliance with the requirement?
If performance results can be practically measured quantitatively, are metrics provided within the
requirement to indicate satisfactory performance?
Technical Basis in Engineering and Operations
Is this reliability standard based upon sound engineering and operating judgment, analysis, or
experience, as determined by expert practitioners in that particular field?
Page 1 of 4
April 2, 2006
Standard Review Guidelines
Completeness
Is this reliability standard complete and self-contained? Does the standard depend on external
information to determine the required level of performance?
Consequences for Noncompliance
In combination with guidelines for penalties and sanctions, as well as other ERO and regional
entity compliance documents, are the consequences of violating a standard clearly known to the
responsible entities?
Clear Language
Is the reliability standard stated using clear and unambiguous language? Can responsible
entities, using reasonable judgment and in keeping with good utility practices, arrive at a
consistent interpretation of the required performance?
Practicality
Does this reliability standard establish requirements that can be practically implemented by the
assigned responsible entities within the specified effective date and thereafter?
Capability Requirements versus Performance Requirements
In general, requirements for entities to have ‘capabilities’ (this would include facilities for
communication, agreements with other entities, etc.) should be located in the standards for
certification. The certification requirements should indicate that entities have a responsibility to
‘maintain’ their capabilities.
Consistent Terminology
To the extent possible, does this reliability standard use a set of standard terms and definitions
that are approved through the NERC reliability standards development process?
If the standard uses terms that are included in the NERC Glossary of Terms Used in Reliability
Standards, then the term must be capitalized when it is used in the standard. New terms should
not be added unless they have a ‘unique’ definition when used in a NERC reliability standard.
Common terms that could be found in a college dictionary should not be defined and added to
the NERC Glossary.
Are the verbs on the ‘verb list’ from the DT Guidelines? If not – do new verbs need to be added
to the guidelines or could you use one of the verbs from the verb list?
Violation Risk Factors (Risk Factor)
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures;
or a requirement in a planning time frame that, if violated, could, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of
Page 2 of 4
April 2, 2006
Standard Review Guidelines
failures, or could place the bulk electric system at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of
the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of a medium risk requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures;
or a requirement in a planning time frame that, if violated, could, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly and adversely
affect the electrical state or capability of the bulk electric system, or the ability to
effectively monitor, control, or restore the bulk electric system. However, violation of a
medium risk requirement is unlikely, under emergency, abnormal, or restoration
conditions anticipated by the preparations, to lead to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the bulk electric system, or the ability to effectively monitor and
control the bulk electric system. A requirement that is administrative in nature;
or a requirement in a planning time frame that, if violated, would not, under the
emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system,
or the ability to effectively monitor, control, or restore the bulk electric system. A
planning requirement that is administrative in nature.
Time Horizon
The drafting team should also indicate the time horizon available for mitigating a violation to the
requirement using the following definitions:
•
Long-term Planning — a planning horizon of one year or longer.
•
Operations Planning — operating and resource plans from day-ahead up to and including
seasonal.
•
Same-day Operations — routine actions required within the timeframe of a day, but not
real-time.
•
Real-time Operations — actions required within one hour or less to preserve the
reliability of the bulk electric system.
•
Operations Assessment — follow-up evaluations and reporting of real time operations.
Violation Severity Levels
The drafting team should indicate a set of violation severity levels that can be applied for the
requirements within a standard. (‘Violation severity levels’ replace existing ‘levels of noncompliance.’) The violation severity levels may be applied for each requirement or combined to
cover multiple requirements, as long as it is clear which requirements are included.
Page 3 of 4
April 2, 2006
Standard Review Guidelines
The violation severity levels should be based on the following definitions:
•
Lower: mostly compliant with minor exceptions — The responsible entity is mostly
compliant with and meets the intent of the requirement but is deficient with respect to one
or more minor details. Equivalent score: 95% to 99% compliant.
•
Moderate: mostly compliant with significant exceptions — The responsible entity is
mostly compliant with and meets the intent of the requirement but is deficient with
respect to one or more significant elements. Equivalent score: 85% to 94% compliant.
•
High: marginal performance or results — The responsible entity has only partially
achieved the reliability objective of the requirement and is missing one or more
significant elements. Equivalent score: 70% to 84% compliant.
•
Severe: poor performance or results — The responsible entity has failed to meet the
reliability objective of the requirement. Equivalent score: less than 70% compliant.
Compliance Monitor
Replace, ‘Regional Reliability Organization’ with ‘Regional Entity’.
Fill-in-the-blank Requirements
Do not include any ‘fill-in-the-blank’ requirements. These are requirements that assign one
entity responsibility for developing some performance measures without requiring that the
performance measures be included in the body of a standard – then require another entity to
comply with those requirements.
Every reliability objective can be met, at least at a threshold level, by a North American
standard. If we need regions to develop regional standards, such as in under-frequency load
shedding, we can always write a uniform North American standard for the applicable functional
entities as a means of encouraging development of the regional standards.
Requirements for Regional Reliability Organization
Do not write any requirements for the Regional Reliability Organization. Any requirements
currently assigned to the RRO should be re-assigned to the applicable functional entity.
Effective Dates
Must be 1st day of 1st quarter after entities are expected to be compliant – must include time to
file with regulatory authorities and provide notice to responsible entities of the obligation to
comply. If the standard is to be actively monitored, time for the Compliance Monitoring and
Enforcement Program to develop reporting instructions and modify the Compliance Data
Management System(s) both at NERC and Regional Entities must be provided in the
implementation plan.
Associated Documents
If there are standards that are referenced within a standard, list the full name and number of the
standard under the section called, ‘Associated Documents’.
Page 4 of 4
April 2, 2006
Standard Review Guidelines
Functional Model Version 3
Review the requirements against the latest descriptions of the responsibilities and tasks assigned
to functional entities as provided in pages 13 through 53 of the draft Functional Model Version
3.
Page 5 of 4
April 2, 2006
Standard Authorization Request Form
Revisions to FAC-003-1 Transmission Vegetation Management Program Project 2007-07
Request Date
January 9, 2007
Revised Date
April 2, 2007
Revised Date
June 22, 2007
SAR Requestor Information
SAR Type (Check a box for each one
that applies.)
Name Richard Dearman
New Standard
Primary Contact
Revision to existing Standard
Telephone
Richard Dearman
(256) 851-3523
Withdrawal of existing Standard
[email protected]
Urgent Action
Fax
E-mail
Purpose/Industry Need (Describe the purpose of the standard — what the standard will
achieve in support of reliability.)
The purpose of revising this standard is to:
1. Provide an adequate level of reliability for the North American electric transmission
system – by verifying that the standard is complete and that its requirements are set at
an appropriate level to ensure reliability.
2. Incorporate other general improvements described in the attached Standard Review
Guidelines to bring it into conformance with the latest version of the Reliability Standard
Development Procedure and the ERO Sanctions Guidelines.
3. Consider comments received from ERO regulatory authorities and stakeholders, as noted
in the attached review sheets.
4. Satisfy the standards procedure requirement for five-year review of the standards.
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
Standards Authorization Request Form
Detailed Description
This is a new standard that was approved in 2006. It has some ‘fill-in-the-blank’ components to eliminate.
In addition, the following comments submitted by FERC and stakeholders need to be addressed in the
refinement of the standard:
FERC Order 693 items
1. To address the issue regarding applicability:
The Standard DT shall work with the reliability entities and the ERO to collect and make
available to the FERC, a list of critical lower voltage transmission lines. (Refer to
Applicability 4.3 section of the standard.)
o The standard DT may consider other criteria in determining applicability of the
standard to sub 200kV lines.
2. To address the issue of clearances for lines on both federal and non-federal lands:
o The standard drafting team shall review and analyze outage data (collected by
the ERO) then consider defining clearances needed to avoid sustained
vegetation-related outages that would apply to transmission lines crossing both
federal and non-federal land.
3. To consider revising the definition of right of way to encompass required clearance areas.
4. To review the suitability of IEEE 516-2003 standard for minimum vegetation clearance.
Procedural items
5. Re-format standard to bring it into conformance with the latest version of the Reliability
Standard Development Procedure and the ERO Sanctions Guidelines.
6. Remove references to RRO in the standard and substitute a responsible entity.
7. Add newly developed compliance elements such as time horizons, violation risk factors,
violation severity levels, etc.
Stakeholder items
8. The Standard DT shall prepare technical reference material such as a “white paper” to aid in
understanding the technical basis for the standard.
9. The Standard DT shall review reporting criteria for Category 3 outages in the proposed
technical reference material and may remove the reporting requirement of Category 3
outages in R.3 and R.4.
10. The Standard DT shall consider deleting requirement R.4.
11. The Standard DT will review the reporting exemptions to include all category outages under
major disasters in Requirement R3.2.
SAR- 2
Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports interconnection frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced Interchange Schedules between Balancing Authority
Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator
Area..
Resource Planner
Develops a (>one year) plan for the resource adequacy of specific
loads within a Planning Coordinator Area.
Transmission
Planner
Develops a (>one year) plan for the reliability of the
interconnected Bulk Electric System within its portion of the
Planning Coordinator Area.
Transmission
Service Provider
Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).
Transmission Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator Owner
Owns and maintains generation facilities.
Generator Operator
Operates generation unit(s) to provide real and reactive power.
Purchasing-Selling
Entity
Purchases or sells energy, capacity, and all necessary reliabilityrelated services as required.
Market Operator
Interface point for reliability functions with commercial functions.
Load-Serving Entity
Secures energy and transmission (and related reliability-related
services) to serve the End-use Customer.
SAR- 3
Standards Authorization Request Form
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk electric systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk electric systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk electric
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk electric
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk electric systems.
6. Personnel responsible for planning and operating interconnected bulk electric
systems shall be trained, qualified, and have the responsibility and authority to
implement actions.
7. The security of the interconnected bulk electric systems shall be assessed,
monitored and maintained on a wide area basis.
Does the proposed Standard comply with all the following Market Interface
Principles? (Select “yes” or “no” from the drop-down box.)
1. The planning and operation of bulk electric systems shall recognize that reliability is an
essential requirement of a robust North American economy. Yes
2. An Organization Standard shall not give any market participant an unfair competitive
advantage.Yes
3. An Organization Standard shall neither mandate nor prohibit any specific market structure.
Yes
4. An Organization Standard shall not preclude market solutions to achieving compliance with
that Standard. Yes
5. An Organization Standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes
SAR- 4
Standards Authorization Request Form
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Explanation
Regional Differences
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
SAR- 5
Standard Review Guidelines
Standard Review Guidelines
Applicability
Does this reliability standard clearly identify the functional classes of entities responsible for
complying with the reliability standard, with any specific additions or exceptions noted? Where
multiple functional classes are identified is there a clear line of responsibility for each
requirement identifying the functional class and entity to be held accountable for compliance?
Does the requirement allow overlapping responsibilities between Registered Entities possibly
creating confusion for who is ultimately accountable for compliance?
Does this reliability standard identify the geographic applicability of the standard, such as the
entire North American bulk power system, an interconnection, or within a regional entity area?
If no geographic limitations are identified, the default is that the standard applies throughout
North America.
Does this reliability standard identify any limitations on the applicability of the standard based
on electric facility characteristics, such as generators with a nameplate rating of 20 MW or
greater, or transmission facilities energized at 200 kV or greater or some other criteria? If no
functional entity limitations are identified, the default is that the standard applies to all identified
functional entities.
Purpose
Does this reliability standard have a clear statement of purpose that describes how the standard
contributes to the reliability of the bulk power system? Each purpose statement should include a
value statement.
Performance Requirements
Does this reliability standard state one or more performance requirements, which if achieved by
the applicable entities, will provide for a reliable bulk power system, consistent with good utility
practices and the public interest?
Does each requirement identify who shall do what under what conditions and to what outcome?
Measurability
Is each performance requirement stated so as to be objectively measurable by a third party with
knowledge or expertise in the area addressed by that requirement?
Does each performance requirement have one or more associated measures used to objectively
evaluate compliance with the requirement?
If performance results can be practically measured quantitatively, are metrics provided within the
requirement to indicate satisfactory performance?
Technical Basis in Engineering and Operations
Is this reliability standard based upon sound engineering and operating judgment, analysis, or
experience, as determined by expert practitioners in that particular field?
Page 1 of 4
April 2, 2006
Standard Review Guidelines
Completeness
Is this reliability standard complete and self-contained? Does the standard depend on external
information to determine the required level of performance?
Consequences for Noncompliance
In combination with guidelines for penalties and sanctions, as well as other ERO and regional
entity compliance documents, are the consequences of violating a standard clearly known to the
responsible entities?
Clear Language
Is the reliability standard stated using clear and unambiguous language? Can responsible
entities, using reasonable judgment and in keeping with good utility practices, arrive at a
consistent interpretation of the required performance?
Practicality
Does this reliability standard establish requirements that can be practically implemented by the
assigned responsible entities within the specified effective date and thereafter?
Capability Requirements versus Performance Requirements
In general, requirements for entities to have ‘capabilities’ (this would include facilities for
communication, agreements with other entities, etc.) should be located in the standards for
certification. The certification requirements should indicate that entities have a responsibility to
‘maintain’ their capabilities.
Consistent Terminology
To the extent possible, does this reliability standard use a set of standard terms and definitions
that are approved through the NERC reliability standards development process?
If the standard uses terms that are included in the NERC Glossary of Terms Used in Reliability
Standards, then the term must be capitalized when it is used in the standard. New terms should
not be added unless they have a ‘unique’ definition when used in a NERC reliability standard.
Common terms that could be found in a college dictionary should not be defined and added to
the NERC Glossary.
Are the verbs on the ‘verb list’ from the DT Guidelines? If not – do new verbs need to be added
to the guidelines or could you use one of the verbs from the verb list?
Violation Risk Factors (Risk Factor)
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures;
Page 2 of 4
April 2, 2006
Standard Review Guidelines
or a requirement in a planning time frame that, if violated, could, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of
failures, or could place the bulk electric system at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of
the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of a medium risk requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures;
or a requirement in a planning time frame that, if violated, could, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly and adversely
affect the electrical state or capability of the bulk electric system, or the ability to
effectively monitor, control, or restore the bulk electric system. However, violation of a
medium risk requirement is unlikely, under emergency, abnormal, or restoration
conditions anticipated by the preparations, to lead to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the bulk electric system, or the ability to effectively monitor and
control the bulk electric system. A requirement that is administrative in nature;
or a requirement in a planning time frame that, if violated, would not, under the
emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system,
or the ability to effectively monitor, control, or restore the bulk electric system. A
planning requirement that is administrative in nature.
Time Horizon
The drafting team should also indicate the time horizon available for mitigating a violation to the
requirement using the following definitions:
•
Long-term Planning — a planning horizon of one year or longer.
•
Operations Planning — operating and resource plans from day-ahead up to and
including seasonal.
•
Same-day Operations — routine actions required within the timeframe of a day, but not
real-time.
•
Real-time Operations — actions required within one hour or less to preserve the
reliability of the bulk electric system.
•
Operations Assessment — follow-up evaluations and reporting of real time operations.
Violation Severity Levels
Page 3 of 4
April 2, 2006
Standard Review Guidelines
The drafting team should indicate a set of violation severity levels that can be applied for the
requirements within a standard. (‘Violation severity levels’ replace existing ‘levels of noncompliance.’) The violation severity levels may be applied for each requirement or combined to
cover multiple requirements, as long as it is clear which requirements are included.
The violation severity levels should be based on the following definitions:
•
Lower: mostly compliant with minor exceptions — The responsible entity is mostly
compliant with and meets the intent of the requirement but is deficient with respect to one
or more minor details. Equivalent score: 95% to 99% compliant.
•
Moderate: mostly compliant with significant exceptions — The responsible entity is
mostly compliant with and meets the intent of the requirement but is deficient with
respect to one or more significant elements. Equivalent score: 85% to 94% compliant.
•
High: marginal performance or results — The responsible entity has only partially
achieved the reliability objective of the requirement and is missing one or more
significant elements. Equivalent score: 70% to 84% compliant.
•
Severe: poor performance or results — The responsible entity has failed to meet the
reliability objective of the requirement. Equivalent score: less than 70% compliant.
Compliance Monitor
Replace, ‘Regional Reliability Organization’ with ‘Regional Entity’.
Fill-in-the-blank Requirements
Do not include any ‘fill-in-the-blank’ requirements. These are requirements that assign one
entity responsibility for developing some performance measures without requiring that the
performance measures be included in the body of a standard – then require another entity to
comply with those requirements.
Every reliability objective can be met, at least at a threshold level, by a North American
standard. If we need regions to develop regional standards, such as in under-frequency load
shedding, we can always write a uniform North American standard for the applicable functional
entities as a means of encouraging development of the regional standards.
Requirements for Regional Reliability Organization
Do not write any requirements for the Regional Reliability Organization. Any requirements
currently assigned to the RRO should be re-assigned to the applicable functional entity.
Effective Dates
Must be 1st day of 1st quarter after entities are expected to be compliant – must include time to
file with regulatory authorities and provide notice to responsible entities of the obligation to
comply. If the standard is to be actively monitored, time for the Compliance Monitoring and
Enforcement Program to develop reporting instructions and modify the Compliance Data
Management System(s) both at NERC and Regional Entities must be provided in the
implementation plan.
Page 4 of 4
April 2, 2006
Standard Review Guidelines
Associated Documents
If there are standards that are referenced within a standard, list the full name and number of the
standard under the section called, ‘Associated Documents’.
Functional Model Version 3
Review the requirements against the latest descriptions of the responsibilities and tasks assigned
to functional entities as provided in pages 13 through 53 of the draft Functional Model Version
3.
Page 5 of 4
April 2, 2006
Standard Authorization Request Form
Revisions to FAC-003-1 Transmission Vegetation Management Program Project 2007-07
Request Date
January 9, 2007
Revised Date
April 2, 2007
Revised Date
June 22, 2007
SAR Requestor Information
SAR Type (Check a box for each one
that applies.)
Name Richard Dearman
New Standard
Primary Contact
Revision to existing Standard
Telephone
Richard Dearman
(256) 851-3523
Withdrawal of existing Standard
[email protected]
Urgent Action
Fax
E-mail
Purpose/Industry Need (Describe the purpose of the standard — what the standard will
achieve in support of reliability.)
The purpose of revising this standard is to:
1. Provide an adequate level of reliability for the North American electric transmission system – by
verifying that the standard is complete and that its requirements are set at an appropriate level to
ensure reliability.
2. Incorporate other general improvements described in the attached Standard Review Guidelines to
bring it into conformance with the latest version of the Reliability Standard Development Procedure
and the ERO Sanctions Guidelines.
3. Consider comments received from ERO regulatory authorities and stakeholders, as noted in the
attached review sheets.
4. Satisfy the standards procedure requirement for five-year review of the standards.
SAR-1116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
Standards Authorization Request Form
Detailed Description
This is a new standard that was approved in 2006. It has some ‘fill-in-the-blank’ components to eliminate.
In addition, the following comments submitted by FERC and stakeholders need to be addressed in the
refinement of the standard:
FERC Order 693 items
1. To address the issue regarding applicability:
The Standard DT shall work with the reliability entities and the ERO to collect and make
available to the FERC, a list of critical lower voltage transmission lines. (Refer to
Applicability 4.3 section of the standard.)
o The standard DT may consider other criteria in determining applicability of the
standard to sub 200kV lines.
2. To address the issue of clearances for lines on both federal and non-federal lands:
o The standard drafting team shall collect review and analyze outage data
(collected by the ERO) then consider defining clearances needed to avoid
sustained vegetation-related outages that would apply to transmission lines
crossing both federal and non-federal land.
3. To consider revising the definition of right of way to encompass required clearance areas.
4. To review the suitability of IEEE 516-2003 standard for minimum vegetation clearance.
Procedural items
5. Re-format standard to bring it into conformance with the latest version of the Reliability
Standard Development Procedure and the ERO Sanctions Guidelines.
6. Remove references to RRO in the standard and substitute a responsible entity.
7. Add newly developed compliance elements such as time horizons, violation risk factors,
violation severity levels, etc.
Stakeholder items
8. The Standard DT shall prepare technical reference material such as a “white paper” to aid in
understanding the technical basis for the standard.
9. The Standard DT shall review reporting criteria for Category 3 outages in the proposed
technical reference material and may remove the reporting requirement of Category 3
outages in R.3 and R.4.
10. The Standard DT shall consider deleting requirement R.4.
11. The Standard DT will review the reporting exemptions to include all category outages under
major disasters in Requirement R3.2.
SAR- 2
Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports interconnection frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced Interchange Schedules between Balancing Authority
Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator
Area..
Resource Planner
Develops a (>one year) plan for the resource adequacy of specific
loads within a Planning Coordinator Area.
Transmission
Planner
Develops a (>one year) plan for the reliability of the
interconnected Bulk Electric System within its portion of the
Planning Coordinator Area.
Transmission
Service Provider
Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).
Transmission Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator Owner
Owns and maintains generation facilities.
Generator Operator
Operates generation unit(s) to provide real and reactive power.
Purchasing-Selling
Entity
Purchases or sells energy, capacity, and all necessary reliabilityrelated services as required.
Market Operator
Interface point for reliability functions with commercial functions.
Load-Serving Entity
Secures energy and transmission (and related reliability-related
services) to serve the End-use Customer.
SAR- 3
Standards Authorization Request Form
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk electric systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk electric systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk electric
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk electric
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk electric systems.
6. Personnel responsible for planning and operating interconnected bulk electric
systems shall be trained, qualified, and have the responsibility and authority to
implement actions.
7. The security of the interconnected bulk electric systems shall be assessed,
monitored and maintained on a wide area basis.
Does the proposed Standard comply with all the following Market Interface
Principles? (Select “yes” or “no” from the drop-down box.)
1. The planning and operation of bulk electric systems shall recognize that reliability is an
essential requirement of a robust North American economy. Yes
2. An Organization Standard shall not give any market participant an unfair competitive
advantage.Yes
3. An Organization Standard shall neither mandate nor prohibit any specific market structure.
Yes
4. An Organization Standard shall not preclude market solutions to achieving compliance with
that Standard. Yes
5. An Organization Standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes
SAR- 4
Standards Authorization Request Form
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Explanation
Regional Differences
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
SAR- 5
Standard Review Guidelines
Standard Review Guidelines
Applicability
Does this reliability standard clearly identify the functional classes of entities responsible for complying
with the reliability standard, with any specific additions or exceptions noted? Where multiple functional
classes are identified is there a clear line of responsibility for each requirement identifying the functional
class and entity to be held accountable for compliance? Does the requirement allow overlapping
responsibilities between Registered Entities possibly creating confusion for who is ultimately accountable
for compliance?
Does this reliability standard identify the geographic applicability of the standard, such as the entire North
American bulk power system, an interconnection, or within a regional entity area? If no geographic
limitations are identified, the default is that the standard applies throughout North America.
Does this reliability standard identify any limitations on the applicability of the standard based on electric
facility characteristics, such as generators with a nameplate rating of 20 MW or greater, or transmission
facilities energized at 200 kV or greater or some other criteria? If no functional entity limitations are
identified, the default is that the standard applies to all identified functional entities.
Purpose
Does this reliability standard have a clear statement of purpose that describes how the standard
contributes to the reliability of the bulk power system? Each purpose statement should include a value
statement.
Performance Requirements
Does this reliability standard state one or more performance requirements, which if achieved by the
applicable entities, will provide for a reliable bulk power system, consistent with good utility practices
and the public interest?
Does each requirement identify who shall do what under what conditions and to what outcome?
Measurability
Is each performance requirement stated so as to be objectively measurable by a third party with
knowledge or expertise in the area addressed by that requirement?
Does each performance requirement have one or more associated measures used to objectively evaluate
compliance with the requirement?
If performance results can be practically measured quantitatively, are metrics provided within the
requirement to indicate satisfactory performance?
Technical Basis in Engineering and Operations
Is this reliability standard based upon sound engineering and operating judgment, analysis, or experience,
as determined by expert practitioners in that particular field?
Completeness
Is this reliability standard complete and self-contained? Does the standard depend on external
information to determine the required level of performance?
Consequences for Noncompliance
Page 1 of 4
April 2, 2006
Standard Review Guidelines
In combination with guidelines for penalties and sanctions, as well as other ERO and regional entity
compliance documents, are the consequences of violating a standard clearly known to the responsible
entities?
Clear Language
Is the reliability standard stated using clear and unambiguous language? Can responsible entities, using
reasonable judgment and in keeping with good utility practices, arrive at a consistent interpretation of the
required performance?
Practicality
Does this reliability standard establish requirements that can be practically implemented by the assigned
responsible entities within the specified effective date and thereafter?
Capability Requirements versus Performance Requirements
In general, requirements for entities to have ‘capabilities’ (this would include facilities for
communication, agreements with other entities, etc.) should be located in the standards for certification.
The certification requirements should indicate that entities have a responsibility to ‘maintain’ their
capabilities.
Consistent Terminology
To the extent possible, does this reliability standard use a set of standard terms and definitions that are
approved through the NERC reliability standards development process?
If the standard uses terms that are included in the NERC Glossary of Terms Used in Reliability Standards,
then the term must be capitalized when it is used in the standard. New terms should not be added unless
they have a ‘unique’ definition when used in a NERC reliability standard. Common terms that could be
found in a college dictionary should not be defined and added to the NERC Glossary.
Are the verbs on the ‘verb list’ from the DT Guidelines? If not – do new verbs need to be added to the
guidelines or could you use one of the verbs from the verb list?
Violation Risk Factors (Risk Factor)
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures;
or a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly cause or contribute to bulk electric
system instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures, or could hinder
restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures;
Page 2 of 4
April 2, 2006
Standard Review Guidelines
or a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly and adversely affect the electrical
state or capability of the bulk electric system, or the ability to effectively monitor, control, or
restore the bulk electric system. However, violation of a medium risk requirement is unlikely,
under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
bulk electric system instability, separation, or cascading failures, nor to hinder restoration to a
normal condition.
Lower Risk Requirement
A requirement that, if violated, would not be expected to adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively monitor and control the bulk
electric system. A requirement that is administrative in nature;
or a requirement in a planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely
affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. A planning requirement that is administrative
in nature.
Time Horizon
The drafting team should also indicate the time horizon available for mitigating a violation to the
requirement using the following definitions:
•
Long-term Planning — a planning horizon of one year or longer.
•
Operations Planning — operating and resource plans from day-ahead up to and including
seasonal.
•
Same-day Operations — routine actions required within the timeframe of a day, but not realtime.
•
Real-time Operations — actions required within one hour or less to preserve the reliability of
the bulk electric system.
•
Operations Assessment — follow-up evaluations and reporting of real time operations.
Violation Severity Levels
The drafting team should indicate a set of violation severity levels that can be applied for the
requirements within a standard. (‘Violation severity levels’ replace existing ‘levels of non-compliance.’)
The violation severity levels may be applied for each requirement or combined to cover multiple
requirements, as long as it is clear which requirements are included.
The violation severity levels should be based on the following definitions:
•
Lower: mostly compliant with minor exceptions — The responsible entity is mostly compliant
with and meets the intent of the requirement but is deficient with respect to one or more minor
details. Equivalent score: 95% to 99% compliant.
•
Moderate: mostly compliant with significant exceptions — The responsible entity is mostly
compliant with and meets the intent of the requirement but is deficient with respect to one or
more significant elements. Equivalent score: 85% to 94% compliant.
Page 3 of 4
April 2, 2006
Standard Review Guidelines
•
High: marginal performance or results — The responsible entity has only partially achieved
the reliability objective of the requirement and is missing one or more significant elements.
Equivalent score: 70% to 84% compliant.
•
Severe: poor performance or results — The responsible entity has failed to meet the reliability
objective of the requirement. Equivalent score: less than 70% compliant.
Compliance Monitor
Replace, ‘Regional Reliability Organization’ with ‘Regional Entity’.
Fill-in-the-blank Requirements
Do not include any ‘fill-in-the-blank’ requirements. These are requirements that assign one
entity responsibility for developing some performance measures without requiring that the
performance measures be included in the body of a standard – then require another entity to
comply with those requirements.
Every reliability objective can be met, at least at a threshold level, by a North American
standard. If we need regions to develop regional standards, such as in under-frequency load
shedding, we can always write a uniform North American standard for the applicable functional
entities as a means of encouraging development of the regional standards.
Requirements for Regional Reliability Organization
Do not write any requirements for the Regional Reliability Organization. Any requirements
currently assigned to the RRO should be re-assigned to the applicable functional entity.
Effective Dates
Must be 1st day of 1st quarter after entities are expected to be compliant – must include time to
file with regulatory authorities and provide notice to responsible entities of the obligation to
comply. If the standard is to be actively monitored, time for the Compliance Monitoring and
Enforcement Program to develop reporting instructions and modify the Compliance Data
Management System(s) both at NERC and Regional Entities must be provided in the
implementation plan.
Associated Documents
If there are standards that are referenced within a standard, list the full name and number of the
standard under the section called, ‘Associated Documents’.
Functional Model Version 3
Review the requirements against the latest descriptions of the responsibilities and tasks assigned
to functional entities as provided in pages 13 through 53 of the draft Functional Model Version
3.
Page 4 of 4
April 2, 2006
Nomination Form —Transmission Vegetation Management Standard Drafting
Team
Please return this form to [email protected] by July 17, 2007 with “Trans Veg SDT
Nomination” in the subject line. For questions, please contact Harry Tom at 609-452-8060 or
[email protected].
Although the meeting location hasn’t been determined, the first meeting of the standard
drafting team will be August 28–30, 2007.
Name:
Organization:
Address:
Office
Telephone:
E-mail:
Please briefly describe your experience and qualifications to serve on the
Transmission Vegetation Management Standard Drafting Team. Candidates
should have expertise in one or more of the following areas:
-
Transmission line rights-of-way (ROW) vegetation management or ROW
maintenance
-
Transmission line design and ratings
-
Regulatory or legal considerations in ROW maintenance
-
Existing codes and good practices in vegetation management
Previous experience developing or applying NERC or IEEE standards is beneficial,
but not a requirement.
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
Nomination Form —Transmission Vegetation Management Standard Drafting Team
I represent the
following NERC
Reliability
Region(s) (check
all that apply):
I represent the following Industry Segment (check one):
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs and ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, and Provincial Regulatory or other
Government Entities
10 – Regional Reliability Organizations and Regional Entities
Which of the following Function(s) do you have expertise or responsibilities:
Reliability Coordinator
Transmission Service Provider
Balancing Authority
Transmission Owner
Interchange Authority
Load Serving Entity
Planning Authority or Coordinator
Distribution Provider
Transmission Operator
Purchasing-selling Entity
Generator Operator
Generator Owner
Transmission Planner
Resource Planner
Compliance Monitor
Market Operator
Provide the names and contact information for two references who could attest
to your technical qualifications and your ability to work well in a group.
Name:
Office
Telephone:
Organization:
E-mail:
Name:
Office
Telephone:
Organization:
E-mail:
-2-
FAC-003-2 — Transmission Vegetation Management Program
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and
will be removed when the standard becomes effective.
Development Steps Completed:
1. SC approved SAR for initial posting (January 11, 2007).
2. SAR posted for comment (January 15–February 14, 2007).
3. SAR posted for comment (April 10–May 9, 2007).
4. SC authorized moving the SAR forward to standard development (June 27, 2007).
Proposed Action Plan and Description of Current Draft:
This is the initial posting of the proposed revisions to the requirements and measures in the
standard. Once there is consensus on the language in the requirements and measures, the
drafting team will add compliance elements to the standard.
Future Development Plan:
Anticipated Actions
Anticipated Date
1.
2.
3.
4.
5.
6.
7.
Draft 1: October 22, 2008
Page 1 of 10
FAC-003-2 — Transmission Vegetation Management Program
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Active Transmission Line Right of Way — A strip of land that is occupied by active
transmission facilities. This corridor does not include the inactive or unused part of the Right
of Way intended for other facilities.
Critical Clearance Zone — The area mapped by the radial distance around a conductor
specified in Table I of Attachment 1 to reliability standard FAC-003-2 — Transmission
Vegetation Management Program when the conductor is energized and operating between noload and its Rating, including the design blowout, however, the zone shall not extend beyond
the limits of the Active Transmission Line Right of Way.
Draft 1: October 22, 2008
Page 2 of 10
FAC-003-2 — Transmission Vegetation Management Program
A. Introduction
1. Title:
Transmission Vegetation Management Program
2. Number: FAC-003-2
3. Purpose: To improve the reliability of the Bulk Electric System by preventing vegetation
related outages that could lead to Cascading.
4. Applicability
4.1. Functional Entities:
4.1.1. Transmission Owner
4.1.2. Reliability Coordinator
4.2. Facilities:
4.2.1. Transmission lines (“applicable lines”) operated at 200kV or higher, and
transmission lines operated below 200kV designated by the Reliability
Coordinator as being subject to this standard including but not limited to those
that cross lands owned by federal1, state, provincial, public, private, or tribal
entities.
4.2.2. Transmission lines operated below 200kV designated by the Reliability
Coordinator as being subject to this standard become subject to this standard
12 months after the date the Reliability Coordinator initially designates the
transmission line as being subject to this standard.
4.2.3. Existing transmission line(s) operated at 200kV or higher that are newly
acquired by a Transmission Owner and were not previously subject to this
standard, become subject to this standard 12 months after the acquisition date
of the transmission line(s).
5. Effective Dates:
In those jurisdictions where regulatory approval is required, the first calendar day of the
first calendar quarter one year after applicable regulatory authority approval for all
requirements; or, in those jurisdictions where no regulatory approval is required, the first
calendar day of the first calendar quarter one year following Board of Trustees adoption.
1
EPAct 2005 section 1211c: “Access approvals by Federal agencies”
Draft 1: October 22, 2008
Page 3 of 10
FAC-003-2 — Transmission Vegetation Management Program
B. Requirements
R1. Each Transmission Owner shall have a documented transmission vegetation
management program designed to control vegetation on its Active Transmission
Lines’ Rights of Way. The transmission vegetation management program shall:
R1.1. Specify the methodologies that the Transmission Owner uses to control
vegetation.2
R1.2. Specify a vegetation inspection frequency of at least once per calendar
year that takes into account local3 and environmental factors.
R1.3. Require an annual plan that identifies the applicable lines to be
maintained and associated work to be performed during the year. It shall
be flexible to adjust to changing conditions and to findings from
vegetation inspections. Adjustments to the plan within the year are
permissible. The plan shall take into consideration permitting and
scheduling requirements from landowners or regulatory authorities. It
shall support the objectives of the transmission vegetation management
program and use the methodologies outlined in the transmission
vegetation management program.
R1.4. Require a process or procedure for response to imminent threats of a
vegetation related Sustained Outage. The process or procedure shall
specify actions which shall include immediate communication of the
threat to the Transmission Operator, and may include actions such as a
temporary reduction in line Rating, switching lines out of service, or
other actions.
R1.5. Specify an interim corrective action process for use when the
Transmission Owner is constrained from performing vegetation
maintenance as planned.
R2. Each Transmission Owner shall implement its imminent threat procedure when
the Transmission Owner has knowledge, obtained through normal operating
practices or notification from others, that the Critical Clearance Zone is
approached by vegetation to prevent an encroachment of the Critical Clearance
Zone.
R3. Each Transmission Owner shall conduct inspections of all applicable lines in
accordance with the frequency specified in its transmission vegetation
management program.
R4. Each Transmission Owner shall prevent encroachment within the Critical
Clearance Zone of its applicable lines with the following exceptions:
2
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices,
while not a requirement of this standard, is considered to be an industry best practice.
3
Local factors include treatment cycle, extent and type of treatment, and their relationship to the normal growth
rate.
Draft 1: October 22, 2008
Page 4 of 10
FAC-003-2 — Transmission Vegetation Management Program
Encroachments of the Critical Clearance Zone that result from natural
disasters.4
Encroachments of the Critical Clearance Zone that result from human or
animal activity.5
R5. Each Transmission Owner shall prevent Sustained Outages of applicable lines6
due to vegetation growing into a conductor operating between no-load and its
Rating with the following exceptions:
Sustained Outages of applicable lines that result from natural disasters.4
Sustained Outages of applicable lines that result from human or animal
activity.5
R6. Each Transmission Owner shall prevent Sustained Outages of applicable lines6
due to the blowing together of vegetation and a conductor within an Active
Transmission Line Right of Way (operating within design blow-out conditions)
with the following exception:
Sustained Outages of applicable lines that result from sustained winds or
gusts due to natural disasters.4
R7. Each Transmission Owner shall prevent Sustained Outages of applicable lines6
due to vegetation falling into a conductor from within an Active Transmission
Line Right of Way with the following exceptions:
Sustained Outages of applicable lines that result from natural disasters.4
Sustained Outages of applicable lines that result from human or animal
activity.5
R8. Each Transmission Owner shall implement its annual work plan for vegetation
management to accomplish the purpose of this standard within the extent of its
easement and/or legal rights.
R9. Each Reliability Coordinator in consultation with its Transmission Owner(s)
and neighboring Reliability Coordinator(s) shall jointly prepare and keep
current, a list of designated applicable lines that are operated below 200kV, if
any, which are subject to this standard.
R10. Each Reliability Coordinator shall document its method for assessing the
reliability significance of sub-200kV lines considering all of the following:
4
Examples include, but are not limited to, earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh
gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice storms, and
floods.
5
Examples include, but are not limited to, logging, animal severing tree, vehicle contact with tree, arboricultural
activities or horticultural or agricultural activities, or removal or digging of vegetation.
6
Multiple Sustained Outages on an individual line, if caused by the same vegetation, shall be considered as one
outage regardless of the actual number of outages within a 24-hour period.
Draft 1: October 22, 2008
Page 5 of 10
FAC-003-2 — Transmission Vegetation Management Program
R10.1 Transmission lines whose loss would result in the exceedance of an
Interconnection Reliability Operating Limit (IROL)
R10.2 Transmission lines whose loss would place the grid at an unacceptable
risk of instability, separation, or cascading failures.
B. Measures
M1. The Transmission Owner has a documented transmission vegetation management
program designed to control vegetation on the Active Transmission Line Right of
Way. (R1)
M1.1
The Transmission Owner’s transmission vegetation management program
specifies the methodologies that the Transmission Owner uses to control
vegetation.
M1.2
The Transmission Owner’s transmission vegetation management program
specifies a vegetation inspection frequency that takes into account local and
environmental factors. This inspection frequency shall be at least once per
calendar year.
M1.3
The Transmission Owner’s transmission vegetation management program
requires an annual plan and it identifies the applicable lines to be maintained
and related vegetation management work to be performed during the
calendar year while taking into consideration permitting and scheduling
requirements from landowners or regulatory authorities.
M1.4
The Transmission Owner’s transmission vegetation management program
requires an imminent threat process or procedure for responding to imminent
threats of a vegetation-related Sustained Outage including immediate
communication of the threat to the Transmission Operator, and may include a
temporary reduction in line Rating, switching lines out of service, and/or
other actions that may be taken until the threat is relieved.
M1.5
The Transmission Owner’s transmission vegetation management program
specifies the interim corrective action process for use when the Transmission
Owner is constrained from performing vegetation maintenance as planned.
M2. The Transmission Owner has evidence that it implemented its imminent threat
procedure when it obtained knowledge that the Critical Clearance Zone was
approached by vegetation. (R2)
M3. The Transmission Owner has evidence that it conducted vegetation inspections of all
applicable transmission lines in accordance with the frequency specified in its
transmission vegetation management program. (R3)
M4. The Transmission Owner has evidence such as inspection records, imminent threat
reports or quality assurance reports, demonstrating there were no vegetation
encroachments into the Critical Clearance Zone. (R4)
M5. The Transmission Owner has evidence that there was not a Sustained Outage of an
applicable line due to vegetation growing into a conductor operating between no-load
and its Rating. (R5)
Draft 1: October 22, 2008
Page 6 of 10
FAC-003-2 — Transmission Vegetation Management Program
M6. The Transmission Owner has evidence that there was not a Sustained Outage of an
applicable line due to the blowing together of vegetation and a conductor within the
Active Transmission Line Right of Way. (R6)
M7. The Transmission Owner has evidence that there was not a Sustained Outage of an
applicable line due to vegetation falling into a conductor from within the Active
Transmission Line Right of Way. (R7)
M8. The Transmission Owner has evidence that it is implementing, or has implemented,
its annual work plan. (R8)
M9. The Reliability Coordinator has evidence that it consulted with its Transmission
Owner(s) and adjacent Reliability Coordinator(s), prepared and kept current a list of
designated sub-200kV transmission lines, if any, which are subject to this standard.
(R9)
M10. The Reliability Coordinator has evidence that it has defined its methods for assessing
the reliability significance of sub-200kV lines and has developed selection criteria for
listing any sub-200kV lines. (R10)
C. Compliance (To be added)
D. Regional Differences
None identified.
E. Associated Technical Reference Documents
FAC-003 Reference — Transmission Vegetation Management — White Paper.
Version History
Version
Date
Action
Change Tracking
1
TBA
1. Added “Standard Development
Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section
A, 5.2.
3. Added “Proposed Effective Date:
April 7, 2006” to footer.
4. Added “Draft 3: November 17,
2005” to footer.
1
April 4, 2007
Draft 1: October 22, 2008
Regulatory Approval — Effective Date
New
Page 7 of 10
FAC-003-2 — Transmission Vegetation Management Program
FAC-003-2 Attachment 1
The Critical Clearance Zone is the area mapped by the radial distance around a conductor
specified in Table I below when the conductor is energized and operating between no-load and
its Rating, including the design blow-out, however, the zone shall not extend beyond the limits
of the Active Transmission Line Right of Way.
TABLE I — Minimum Vegetation Clearance Distances
For Alternating Current Voltages
( AC )
( AC )
Nominal
System
Maximum
System
D feet
(meters)
D feet
(meters)
D feet
(meters)
D feet
(meters)
D feet
(meters)
Voltage
(kV)
Voltage
(kV)
sea level
3,000ft
(914.4m)
4,000ft
(1219.2m)
5,000ft
(1524m)
6,000ft
(1828.8m)
765
800
8.06ft
(2.46m)
8.89ft
(2.71m)
9.17ft
(2.80m)
9.45ft
(2.88m)
9.73ft
(2.97m)
500
550
5.06ft
(1.54m)
5.66ft
(1.73m)
5.86ft
(1.79m)
6.07ft
(1.85m)
6.28ft
(1.91m)
345
362
3.12ft
(0.95m)
3.53ft
(1.08m)
3.67ft
(1.12m)
3.82ft
(1.16m)
3.97ft
(1.21m)
230
242
2.97ft
(0.91m)
3.36ft
(1.02m)
3.49ft
(1.06m)
3.63ft
(1.11m)
3.78ft
(1.15m)
161*
169
2ft
(0.61m)
2.28ft
(0.69m)
2.38ft
(0.73m)
2.48ft
(0.76m)
2.58ft
(0.79m)
138*
145
1.7ft
(0.52m)
1.94ft
(0.59m)
2.03ft
(0.62m)
2.12ft
(0.65m)
2.21ft
(0.67m)
115*
121
1.41ft
(0.43m)
1.61ft
(0.49m)
1.68ft
(0.51m)
1.75ft
(0.53m)
1.83ft
(0.56m)
88*
100
1.15ft
(0.35m)
1.32ft
(0.40m)
1.38ft
(0.42m)
1.44ft
(0.44m)
1.5ft
(0.46m)
69*
72
0.82ft
(0.25m)
0.94ft
(0.29m)
0.99ft
(0.30m)
1.03ft
(0.31m)
1.08ft
(0.33m)
*As designated by the Reliability Coordinator
Draft 1: October 22, 2008
Page 8 of 10
FAC-003-2 — Transmission Vegetation Management Program
TABLE I — Minimum Vegetation Clearance Distances (D)
For Alternating Current Voltages
( AC )
( AC )
Nominal
System
Maximum
System
D feet
(meters)
D feet
(meters)
D feet
(meters)
D feet
(meters)
D feet
(meters)
Voltage
(kV)
Voltage
(kV)
7,000ft
(2133.6m)
8,000ft
(2438.4m)
9,000ft
(2743.2m)
10,000ft
(3048m)
11,000ft
(3352.8m)
765
800
10.01ft
(3.05m)
10.29ft
(3.14m)
10.57ft
(3.22m)
10.85ft
(3.31m)
11.13ft
(3.39m)
500
550
6.49ft
(1.98m)
6.7ft
(2.04m)
6.92ft
(2.11m)
7.13ft
(2.17m)
7.35ft
(2.24m)
345
362
4.12ft
(1.26m)
4.27ft
(1.30m)
4.43ft
(1.35m)
4.58ft
(1.40m)
4.74ft
(1.44m)
230
242
3.92ft
(1.19m)
4.07ft
(1.24m)
4.22ft
(1.29m)
4.37ft
(1.33m)
4.53ft
(1.38m)
161*
169
2.69ft
(0.82m)
2.8ft
(0.85m)
2.91ft
(0.89m)
3.03ft
(0.92m)
3.14ft
(0.96m)
138*
145
2.3ft
(0.70m)
2.4ft
(0.73m)
2.49ft
(0.76m)
2.59ft
(0.79m)
2.7ft
(0.82m)
115*
121
1.91ft
(0.58m)
1.99ft
(0.61m)
2.07ft
(0.63m)
2.16ft
(0.66m)
2.25ft
(0.69m)
88*
100
1.57ft
(0.48m)
1.64ft
(0.50m)
1.71ft
(0.52m)
1.78ft
(0.54m)
1.86ft
(0.57m)
69*
72
1.13ft
(0.34m)
1.18ft
(0.36m)
1.23ft
(0.37m)
1.28ft
(0.39m)
1.34ft
(0.41m)
*As designated by the Reliability Coordinator
Draft 1: October 22, 2008
Page 9 of 10
FAC-003-2 — Transmission Vegetation Management Program
TABLE I — Minimum Vegetation Clearance Distances (D)
For Direct Current Voltages
sea level
D feet
(meters)
3,000ft
(914.4m) Alt.
D feet
(meters)
4,000ft
(1219.2m)
Alt.
D feet
(meters)
5,000ft
(1524m)
Alt.
D feet
(meters)
6,000ft
(1828.8m)
Alt.
500
13.92ft
(4.24m)
10.07ft
(3.07m)
7.89ft
(2.40m)
4.78ft
(1.46m)
3.43ft
(1.05m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
5.35ft
(1.63m)
4.02ft
(1.23m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
5.55ft
(1.69m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
5.75ft
(1.75m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
5.95ft
(1.81m)
4.34ft
(1.32m)
Pole to Pole
Nominal
Voltage
(kV)
D feet
(meters)
7,000ft
(2133.6m)
Alt.
D feet
(meters)
(8,000ft
(2438.4m)
Alt.
D feet
(meters)
9,000ft
(2743.2m)
Alt.
D feet
(meters)
10,000ft
(3048m)
Alt.
D feet
(meters)
11,000ft
(3352.8m)
Alt.
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
6.15ft
(1.87m)
4.5ft
(1.37m)
16.9ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
6.36ft
(1.94m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
6.57ft
(2.00m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
6.77ft
(2.06m)
5ft
(1.52m)
17.97ft
(5.48m)
(13.54ft
4.13m)
10.92ft
(3.33m)
6.98ft
(2.13m)
5.17ft
(1.58m)
( DC )
Pole to Pole
Nominal
Voltage
(kV)
1500
1200
1000
800
1500
1200
1000
800
500
Draft 1: October 22, 2008
D feet
(meters)
Page 10 of 10
FAC-003-1 Mapping to Revised NERC Reliability Standard FAC-003-2
Standard FAC-003-1
Comment
Proposed Standard FAC-003-2
NERC Board Approved
1. Title: Transmission Vegetation Management
1. Title: No Change (N/C)
Program
Program
2. Number: FAC-003-1
3. Purpose: To improve the reliability of the electric
2. Number: Update to latest Revision
3. Purpose: Changed electric transmission systems
transmission systems by preventing
outages from vegetation located on transmission
rights-of-way (ROW) and minimizing
outages from vegetation located adjacent to ROW,
maintaining clearances between
transmission lines and vegetation on and along
transmission ROW, and reporting vegetationrelated
outages of the transmission systems to the respective
Regional Reliability
Organizations (RRO) and the North American Electric
Reliability Council (NERC).
to Bulk Electric System. Changed to a shorter more
concise purpose statement. The various explanatory
objectives are now addressed within the standard’s
requirements.
4. Applicability:
4. Applicability:
Separated applicability between functional
entities and facilities for clarity
4.1. Transmission Owner
4.2. Regional Reliability Organization
1. Title: Transmission Vegetation Management
4.1 now is 4.4.1 No change
4.2 Removed Regional Reliability Organization and
added 4.1.2 Reliability Coordinator
4.3 Clarified facility applicability in 4.2, 4.2.1, 4.2.2
and 4.2.3 as stated below
4.3. This standard shall apply to all transmission lines
operated at 200 kV and above and to any lower voltage
lines designated by the RRO as critical to the reliability 4.2.1. Added term “applicable lines” for format
of the electric system in the region.
efficiency in the standard verbiage.
Ensures that all lines are covered by the standard
regardless of the owner of the over which they cross.
1
2. Number: FAC-003-2
3. Purpose: To improve the reliability of the Bulk
Electric System by preventing vegetation related
outages that could lead to widespread cascading
failures.
4. Applicability
4.1 Functional Entities:
4.1.1 Transmission Owner
4.1.2 Reliability Coordinator
4.2 Facilities:
4.2.1 Transmission lines (“applicable lines”)
operated at 200kV or higher, and
transmission lines operated below
200kV designated by the Reliability
Coordinator as being subject to this
standard including but not limited to
those that cross lands owned by federal,
state, provincial, public, private, or
FAC-003-1 Mapping to Revised NERC Reliability Standard FAC-003-2
Standard FAC-003-1
Comment
Proposed Standard FAC-003-2
NERC Board Approved
tribal entities.
4.2.2 Added to identify the time frame allowed to bring
sub 200kV lines into compliance with the standard
after the Reliability Coordinator has determined that
they are subject to the standard.
4.2.3.
Added to specify the time frame allowed, for a newly
acquired above 200kV line, which was not previously
subject to the standard, to become subject to the
standard.
Effective Dates:
5.1 One calendar year from the date of adoption by
the NERC Board of Trustees for Requirement 1 and 2.
5.2 Sixty calendar days from the date of adoption by
the NERC Board of Trustees for the Requirements 3
and 4.
Effective Dates:
Reworded both 5.1 and 5.2 as one statement for
consistency with standards process for a standard
revision.
R1. The Transmission Owner shall prepare, and keep
current, a formal transmission vegetation
management program (TVMP). The TVMP shall
include the Transmission Owner’s
objectives, practices, approved procedures, and work
specifications.
R1. Replaced “prepare, and keep current” with “have”
and removed the longer series of terms with one term
“designed to control vegetation”. Clarified that this
applies on the Active Transmission Line Right of Way.
R1.1 New language replaced the longer series that was
2
4.2.2 Transmission lines operated below
200kV designated by the Reliability
Coordinator as being subject to this
standard become subject to this
standard 12 months after the date the
Reliability Coordinator initially
designates the transmission line as
being subject to this standard.
4.2.3 Existing transmission line(s) operated at
200kV or higher that are newly
acquired by a Transmission Owner and
were not previously subject to this
standard, become subject to this
standard 12 months after the acquisition
date of the transmission line(s).
5. Effective Dates: In those jurisdictions where
regulatory approval is required, the first calendar day
of the first calendar quarter one year after applicable
regulatory authority approval for all requirements; or,
in those jurisdictions where no regulatory approval is
required, the first calendar day of the first calendar
quarter one year following Board of Trustees adoption.
R1. Each Transmission Owner shall have a
documented transmission vegetation management
program designed to control vegetation on its Active
Transmission Lines’ Rights of Way. The transmission
vegetation management program shall:
R1.1. Specify the methodologies that the Transmission
FAC-003-1 Mapping to Revised NERC Reliability Standard FAC-003-2
Standard FAC-003-1
Comment
Proposed Standard FAC-003-2
NERC Board Approved
R1.1. The TVMP shall define a schedule for and the
type (aerial, ground) of ROW vegetation
inspections. This schedule should be flexible enough to
adjust for changing conditions. The inspection
schedule shall be based on the anticipated growth of
vegetation and any other environmental or operational
factors that could impact the
relationship of vegetation to the Transmission Owner’s
transmission lines.
R2. The Transmission Owner shall create and
implement an annual plan for vegetation
management work to ensure the reliability of the
system. The plan shall describe the methods
used, such as manual clearing, mechanical clearing,
herbicide treatment, or other actions. The
plan should be flexible enough to adjust to changing
conditions, taking into consideration
anticipated growth of vegetation and all other
environmental factors that may have an impact
on the reliability of the transmission systems.
Adjustments to the plan shall be documented as
they occur. The plan should take into consideration the
time required to obtain permissions or
permits from landowners or regulatory authorities.
Each Transmission Owner shall have
systems and procedures for documenting and tracking
the planned vegetation management
work and ensuring that the vegetation management
work was completed according to work
specifications.
previously implied by R1 in version 1.
R1.1 replaced by R1.2. Changed inspection schedule
to inspection frequency and specified the frequency to
be at least once per calendar year. Note also that R3
has been added to clarify that the conduction of
inspections is a separate requirement from specifying
the frequency that inspections will occur.
R2 replaced by R1.3 and R8. R1.3 is the explanation
of the TVMP documentation requirements changes
only. See the associated remarks below under R8 for
the changes with respect to implementation of the
annual plan.
3
Owner uses to control vegetation.
R1.2. Specify a vegetation inspection frequency of at
least once per calendar year that takes into account
local 1 and environmental factors.
R1.3. Require an annual plan that identifies the
applicable lines to be maintained and associated work
to be performed during the year. It shall be flexible to
adjust to changing conditions and to findings from
vegetation inspections. Adjustments to the plan within
the year are permissible. The plan shall take into
consideration permitting and scheduling requirements
from landowners or regulatory authorities. It shall
support the objectives of the transmission vegetation
management program and use the methodologies
outlined in the transmission vegetation management
program.
FAC-003-1 Mapping to Revised NERC Reliability Standard FAC-003-2
Standard FAC-003-1
Comment
Proposed Standard FAC-003-2
NERC Board Approved
R1.5. Each Transmission Owner shall establish and
document a process for the immediate communication
of vegetation conditions that present an imminent
threat of a transmission line outage. This is so that
action (temporary reduction in line rating, switching
line out of service, etc.) may be taken until the threat is
relieved.
R1.4. Each Transmission Owner shall develop
mitigation measures to achieve sufficient
clearances for the protection of the transmission
facilities when it identifies locations
on the ROW where the Transmission Owner is
restricted from attaining the clearances
specified in Requirement 1.2.1.
R1.5 replaced by R1.4 which requires a documented
process to respond with examples of actions including
immediate communications and other actions that may
be taken to relieve the threat.
R1.4 replaced by R1.5 – Now referred to as interim
corrective action process to address situations where
vegetation maintenance activities cannot be performed
as planned. The term corrective action plan is used in
lieu of mitigation plan to avoid confusion with other
uses in NERC of “mitigation plan”
New R2 added to ensure that implementation of the
imminent threat procedure as a stand-alone
requirement.
R3. Has been added to separate this conduct of
inspections from R1.2 documentation which specifies
the frequency for inspections.
The old R1.2. Has been changed by elimination of
Clearance 1 and the replacement of Clearance 2 with
the Critical Clearance Zone. See R2 and R4
4
R1.4. Require a process or procedure for response to
imminent threats of a vegetation related Sustained
Outage. The process or procedure shall specify
actions which shall include immediate communication
of the threat to the Transmission Operator, and may
include actions such as a temporary reduction in line
rating, switching lines out of service, or other actions.
R1.5. Specify the general interim corrective action
process for use when the Transmission Owner is
constrained from performing vegetation maintenance
as planned.
R2. Each Transmission Owner shall implement its
imminent threat procedure when the Transmission
Owner has knowledge, obtained through normal
operating practices or notification from others, that
the Critical Clearance Zone is approached by
vegetation to prevent an encroachment of the Critical
Clearance Zone.
R3.Each Transmission Owner shall conduct
inspections of all applicable lines in accordance with
the frequency specified in its transmission vegetation
management program.
FAC-003-1 Mapping to Revised NERC Reliability Standard FAC-003-2
Standard FAC-003-1
Comment
Proposed Standard FAC-003-2
NERC Board Approved
R1.2. The Transmission Owner, in the TVMP, shall
identify and document clearances between vegetation
and any overhead, ungrounded supply conductors,
taking into consideration transmission line voltage, the
effects of ambient temperature on
conductor sag under maximum design loading and the
effects of wind velocities on conductor sway.
Specifically, the Transmission Owner shall establish
R1.2.1 - Clearance 1 requirement eliminated:
clearances to be achieved at the time of vegetation
management work identified herein as Clearance 1,
and shall also establish and maintain a set of clearances
identified herein as Clearance 2 to prevent flashover
between vegetation and overhead ungrounded supply
conductors.
R1.2.1. Clearance 1 — The Transmission Owner shall
determine and document appropriate clearance
distances to be achieved at the time of transmission
vegetation management work based upon local
conditions and the expected time frame in which the
Transmission Owner plans to return for future
vegetation management work. Local conditions
include, but are not limited to: operating voltage,
appropriate vegetation management techniques, fire
risk, reasonably anticipated tree and conductor
movement, species type and growth rates, species
failure characteristics, local climate and rainfall
patterns, line terrain and elevation location of the
vegetation within the span, and worker approach
distance requirements, Clearance 1 distances shall be
greater than those defined by Clearance 2 below
under all rated electrical operating conditions.
R1.2.2 replaced by R4 - Clearance 2 has been replaced
by Critical Clearance Zone.
the old R1.1.2 was a documentation requirement within
the TVMP whereas R4
specifies encroachments as violations. Under the
Levels of Non-Compliance in FAC-003-1, Level 3:
2.3.2 covered failure to “maintain…Clearance 2”. Note
that encroachment reporting will be addressed later in
R4 Each Transmission Owner shall prevent
a VSL for R4
encroachment within the Critical Clearance Zone of
5
FAC-003-1 Mapping to Revised NERC Reliability Standard FAC-003-2
Standard FAC-003-1
Comment
Proposed Standard FAC-003-2
NERC Board Approved
R1.2.2. Clearance 2 — The Transmission Owner shall
determine and document specific radial clearances to
be maintained between vegetation and conductors
under all rated electrical operating conditions. These
minimum clearance distances are necessary to prevent
flashover between vegetation and conductors and will
vary due to such factors as altitude and operating
voltage. These Transmission Owner-specific minimum
clearance distances shall be no less than those set forth
in the Institute of Electrical and Electronics Engineers
(IEEE) Standard 516-2003 (Guide for Maintenance
Methods on Energized Power Lines) and as specified
in its Section 4.2.2.3, Minimum Air Insulation
Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system transient
overvoltage factors are not known, clearances shall be
derived from Table 5, IEEE 516-2003, phase-toground distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system transient
overvoltage factors are known, clearances shall be
derived from Table 7, IEEE 516-2003, phase-to-phase
voltages, with appropriate altitude correction
factors applied
its applicable lines with the following exceptions:
1. Encroachments of the Critical Clearance Zone that
result from natural disasters.
2. Encroachments of the Critical Clearance Zone that
result from human or animal activity.
R1.3. All personnel directly involved in the design and
implementation of the TVMP shall
hold appropriate qualifications and training, as defined
by the Transmission Owner, to
perform their duties.
R1.3 – Personnel qualifications has been removed.
R3. The Transmission Owner shall report quarterly to
R3 Outage reporting is now covered in R5-R7 and
6
R5 Each Transmission Owner shall prevent Sustained
FAC-003-1 Mapping to Revised NERC Reliability Standard FAC-003-2
Standard FAC-003-1
Comment
Proposed Standard FAC-003-2
NERC Board Approved
its RRO, or the RRO’s designee, sustained
transmission line outages determined by the
Transmission Owner to have been caused by
vegetation.
R3.1. Multiple sustained outages on an individual line,
if caused by the same vegetation,
shall be reported as one outage regardless of the actual
number of outages within a 24hour period.
R3.2. The Transmission Owner is not required to
report to the RRO, or the RRO’s designee,
certain sustained transmission line outages caused by
vegetation: (1) Vegetation related
outages that result from vegetation falling into lines
from outside the ROW that
result from natural disasters shall not be considered
reportable (examples of disasters
that could create non-reportable outages include, but
are not limited to, earthquakes,
fires, tornados, hurricanes, landslides, wind shear,
major storms as defined either by
the Transmission Owner or an applicable regulatory
body, ice storms, and floods), and
(2) Vegetation-related outages due to human or animal
activity shall not be considered
reportable (examples of human or animal activity that
could cause a non-reportable
outage include, but are not limited to, logging, animal
severing tree, vehicle contact
with tree, arboricultural activities or horticultural or
agricultural activities, or removal
or digging of vegetation).
R3.3. The outage information provided by the
Transmission Owner to the RRO, or the
RRO’s designee, shall include at a minimum: the name
M5-M7 and the associated Compliance VSLs for R5R7.
Requirements R5, R6, and R7 specify three types of
Sustained Outages which shall be prevented.
Exceptions have been further defined
Outages in FAC-003-1 R3 were reporting
requirements and were not violations per se. In that
version of the standard the Levels of Non-Compliance
2.2.3, 2.3.1, and 2.4.1 the Sustained Outages were
assigned a level of non-compliance.
Outages of applicable lines due to vegetation growing
into a conductor operating between no-load and rated
conditions with the following exceptions:
1. Sustained Outages of applicable lines that result
from natural disasters.
2. Sustained Outages of applicable lines that result
from human or animal activity.
R6 Each Transmission Owner shall prevent
Sustained Outages of applicable lines due to the
blowing together of vegetation and a conductor
within an Active Transmission Line Right of
Way(operating within design blow out
conditions) with the following exception:
1. Sustained Outages of transmission lines that
result from sustained winds or gusts due to
natural disasters.
R7 Each Transmission Owner shall prevent
Sustained Outages of applicable lines due to
vegetation falling into a conductor from within an
Active Transmission Line Right of Way with the
following exceptions:
1. Sustained Outages of applicable lines that result
from natural disasters.
2. Sustained Outages of applicable lines that result
from human or animal activity.
7
FAC-003-1 Mapping to Revised NERC Reliability Standard FAC-003-2
Standard FAC-003-1
Comment
Proposed Standard FAC-003-2
NERC Board Approved
of the circuit(s) outaged, the
date, time and duration of the outage; a description of
the cause of the outage; other
pertinent comments; and any countermeasures taken
by the Transmission Owner.
R3.4. An outage shall be categorized as one of the
following:
R3.4.1. Category 1 — Grow-ins: Outages caused by
vegetation growing into lines
from vegetation inside and/or outside of the ROW;
R3.4.2. Category 2 — Fall-ins: Outages caused by
vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages caused by
vegetation falling into lines from
outside the ROW.
Category 3 – fall-in outages are no longer reportable.
.
R8 Is a new requirement which separates the
implementation of the annual plan from the creation of
the annual plan. See FAC-003-2, 1.3 above.
R8 Each Transmission Owner shall implement its
annual work plan for vegetation management to
accomplish the purpose of this standard within the
extent of its easement and/or legal rights.
R4. The RRO shall report the outage information
provided to it by Transmission Owner’s, as
required by Requirement 3, quarterly to NERC, as well
as any actions taken by the RRO as a
result of any of the reported outages.
R4 Eliminated. The RRO, which is now the RE, is not
subject to standards.
R9 This new requirement addresses the
8
R9 Each Reliability Coordinator in consultation
FAC-003-1 Mapping to Revised NERC Reliability Standard FAC-003-2
Standard FAC-003-1
Comment
Proposed Standard FAC-003-2
NERC Board Approved
identification of sub-200kV lines.
with their Transmission Owner(s) and neighboring
Reliability Coordinator(s) shall jointly prepare and
keep current, a list of designated applicable lines
that are operated below 200kV, if any, which are
subject to this standard.
R10 Each Reliability Coordinator shall document
its method for assessing the reliability
significance of sub-200kV lines considering
all of the following:
R10.1 Transmission lines whose loss would
result in the exceedance of an Interconnection
Reliability Operating Limit (IROL)
R10.2 Transmission lines whose loss would
place the grid at an unacceptable risk of
instability, separation, or cascading failures.
Footnotes have been added to reference the EPact
2005 and to define the active transmission line
ROW
Footnote added to define local factors
Footnotes added to cover exceptions which were
in FAC-003-1 imbedded within the standard
9
Footnotes on Page 2
Footnotes on Page 3
Footnotes on Page 4
First Draft of Standards for Vegetation Management (Project 2007-07)
First draft of the FAC-003-2 — Transmission Vegetation Management Program standard for
the Vegetation Management Standard Drafting Team (Project 2007-07) is up for a 30-day
comment period. Comments must be submitted through the electronic comment form by
November 25, 2008. If you have questions please contact Harry Tom at
[email protected] or by telephone at 860-550-4157
Background Information:
The Standard Drafting Team revised the Vegetation Management Standard in accordance
with the Standard Authorization Request. The Standard Authorization Request scope
reflects comments from the FERC Order 693 and from stakeholders as well as procedural
updates. The Standard Authorization Request also specified that the revised standard
incorporate compliance program elements of time horizons, violation severity levels, etc. to
bring it into conformance with the latest version of the Reliability Standard Development
Procedure and the ERO Sanctions Guidelines. The compliance elements are not included in
this initial posting. The Standard Drafting Team has prepared a Technical Reference
document to supplement the FAC-003-2 Standard and is posted along with the revised
standard. This posting seeks comment on the Standard revision as well as the Technical
Reference document.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Comment Form — Transmission Vegetation Management Standard FAC-003-2
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. In the Purpose Statement the term “electric transmission systems” was changed to
Bulk Electric System, and the Purpose statement was shortened by moving the
various explanatory objectives to other locations in the revised Standard. Do you
agree with the purpose statement? If not, please explain.
Agree
Disagree
Comments:
2. The Reliability Coordinator was chosen as the proper entity to identify sub-200kV
transmission lines to be subject to this standard (see applicability, R9, and R10). Do
you agree with this choice? If not, please explain.
Agree
Disagree
Comments:
3. In R1 the proposed standard replaces “prepare, and keep current” with “have”,
replaces the list of terms, “objectives, practices, approved procedures, and work
specifications,” with “designed to control vegetation”, defines the “active transmission
line ROW”, and specifies that the transmission vegetation management program
applies to that area. Do you agree with R1? If not, please explain.
Agree
Disagree
Comments:
4. Documentation and implementation of the transmission vegetation management
program which were previously combined in Requirement R1 are now separated in
order to apply appropriate VRFs and time horizons. The implementation of some
elements has been moved into standalone requirements such as inspection cycles
(R3) and annual plan implementation (R8). Do you agree with these revisions and
separation? If not, please explain.
Agree
Disagree
Comments:
5. In R1.2 the Transmission Owner is required to have an inspection frequency of at
least once per calendar year. Do you agree with R1.2? If not, please explain.
Agree
Disagree
Comments:
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Comment Form — Transmission Vegetation Management Standard FAC-003-2
6. In R1.3 the Standard requires that transmission vegetation management program
specify an Annual Plan and specifies parameters for the plan. Implementation of the
Annual Plan is separated and placed in R8. Do you agree with R1.3 and the separation
of the implementation from the specification of the Annual Plan? If not, please explain.
Agree
Disagree
Comments:
7. In R1.4 the Standard requires the Transmission Owner to have an Imminent Threat
Procedure and specifies elements to be in that procedure. Do you agree with R1.4? If
not, please explain.
Agree
Disagree
Comments:
8. Requirement 1 section R1.5 replaces Version 1 sub-requirement R1.4. This section is
now referred to as interim corrective action process. This process addresses
situations where vegetation maintenance activities cannot be performed as planned.
The term corrective action plan is used in lieu of mitigation plan to avoid confusion
with other uses in NERC of “mitigation plan”. Do you agree with R1.5? If not, please
explain.
Agree
Disagree
Comments:
9. Clearance 1 in Version 1 was a “fill-in-the-blank” requirement and was removed from
the standard. Do you agree? If not, please explain.
Agree
Disagree
Comments:
10. Personnel Qualifications in R1.3 in Version 1 was a “fill-in-the-blank” requirement and
was removed from Version 2 of the standard. Do you agree? If not please explain.
Agree
Disagree
Comments:
11. The IEEE 516 standard distances were replaced with the Gallet equation distances.
Clearance 2 was replaced by the Critical Clearance Zone. The Critical Clearance Zone
is defined as the zone of all possible positions of the conductor at the line’s designed
operating ratings including wind factors. (Please refer to pages 22-32 in the Technical
Reference Document on the Critical Clearance Zone for further background for this
question.) The imminent threat procedure, R2, requires action to be taken to prevent
an outage when the Critical Clearance Zone is approached. Do you agree with R2? If
not please explain.
Agree
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Comment Form — Transmission Vegetation Management Standard FAC-003-2
Disagree
Comments:
12. The Standard Drafting Team revised the spark-over (also referred to as “flashover”)
distance thresholds utilizing technically-equivalent Gallet equations in lieu of IEEE 516
minimum air insulation distance (MAID) calculations that were used in FAC-003-1.
The rationale is that the minimum air insulation distances in IEEE 516 were safety
clearances developed under laboratory conditions and thus there exists concern these
distances may be too conservative to apply to lines operating in actual field
conditions. Do you agree with this? If not, please explain.
Agree
Disagree
Comments:
13. The Standard Drafting Team applied a transient overvoltage factor (T) of 1.4 and 2.0
for ac voltage classes of 345kV and above and sub-345kV facilities, respectively.
Version 1, using the IEEE 516 method, assumes a maximum transient overvoltage
value. The Standard Drafting Team asserts that in this application of steady-state
flashovers and due to the design attributes of higher voltage systems, a lower T factor
is applicable. Do you agree with this? If not, please explain.
Agree
Disagree
Comments:
14. R3 has been added to clarify that conduction of inspections is a separate requirement
from specifying the frequency that inspections will occur. Do you agree with R3? If
not please explain.
Agree
Disagree
Comments:
15. Several alternatives to R4 were considered by the drafting team. The drafting team
explored these significantly different alternatives at length. They are outlined below to
provide background to industry during this comment period. (Please refer to pages
22-32 in the Technical Reference Document on the Critical Clearance Zone for further
background for this question.)
•
As written, R4, a new requirement, stipulates that the Transmission Owner
is in violation if an encroachment of the Critical Clearance Zone occurs at
any time. If vegetation enters the Critical Clearance Zone, a violation will
have occurred, regardless of the actual proximity of the vegetation to the
conductor at the time. Evidence will be required to prove that no
encroachments of the Critical Clearance Zone have occurred anywhere at
any time during the annual compliance period. This will require the time
and effort to postpone vegetation maintenance to perform field
investigations and document all possible encroachments.
•
One alternative to R4 required immediate removal of the vegetation or
immediate implementation of the imminent threat procedure upon
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Comment Form — Transmission Vegetation Management Standard FAC-003-2
discovery of a possible encroachment of the Critical Clearance Zone,
thereby proactively preventing an outage. A violation would have occurred
only if the imminent threat process was not successfully implemented.
•
Another alternative was a tiered approach. This tiered approach involved a
“per thousand mile” metric to determine when a violation had occurred and
the severity of the violation. This metric was an attempt to equitably
account for varying exposures that exist due to widely ranging system
sizes.
Do you agree that R4 is written in the most effective way to achieve the purpose of
the standard? If not, what do you propose as an alternative to R4 that would ensure
a level of reliability equal to or better than FAC-003-1?
Agree
Disagree
Comments:
16. Requirements R5, R6, and R7 define that Sustained Outages due to vegetation
growing into, blowing together with, and falling into transmission lines are violations
(subject to certain exemptions). Therefore, all such outages must be reported as
violations of the standard. Do you agree with this change? If not, please explain.
Agree
Disagree
Comments:
17. R8 is a new requirement which separates the implementation of the annual plan from
the requirement to have an annual plan. Do you agree with R8? If not please explain.
Agree
Disagree
Comments:
18. If you have further suggestions for improving this standard or the technical reference
document, please offer them.
Comments:
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Transmission Vegetation Management
NERC Standard FAC-003-2 Technical Reference
Prepared by the
North American Electric Reliability Corporation
Vegetation Management Standard Drafting Team
OCTOBER 20, 2008
NERC Standard FAC-003-2 Technical Reference
Table of Contents
INTRODUCTION .....................................................................................................................................................................3
DISCLAIMER ...........................................................................................................................................................................4
DEFINITION OF TERMS .......................................................................................................................................................5
APPLICABILITY OF THE STANDARD...............................................................................................................................9
TRANSMISSION VEGETATION MANAGEMENT PROGRAM ...................................................................................11
METHODOLOGY TO CONTROL VEGETATION ...........................................................................................................................12
ANSI A300 – BEST MANAGEMENT PRACTICES FOR TREE CARE OPERATIONS......................................................................13
VEGETATION INSPECTION FREQUENCY .................................................................................................................................18
ANNUAL PLANS .....................................................................................................................................................................19
IMMINENT THREAT PROCEDURE ............................................................................................................................................20
INTERIM CORRECTIVE ACTION PROCESS ...............................................................................................................................21
IMPLEMENT IMMINENT THREAT PROCEDURE........................................................................................................22
DETERMINING CLEARANCE DISTANCES FOR VEGETATION NEAR TRANSMISSION LINES .......................................................23
ENCROACHMENTS WITHIN CRITICAL CLEARANCE ZONE............................................................................... 33
SUSTAINED OUTAGES - VEGETATION GROW-INS....................................................................................................34
SUSTAINED OUTAGES – VEGETATION AND CONDUCTORS BLOWING TOGETHER.....................................35
SUSTAINED OUTAGES - VEGETATION FALLING INTO CONDUCTORS ..............................................................37
IMPLEMENT ANNUAL WORK PLAN ..............................................................................................................................38
DESIGNATING SUB-200KV LINES....................................................................................................................................39
DOCUMENTING METHOD OF IDENTIFYING SUB-200KV LINES............................................................................40
LIST OF ACRONYMS AND ABBREVIATIONS ...............................................................................................................41
REFERENCES ........................................................................................................................................................................42
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NERC Standard FAC-003-2 Technical Reference
Introduction
This document is intended to provide supplemental information and guidance for complying with
the requirements of Reliability Standard FAC-003-2. It is a supporting document and provides
explanatory background to the requirements of the Standard.
The purpose of the Standard is to improve the reliability of the Bulk Electric System by
preventing vegetation related outages that could lead to Cascading.
Compliance with the Standard is mandatory and enforceable.
FAC-003-2 Technical Reference
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NERC Standard FAC-003-2 Technical Reference
Disclaimer
This supporting document may explain or facilitate implementation of reliability standard FAC003-2 — Transmission Vegetation Management but does not contain mandatory requirements
subject to compliance review.
FAC-003-2 Technical Reference
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NERC Standard FAC-003-2 Technical Reference
Def inition of Terms
Active Transmission Line Right of Way* — A strip of land that is occupied by active
transmission facilities. This corridor does not include the inactive or unused part of the Right-ofWay intended for other facilities.
Examples of active and inactive portions of corridors include:
1) Where portions of the right of way are occupied by active facilities and other portions
are acquired to accommodate future facilities. Power plant exits are examples where
large rights-of-way are obtained for maximum corridor utilization and may currently
have fewer structures constructed (see Figure 1 on page 6).
2) Rights of way where corridor edge zones are provided for vegetation to exist (see
Figure 2 on page 7).
3) Where double-circuit structures are installed but only one circuit is currently strung
with conductors (see Figure 3 on page 8).
Critical Clearance Zone* — The area mapped by the radial distance around a conductor
specified in Table I of Attachment 1to the reliability standard FAC-003-2 — Transmission
Vegetation Management Program when the conductor is energized and operating between noload and its Rating, including the design blow-out, however the zone shall not extend beyond the
limits of the Active Transmission Line Right of Way.
Sustained Outage** — The deenergized condition of a transmission line resulting from a fault
or disturbance following an unsuccessful automatic reclosing sequence and/or unsuccessful
manual reclosing procedure.
Cascading ** — The uncontrolled successive loss of system elements triggered by an incident at
any location. Cascading results in widespread electric service interruption that cannot be
restrained from sequentially spreading beyond an area predetermined by studies.
Rating ** — The operational limits of a transmission system element under a set of specified
conditions.
*To be added to the NERC glossary of terms with final approval of this standard revision
** Currently defined in the NERC glossary of terms
FAC-003-2 Technical Reference
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NERC Standard FAC-003-2 Technical Reference
Figure 1
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NERC Standard FAC-003-2 Technical Reference
Figure 2
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NERC Standard FAC-003-2 Technical Reference
Figure 3
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NERC Standard FAC-003-2 Technical Reference
Applicability of the Standard
4.
Applicability:
4.1.
Functional Entities:
4.1.1. Transmission Owner
4.1.2. Reliability Coordinator
4.2.
Facilities:
4.2.1. Transmission lines (“applicable lines”) operated at 200kV or higher, and
transmission lines operated below 200kV designated by the Reliability
Coordinator as being subject to this standard including but not limited to those
that cross lands owned by federal 1 , state, provincial, public, private, or tribal
entities.
4.2.2. Transmission lines operated below 200kV as designated by the Reliability
Coordinator as being subject to this standard become subject to this standard 12
months after the date the Reliability Coordinator initially designates the
Transmission Line as being subject to this standard.
4.2.3. Existing transmission line(s) operated at 200kV or higher that are newly
acquired by a Transmission Owner and were not previously subject to this
standard, become subject to this standard 12 months after the acquisition date of
the transmission line(s).
The reliability objective of this NERC Vegetation Management Standard (“Standard”) is to
prevent vegetation-related outages which could lead to Cascading by effective vegetation
maintenance while recognizing that certain outages such as those due to vandalism, human errors
and acts of nature are not preventable. Operating experience clearly indicates that trees that have
grown out of specification could contribute to a cascading grid failure, especially under heavy
electrical loading conditions.
Serious outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations. To
properly reduce and manage this risk, it is necessary to apply the Standard to applicable lines on
any kind of land or easement, whether they are Federal Lands, state or provincial lands, public or
private lands, franchises, easements or lands owned in fee.
The Standard addresses vegetation management along applicable overhead lines that serve to
connect one electric station to another. However, it is not intended to be applied to lines sections
inside the electric station fence or other boundary of an electric station or underground lines.
The Standard is intended to reduce the risk of Cascading involving vegetation. It is not intended
to prevent customer outages from occurring due to tree contact with all transmission lines and
EPAct 2005 section 1211c: “Access approvals by Federal agencies”
FAC-003-2 Technical Reference
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NERC Standard FAC-003-2 Technical Reference
voltages. For example, localized customer service could be disrupted if vegetation were to make
contact with a 69kV transmission line supplying power to a 12kV distribution station. This
Standard is not written to address such isolated situations which have little impact on the overall
Bulk Electric System.
Vegetation growth is constant and always present. Unmanaged vegetation poses an increased
outage risk when numerous transmission lines are operating at or near their Rating as a result of
increased sags incurred. This poses a significant risk of multiple line failures and Cascading. On
the other hand, most other outage causes (such as trees falling into lines, lightning, animals,
motor vehicles, etc.) are statistically intermittent. The probability of occurrence of these events is
not dependent on heavy loads. There is no cause-effect relationship which creates the probability
of simultaneous occurrence of other such events. Therefore these type events are highly unlikely
to cause large-scale grid failures.
In preparing the original vegetation management standard in 2005, industry stakeholders set the
threshold for applicability of the standard at 200kV. This was because an unexpected loss of
lines operating at above 200kV has a higher probability of initiating a widespread blackout or
cascading outages compared with lines operating at less than 200kV.
The original NERC vegetation management standard also allowed for application of the standard
to “critical” circuits (critical from the perspective of initiating widespread blackouts or cascading
outages) operating below 200kV. While the percentage of these circuits is relatively low (at one
major U.S. utility, only 3% of its thousands of sub-200kV circuits are considered critical), it
remains a fact that there are sub-200kV circuits whose loss could contribute to a widespread
outage. Given the very limited exposure and unlikelihood of a major event related to these lowervoltage lines, it would be an imprudent use of resources to apply the Standard to all sub-200kV
lines. The drafting team selected, after evaluating several alternatives, the Reliability
Coordinator as the best entity to determine applicable lines below 200 kV that are subject to this
standard.
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NERC Standard FAC-003-2 Technical Reference
Transmission Vegetation Management Program
R1.
Each Transmission Owner shall have a documented transmission vegetation
management program designed to control vegetation on its Active Transmission
Lines’ Rights of Way. The transmission vegetation management program shall:
The purpose of the Standard is to prevent vegetation-related outages that can result in Cascading.
Under Requirement R1, each Transmission Owner is required to have a transmission vegetation
management program designed to control vegetation on the Active Transmission Line Right of
Way. The transmission vegetation management program is an important component of the
Standard because it is the formal document that Transmission Owners use to manage vegetation
to achieve the purpose of the Standard. An adequate transmission vegetation management
program formally establishes the guidelines that are used by the Transmission Owner to plan and
perform vegetation work that is necessary to prevent transmission outages and minimize risk to
the transmission system.
It should be noted that Requirement R1 is concerned with the content of the transmission
vegetation management program and supporting documents, but does not address
implementation of the elements of the transmission vegetation management program. Other
requirements address implementation of the transmission vegetation management program. For
example, sub-part 1.4 requires Transmission Owners to establish an imminent threat procedure.
However, sub-part 1.4 does not address implementation or execution of the imminent threat
procedure. This is addressed in Requirement R2. These situations will be reviewed in the
following discussion.
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NERC Standard FAC-003-2 Technical Reference
Methodology to Control Vegetation
R1.1.
Specify the methodologies that the Transmission Owner uses to control
vegetation 2
Transmission Owners are required to specify the methodologies or management methods used to
control vegetation on applicable lines in the transmission vegetation management program. The
methods specified in the transmission vegetation management program under this requirement
are the methods that will be applied to the development and implementation of the annual work
plan (R1.3 and R8).
The intent of this sub-part is for the Transmission Owner to list and generally describe the
vegetation management methods that are used on its Active Transmission Line Right of Way.
Transmission Owners are not required to deploy each of the methods listed in every situation.
Nor are they required to provide a detailed description of each method, although these may exist
in the Transmission Owner’s specifications. Instead, the methods listed under this requirement
are intended to provide a menu of vegetation management options that the Transmission Owner
may deploy when developing and implementing the annual work plan based upon the many
different circumstances that are typically encountered.
It should be emphasized that pruning is an ineffective maintenance method. Removal is always
superior to pruning in ensuring tree conflicts do not occur.
In general, the best management practice for the Transmission Owner is to always exercise its
maximum legal rights to achieve the objectives of the transmission vegetation management
program. This minimizes the possibility of conflicts between energized conductors and
vegetation. Since this is not always possible, the Transmission Owner’s strategy should be to
use its prescribed vegetation maintenance methods to work towards or achieve the maximum use
of the Active Transmission Line Right of Way.
The following are several examples of how methodologies could be specified in the transmission
vegetation management program under this requirement. These are offered as examples only and
it is recognized that numerous other methodologies could be included in the transmission
vegetation management program. It is also recognized that more detailed descriptions would
typically be included in the Transmission Owner’s internal specifications and procedures. The
“average” tree does not usually cause a Sustained Outage. It is above-average growth that creates
the greatest risk. In summary, methods must be applied in a sound biological manner
Mechanical Clearing — Remove all trees and brush in the Active Transmission Line Right of
Way. Cut or mow all stumps to 3 inches or less above grade. De-limb and windrow on the edge
of the right of way those larger trees that could be obstructive to other line maintenance
activities.
Selective Mechanical Tree Removal — Selectively remove with chain saws or mechanized
equipment all tall-growing species of trees, as listed in the specifications. Chemically treat the
stumps of re-sprouting trees with the herbicide mixtures identified in the specification within one
ANSI A300, Tree Care Operations — Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices,
while not a requirement of this standard, is considered to be an industry best practice.
FAC-003-2 Technical Reference
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NERC Standard FAC-003-2 Technical Reference
hour of making the cut. All low-growing species of shrubs and trees, as listed in the
specification, will be preserved unless otherwise noted.
Low-Volume Foliar Selective Herbicide Treatment — Selectively treat with herbicide all tallgrowing species of trees as listed in the specification which are less than ten feet in height, using
the low-volume foliar herbicide mixture and application process listed in the specification. All
low-growing species of shrubs and trees, as listed in the specification will be preserved unless
otherwise noted.
Side Pruning — Prune trees adjacent to the Active Transmission Line Right of Way that have
grown to an extent that they have encroached upon or will soon encroach upon the clearances
listed in the specification. In cases where specified clearances can not be achieved due to Active
Transmission Line Right of Way width restrictions, remove branches to prevent entry into the
Active Transmission Line Right of Way.
ANSI A300 – Best Management Practices for Tree Care Operations
Transmission Owners have the option of adopting the procedures and practices contained in an
industry-recognized ANSI Standard known as A300 for use as a central component of its
vegetation management program. The following is a description of A300.
Introduction
Integrated Vegetation Management (IVM) is a best management practice conveyed in the
American National Standard for Tree Care Operations, Part 7 (ANSI 2006) and the International
Society of Arboriculture’s Best Management Practices: Integrated Vegetation Management
(Miller 2007). IVM is consistent with the requirements in FAC-003-02, and it provides
practitioners with what industry experts consider to be the most appropriate techniques to apply
to electric right-of-way projects in order to exceed those requirements.
IVM is a system of managing plant communities whereby managers set objectives, identify
compatible and incompatible vegetation, consider action thresholds, and evaluate, select and
implement the most appropriate control method or methods to achieve set objectives. The choice
of control method or methods should be based on the environmental impact and anticipated
effectiveness, along with site characteristics, security, economics, current land use and other
factors.
Planning and Implementation
Best management practices provide a systematic way of planning and implementing a vegetation
management program. While designed primarily with transmission systems in mind, it is also
applicable to distribution projects. As presented in ANSI A300 part 7 and the ISA best
management practices, IVM consists of 6 elements:
1)
2)
3)
4)
Set Objectives
Evaluate the Site
Define Action Thresholds
Evaluate and Select Control Methods
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NERC Standard FAC-003-2 Technical Reference
5) Implement IVM
6) Monitor Treatment and Quality Assurance
The setting of objectives, defining action thresholds, and evaluating and selecting control
methods all require decisions. The planning and implementation process is cyclical and
continuous, because vegetation is dynamic and managers must have the flexibility to adjust their
plans. Adjustments may be made at each stage as new information becomes available and
circumstances evolve.
Set Objectives
Objectives should be clearly defined and documented. Examples of objectives can
include promoting safety, preventing outages caused by vegetation growing into electric
facilities and minimizing them from trees growing outside the right of way, maintaining
regulatory compliance, protecting structures and security, restoring electric service during
emergencies, maintaining access and clear lines of sight, protecting the environment, and
facilitating cost effectiveness.
Objectives should be based on site factors, such as workload and vegetation type, in
addition to human, equipment and financial resources. They will vary from utility to
utility and project to project, depending on line voltage and criticality, as well as
topographical, environmental, fiscal and political considerations. However, where it is
appropriate, the overriding focus should be on environmentally-sound, cost effective
control of species that potentially conflict with the electric facility, while promoting
compatible, early successional, sustainable plant communities.
Work Load Evaluations
Work-load evaluations are inventories of vegetation that could have a bearing on
management objectives. Work load assessments can capture a variety of vegetation
characteristics, such as location, height, species, size and condition, hazard status, density
and clearance from conductors. Assessments should be conducted considering voltage,
conductor sag from ambient temperatures and loading, and the potential influence of
wind on line sway.
Evaluations can be comprehensive or point sample, and can be done to obtain
information on an entire program or an individual project. Comprehensive evaluations
account for vegetation that could potentially affect management objectives, including
hazard trees. Program-level comprehensive evaluations can be made of all target
vegetation on a system, while project-level evaluations focus on vegetation relevant to a
specific job. Comprehensive evaluations provide the advantage of supplying a complete
set of data upon which to base management decisions. On the other hand, comprehensive
surveys can be impractical for utilities with large numbers of trees, limited human and
financial resources, or both.
Point sampling offers an alternative for utilities for which comprehensive inventories are
impractical. Point sampling is cost effective, and has a proven track record for
reasonable accuracy. A common method involves dividing a management area (a system
or project) into equal-sized units and selecting a random sample sufficient to statistically
FAC-003-2 Technical Reference
October 22, 2008
14
NERC Standard FAC-003-2 Technical Reference
represent the total work quantity. Random selection eliminates the chance of bias on the
part of the investigator. Every plant or plant community of interest within each selected
area is inventoried, with collected data used to forecast the total workload.
Evaluate and Select Control Methods
Control methods are the process through which managers achieve objectives. The most
suitable control method best achieves management objectives at a particular site. Many
cases call for a combination of methods. Managers have a variety of controls from which
to choose, including manual, mechanical, herbicide and tree growth regulators,
biological, and cultural options.
Manual Control Methods
Manual methods employ workers with hand-carried tools, including chainsaws,
handsaws, pruning shears and other devices to control incompatible vegetation. The
advantage of manual techniques is that they are selective and can be used where others
may not be. On the other hand, manual techniques can be inefficient and expensive
compared to other methods. If pruning is necessary, it should comply with ANSI A300
Part 1 (ANSI 2001) and ISA best management practices for utility pruning (Kempter
2004).
Mechanical Control Methods
Mechanical controls are done with machines. They are efficient and cost effective,
particularly for clearing dense vegetation during initial establishment, or reclaiming
neglected or overgrown right of way. On the other hand, mechanical control methods can
be non-selective and disturb sensitive sites.
Tree Growth Regulator and Herbicide Control Methods
Tree growth regulators and herbicides are essential for effective vegetation management.
Tree growth regulators (TGRs) are designed to reduce growth rates by interfering with
natural plant processes. TGRs can be helpful where removals are prohibited or
impractical by reducing the growth rates of some fast-growing species.
Herbicides control plants by interfering with specific botanical biochemical pathways.
Herbicide use can control individual plants that are prone to re-sprout or sucker after
removal. When trees that re-sprout or sucker are removed without herbicide treatment,
dense thickets develop, impeding access, swelling workloads, increasing costs, blocking
lines-of-site, and deteriorating wildlife habitat. Treating suckering plants allows early
successional, compatible species to dominate the right-of-way and out-compete
incompatible species, ultimately reducing work.
Cultural Control Methods
Cultural methods modify habitat to discourage incompatible vegetation and establish and
manage desirable, early successional plant communities. Cultural methods take
advantage of seed banks of native, compatible species lying dormant on site. In the long
run, cultural control is the most desirable method where it is applicable.
FAC-003-2 Technical Reference
October 22, 2008
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NERC Standard FAC-003-2 Technical Reference
A cultural control known as cover-type conversion provides a competitive advantage to
short-growing, early successional plants, allowing them to thrive and eventually outcompete unwanted tree species for sunlight, essential elements and water. The early
successional plant community is relatively stable, tree-resistant and reduces the amount
of work, including herbicide application, with each successive treatment.
Wire-Border Zone
The wire-border zone technique is a management philosophy that can be applied through
cultural control. W.C. Bramble and W.R. Byrnes developed it in the mid-1980s out of
research begun in 1952 on a transmission right-of-way in the Pennsylvania State Game
Lands 33 Research and Demonstration project (Yahner and Hutnik (2004).
The wire zone is the section of a utility transmission right-of-way directly under the wires
and extending outward about 10 feet on each side. The wire zone is managed to promote
a low-growing plant community dominated by grasses, herbs and small shrubs (under 3
feet in height at maturity). The border zone is the remainder of the right-of-way. It is
managed to establish small trees and tall shrubs (under 25 feet in height at maturity).
When properly managed, diverse, tree-resistant plant communities develop in wire and
border zones. The communities not only protect the electric facility and reduce long-term
maintenance, but also enhance wildlife habitat, forest ecology and aesthetic values.
Although the wire-border zone is a best practice in many instances, it is not necessarily
universally suitable. For example, standard wire-border zone prescriptions may be
unnecessary where lines are high off the ground, such as across low valleys or canyons,
so the technique can be modified without sacrificing reliability.
One way to accommodate variances in topography is to establish different regions based
on wire height. For example, over canyon bottoms or other areas where conductors are
100 feet or more above the ground, only a few trees are likely to be tall enough to conflict
with the lines. In those cases, trees that potentially interfere with the transmission lines
can be removed selectively on a case-by-case basis.
In areas where the wire is lower, perhaps between 50-100 feet from the ground, a border
zone community can be developed throughout the right-of-way. Note that in many cases,
conductor attachment points are more than 50 feet off the ground, so a border zone
community can be cultivated near structures. Where the line is less than 50 feet off the
ground, managers could apply a full wire-border zone prescription.
An environmental advantage of this type of modification is stream protection. Streams
often course through the valleys and canyons where lines are likely to be elevated.
Leaving timber or border zone communities in canyon bottoms helps shelter this valuable
habitat, enabling managers to achieve environmentally sensitive objectives.
Implement IVM
All laws and regulations governing IVM practices and specifications written by qualified
vegetation managers must be followed. Integrated vegetation management control
methods should be implemented on regular work schedules, which are based on
established objectives and completed assessments. Work should progress systematically,
using control measures determined to be best for varying conditions at specific locations
FAC-003-2 Technical Reference
October 22, 2008
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NERC Standard FAC-003-2 Technical Reference
along a right-of-way. Some considerations used in developing schedules include the
importance and type of line, vegetation clearances, work loads, growth rate of predominant
vegetation, geography, accessibility, and in some cases, time lapsed since the last scheduled
work.
Clearances Following Work
The Transmission Owner should establish and document appropriate minimum clearance
distances to be achieved at the time of work. Clearances following work should be
sufficient to meet management objectives, including reducing preventing trees from
entering the Critical Clearance Zone, electric safety risks, service-reliability threats and
cost.
Monitor Treatment and Quality Assurance
An effective program includes documented processes to evaluate results. Evaluations
can involve quality assurance while work is underway and after it is completed.
Monitoring for quality assurance should begin early to correct any possible
miscommunication or misunderstanding on the part of crewmembers. Early and
consistent observation and evaluation also provides an opportunity to modify the plan, if
need be, in time for a successful outcome.
Utility vegetation management programs should have systems and procedures in place
for documenting and verifying that vegetation management work was completed to
specifications. Post-control reviews can be comprehensive or based on a statistically
representative sample. This final review points back to the first step and the planning
process begins again.
Summary
Integrated vegetation management offers a systematic way of planning and implementing a
vegetation management program as presented in ANSI A300 Part 7. This methodology enables
a program to comply with the NERC Transmission Vegetation Management Program standard
(FAC-003-2). Managers should select control options to best promote management objectives.
Tree-resistant plant communities can be a desirable objective to reduce long-term work loads and
costs because, once established, they out-compete incompatible plants. When effectively
implemented, IVM is a systematic, preventive strategy that results in site-specific treatments to
meet management objectives. A sound program includes documented processes to evaluate
results, which should involve both monitoring for quality assurance while work is underway and
after it is completed. However, the overriding focus should be on environmentally-sound, cost
effective control of species that potentially conflict with the electric facility while promoting
compatible, early successional, sustainable plant communities where appropriate.
FAC-003-2 Technical Reference
October 22, 2008
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NERC Standard FAC-003-2 Technical Reference
Vegetation Inspection Frequency
R1.2.
Specify a vegetation inspection frequency of at least once per calendar year that
takes into account local 3 and environmental factors.
The transmission vegetation management program shall specify the frequency of
inspection. The inspection frequency shall be at least once per calendar year.
Transmission Owners should consider factors that could warrant more frequent
inspection including growth studies, the need to insure individual fast-growing trees have
not encroached into the Critical Clearance Zone, the need to identify excessive spring
growth, and the need to identify seasonally occurring hazard trees.
3
Local factors include treatment cycle, extent and type of treatment, and their relationship to the normal growth rate.
FAC-003-2 Technical Reference
October 22, 2008
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NERC Standard FAC-003-2 Technical Reference
Annual Plans
R1.3.
Require an annual plan that identifies the applicable lines to be maintained and
work to be performed during the year. It shall be flexible to adjust to changing
conditions and to findings from vegetation inspections. Adjustments to the plan
within the year are permissible. The plan shall take into consideration
permitting and scheduling requirements from landowners or regulatory
authorities. It shall support the objectives of the transmission vegetation
management program and use the methodologies outlined in the transmission
vegetation management program.
The work plan is not intended to be a “span-by-span” detailed description of all work to be
performed. It is intended to require the Transmission Owner to plan and schedule vegetation
work to avoid encroachment into the Critical Clearance Zone.
The reference in the standard to "implement the annual work plan for vegetation management to
accomplish the purpose of this standard within the extent of its easement and/or legal rights" is
intended to address the importance of maintaining all locations on the Active Transmission Line
Right of Way for reliability purposes in lieu of making special exceptions.
Property owners and other interested parties occasionally request special considerations
to leave undesirable vegetation conditions. It is recognized that such considerations must
never be allowed to impact reliability.
These undesirable vegetation conditions require more frequent work or inspections than
other locations with similar vegetation threats and similar easement rights which are not
subject to the special property requests
The Transmission Owner's vegetation maintenance work necessary to implement the
annual work plan is most effective when performed to the maximum extent allowed by
any legal and/or easement rights.
The Transmission Owner should, therefore, endeavor to maintain its Active Transmission
Line Right of Way to the full extent of its legal rights at all times and in all cases.
This approach is superior to incremental management over the long term because it reduces
overall encroachments, and it ensures that future planned work and future planned inspection
cycles are sufficient at all locations on the Active Transmission Line Right of Way .
FAC-003-2 Technical Reference
October 22, 2008
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NERC Standard FAC-003-2 Technical Reference
Imminent Threat Procedure
R1.4. Require a process or procedure for response to imminent threats of a vegetation
related Sustained Outage. The process or procedure shall specify actions which
shall include immediate communication of the threat to the Transmission
Operator, and may include actions such as a temporary reduction in line Rating,
switching lines out of service, or other actions.
The term “imminent threat” refers to a vegetation condition which is placing the transmission
line at a significant risk of a Sustained Outage.
Examples of imminent threats may include vegetation that is rapidly approaching or has
encroached within the Critical Clearance Zone or a tall tree which has been uprooted and is
leaning precariously toward transmission conductors which could draw an arc when the tree
falls. Both cases represent imminent threats due to the high probability that they could cause a
Sustained Outage.
Two key elements of an acceptable imminent threat procedure are outlined below:
Upon discovery of an imminent threat, the operating authority (operating authority refers
to personnel with direct responsibility for operating the transmission lines, including but
not limited to ordering the de-rating or de-energization of transmission lines) will be
notified of the condition so that action (such as temporary reduction in line Rating,
switching the line out of service, etc.) may be taken until the threat is relieved.
The protocol for contacting the operating authority should be defined. For example, some
Transmission Owners’ processes may require a call directly to the operating authority,
while other Transmission Owners may require a call to a supervisor or field forester. The
process should be explicit for the expectations of actions upon the individual discovering
the imminent threat.
The urgency of addressing imminent threats may be contrasted with the longer time frames of
corrective action plans which are developed from a corrective action process as defined in R1.5.
The communication of imminent threats should typically be done in a matter of minutes or hours,
whereas corrective action plans may require months or years (see requirement R1.5).
All serious conditions are not necessarily considered as imminent threats under the Standard. For
example, Transmission Owners may assign a high priority to the removal of trees that have been
designated for removal under a danger tree identification program, but not yet encroached within
the Critical Clearance Zone. These trees are not considered imminent threats under the Standard
because there is not a high probability that they will grow sufficiently before treatment to
encroach into the Critical Clearance Zone or immediately fall and subsequently cause a
Sustained Outage.
Some encroachments may be found within the Critical Clearance Zone at a time when there
exists sufficient safety clearance distance from the conductors to allow their safe removal. If so
their removal may not require switching the line out of service, de-rating the line temporarily or
other actions.
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October 22, 2008
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NERC Standard FAC-003-2 Technical Reference
Interim Corrective Action Process
R1.5. Specify an interim corrective action process for use when the Transmission
Owner is constrained from performing vegetation maintenance as planned.
Each Transmission Owner is required to specify an interim corrective action process in its
transmission vegetation management program. The purpose of this sub-part is to ensure that
Transmission Owners have in place a process to develop a corrective action plan that identifies
and mitigates risk to the reliability of transmission lines when the Transmission Owner is
constrained from performing vegetation maintenance work as planned.
Constraints to performing vegetation maintenance work as planned could result from legal
injunctions filed by property owners, the discovery of easement stipulations which limit the
Transmission Owner’s rights, or other circumstances. The Standard recognizes that numerous
circumstances resulting in work constraints can occur, and that numerous ways to identify and
mitigate the associated risks to line reliability can be developed. Thus, the requirement is such
that the Transmission Owner must specify a general, flexible corrective action process which
provides a framework that can be applied over a wide range of situations to ensure line
reliability.
A general interim corrective action process may include the following steps:
Determine and understand the constraint
Determine the degree of risk to line reliability due to the constraint
Determine a specific interim corrective action plan to mitigate the risk
If applicable, determine the time frame for the corrective action plan to be in effect
FAC-003-2 Technical Reference
October 22, 2008
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NERC Standard FAC-003-2 Technical Reference
Implement Imminent Threat Procedure
R2.
Each Transmission Owner shall implement its imminent threat procedure when
the Transmission Owner has knowledge, obtained through normal operating
practices or notification from others, that the Critical Clearance Zone is
approached by vegetation to prevent an encroachment of the Critical Clearance
Zone.
Determining Clearance Distances for Vegetation near Transmission Lines
A vital component of an effective vegetation management program is maintaining an adequate
distance between energized transmission line conductors and vegetation. Maintaining a
minimum separation can prevent inadvertent Sustained Outages caused by direct contact of the
conductors and the vegetation or sparkover between the conductors and the vegetation.
The Gallet Equation is a well known method of computing the required strike distance for proper
insulation coordination, and has the ability to take into account various air gap geometries, as
well as non-standard atmospheric conditions. When the Gallet Equation and conservative
probabilistic methods are combined, i.e. deterministic design, sparkover probabilities of 10-6 or
less are achieved. This approach is well known for its conservatism and was used to design the
first 500 kV and 765 kV lines in North America [1]. Thus, the deterministic design approach
using the Gallet Equation is used for the standard to compute the minimum strike distance
between transmission lines and the vegetation that may be present in or along the transmission
corridor.
Method Explanation (Gallet Equation)
In 1975 G. Gallet published a benchmark paper that provided a method to compute the critical
flashover voltage (CFO) of various air gap geometries [4]. The Gallet Equation uses various
“gap factors” to take into account various air gap geometries. Various gap factor values are
provided in [1]. If the vegetation in a transmission corridor, e.g. a tree, is assumed electrically to
be a large structure then the CFO of such an air gap geometry can be computed for dry or wet
conditions using a well established equation proposed by Gallet [1],[2],[4],
CFOA k w k g m
3400
8
1
D
(1)
where,
kw
is defined as the factor that takes into account wet or dry conditions (dry = 1.0
and wet = 0.96) and phase arrangement (multiply by 1.08 for outside phase), e.g.
outside phase and wet conditions = (0.96)(1.08) = 1.037,
kg
is defined as the gap factor (1.3 for conductor to large structure),
FAC-003-2 Technical Reference
October 22, 2008
22
NERC Standard FAC-003-2 Technical Reference
D
is the strike distance (m),
CFO A
is the CFO for the relative air density (kV).
δ
is defined as the relative air density and is approximately equal to (2) where A is
the altitude in km,
e
A
8.6
(2)
m 1.25G0 G0 0.2
(3)
CFOs
500 D
(4)
G0
CFOs k w k g
3400
8
1
D
(5)
where CFO S is the CFO for standard atmospheric conditions (kV). Using (1)-(5), the required CFO A can
be computed using an iterative process.
Once the CFO A is known, deterministic methods can be used to determine the required clearance
distance. If we let the maximum switching overvoltage be equal to the withstand voltage of the
air gap (CFO A - 3) then the CFO A can be written as (6).
Vm
1 3
CFOA
CFOA
(6)
where
V m is equal to the maximum switching overvoltage, i.e. the value that has a 0.135% chance of being
exceeded,
is the standard deviation of the air gap insulation,
CFO A is the critical flashover voltage of the air gap insulation under non-standard atmospheric conditions.
The ratio of to the CFO A given in (6) can be assumed to be 0.05 (5%) [1]. Thus, (6) can be
written as (7).
CFOA
Vm
0.85
(7)
Substituting (7) into (1) we arrive at (8).
Vm 0.85 kw k g m
FAC-003-2 Technical Reference
October 22, 2008
3400
8
1
D
(8)
23
NERC Standard FAC-003-2 Technical Reference
Equation 8 relates the maximum transient overvoltage, V m , to the air gap distance, D. Using (8)
to compute the required clearance distance for the specified air gap geometry (conductor to large
structure) results in a probability of flashover in the range of 10-6.
TRANSIENT OVERVOLTAGE
In general, the worst case transient overvoltages occurring on a transmission line are caused by
energizing or re-energizing the line with the latter being the extreme case if trapped charge is
present. The intent of FAC-003 is to keep a transmission line that is in service from becoming
de-energized (i.e. tripped out) due to sparkover from the line conductor to nearby vegetation.
Thus, the worst case scenarios that are typically analyzed for insulation coordination purposes
(e.g. line energization and re-energization) can be ignored. For the purposes of FAC-003-2, the
worst case transient overvoltage then becomes the maximum value that can occur with the line
energized. Determining a realistic value of transient overvoltage for this situation is difficult
because the maximum transient overvoltage factors listed in the literature are based on a
switching operation of the line in question. In other words, these maximum overvoltage values
(e.g. the values listed in [2], [3] and [5]) are based on the assumption that the subject line is being
energized, re-energized or de-energized. These operations, by their very nature, will create the
largest transient overvoltages. Typical values of transient overvoltages of in-service lines, as
such, are not readily available in the literature because the resulting level of overvoltage is
negligible compared with the maximum (e.g. re-energizing a transmission line with trapped
charge). A conservative value for the maximum transient overvoltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 p.u.[2]. This value is a
conservative estimate of the transient overvoltage that is created at the point of application (e.g. a
substation) by switching a capacitor bank without a pre-insertion device (e.g. closing resistors).
At voltage levels where capacitor banks are not very common (e.g. 362 kV), the maximum
transient overvoltage of an “in-service” ac line are created by fault initiation on adjacent ac lines
and shunt reactor bank switching. These transient voltages are usually 1.5 p.u. or less [2]. It is
well known that these theoretical transient overvoltages will not be experienced at locations
remote from the bus at which they were created; however, in order to be conservative, it will be
assumed that all nearby ac lines are subjected to this same level of overvoltage. Thus, a
maximum transient overvoltage factor of 2.0 p.u. for 242 kV and below and 1.4 p.u. for ac
transmission lines 362 kV and above is used to compute the required clearance distances for
vegetation management purposes.
The overvoltage characteristics of dc transmission lines vary somewhat from their ac
counterparts. The referenced empirically derived transient overvoltage factor used to calculate
the minimum clearance distances from dc transmission lines to vegetation for the purpose of
FAC-003-2 will be 1.8 p.u.[3].
EXAMPLE CALCULATION
An example calculation is presented below using the proposed method of computing the
vegetation clearance distances. It is assumed that the line in question has a maximum operating
voltage of 550 kV rms line-to-line. Using a per unit transient overvoltage factor of 1.4, the result
is a peak transient voltage of 629 kV crest . It is further assumed that the line in question operates
at a maximum altitude of 7000 feet (2.134 km) above sea level.
FAC-003-2 Technical Reference
October 22, 2008
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NERC Standard FAC-003-2 Technical Reference
The required withstand voltage of the air gap must be equal to or greater than 629 kV crest . Since
the altitude is above sea level, (1) - (5) have to be iterated on to achieve the desired result.
Equation (9) can be used as an initial guess for the clearance distance.
8
3400 k w k g
Di
Vm
0.85
(9)
1
For our case here, V m is equal to 629 kV, k w = 1.037 and k g = 1.3. Thus,
Di
8
3400 k w k g
Vm
0.85
1
(10)
8
1.535m
3400 1.037 1.3
1
629
0.85
Using (2)-(5) and (8) the withstand voltage of the air gap is next computed. This value will then
be compared to the maximum transient overvoltage.
CFO S k w k g
e
GO
3400
3400
1 .037 1 .3
737 .7 kV
8
8
1
1
D
1 .535
A
8.6
e
2.134
8.6
0.78
(12)
CFO S
737 .7
0.961
500 D 500 1 .535
(13)
m 1.25 G O G O 0.2 1.25 0.9610.961 0.2 0.915
V m 0 . 85 k w k g
m
3400
3400
0 .915
0 . 85 1 .037 1 . 3 0 .78
8
1 8
1
D
1 . 535
(11)
(14)
499 . 8 kV
(15)
The calculated V m is less than 629 kV; thus, the clearance distance must be increased. A few
iterations using (2)-(5) and (8) are required until the computed V m 629 kV. For this case it was
found that D = 1.978 m (6.49 feet) yielded V m = 629.3 kV. Using this clearance distance the
following values were computed for the final iteration.
CFO
S
kw kg
e
FAC-003-2 Technical Reference
October 22, 2008
3400
3400
1 . 037 1 . 3
908 . 5 kV
8
8
1
1
D
1 . 978
A
8.6
e
2.134
8.6
0.78
(16)
(17)
25
NERC Standard FAC-003-2 Technical Reference
GO
CFOS
908.5
0.919
500 D 500 1.978
(18)
m 1.25 G O G O 0.2 1.25 0.919 0.919 0.2 0.825
V m 0 . 85 k w k g
m
(19)
3400
3400
0 . 825
0 . 85 1 . 037 1 . 3 0 . 78
8
8
1
1
1 .978
D
629 . 3 kV
(20)
Therefore, the minimum vegetation clearance distance for a maximum line to line ac operating
voltage of 550 kV at 7000 feet above sea level is 1.978 m (6.49 feet). Table I provides
calculated distances for various altitudes and maximum system operating ac voltages.
TABLE I — Minimum Vegetation Clearance Distances
For Alternating Current Voltages
( AC )
Nominal
System
Voltage
(kV)
( AC )
Maximum
System
Voltage
(kV)
765
800
500
550
345
362
230
242
161*
169
138*
145
115*
121
88*
100
69*
72
D feet
(meters)
sea level
8.06ft
(2.46m)
5.06ft
(1.54m)
3.12ft
(0.95m)
2.97ft
(0.91m)
2ft
(0.61m)
1.7ft
(0.52m)
1.41ft
(0.43m)
1.15ft
(0.35m)
0.82ft
(0.25m)
D feet
(meters)
3,000ft
(914.4m)
8.89ft
(2.71m)
5.66ft
(1.73m)
3.53ft
(1.08m)
3.36ft
(1.02m)
2.28ft
(0.69m)
1.94ft
(0.59m)
1.61ft
(0.49m)
1.32ft
(0.40m)
0.94ft
(0.29m)
D feet
(meters)
4,000ft
(1219.2m)
9.17ft
(2.80m)
5.86ft
(1.79m)
3.67ft
(1.12m)
3.49ft
(1.06m)
2.38ft
(0.73m)
2.03ft
(0.62m)
1.68ft
(0.51m)
1.38ft
(0.42m)
0.99ft
(0.30m)
D feet
(meters)
5,000ft
(1524m)
9.45ft
(2.88m)
6.07ft
(1.85m)
3.82ft
(1.16m)
3.63ft
(1.11m)
2.48ft
(0.76m)
2.12ft
(0.65m)
1.75ft
(0.53m)
1.44ft
(0.44m)
1.03ft
(0.31m)
D feet
(meters)
6,000ft
(1828.8m)
9.73ft
(2.97m)
6.28ft
(1.91m)
3.97ft
(1.21m)
3.78ft
(1.15m)
2.58ft
(0.79m)
2.21ft
(0.67m)
1.83ft
(0.56m)
1.5ft
(0.46m)
1.08ft
(0.33m)
*As designated by the Reliability Coordinator
FAC-003-2 Technical Reference
October 22, 2008
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NERC Standard FAC-003-2 Technical Reference
TABLE I — Minimum Vegetation Clearance Distances (D)
For Alternating Current Voltages
( AC )
Nominal
System
Voltage
(kV)
( AC )
Maximum
System
Voltage
(kV)
765
800
500
550
345
362
230
242
161*
169
138*
145
115*
121
88*
100
69*
72
D feet
(meters)
7,000ft
(2133.6m)
10.01ft
(3.05m)
6.49ft
(1.98m)
4.12ft
(1.26m)
3.92ft
(1.19m)
2.69ft
(0.82m)
2.3ft
(0.70m)
1.91ft
(0.58m)
1.57ft
(0.48m)
1.13ft
(0.34m)
D feet
(meters)
8,000ft
(2438.4m)
10.29ft
(3.14m)
6.7ft
(2.04m)
4.27ft
(1.30m)
4.07ft
(1.24m)
2.8ft
(0.85m)
2.4ft
(0.73m)
1.99ft
(0.61m)
1.64ft
(0.50m)
1.18ft
(0.36m)
D feet
(meters)
9,000ft
(2743.2m)
10.57ft
(3.22m)
6.92ft
(2.11m)
4.43ft
(1.35m)
4.22ft
(1.29m)
2.91ft
(0.89m)
2.49ft
(0.76m)
2.07ft
(0.63m)
1.71ft
(0.52m)
1.23ft
(0.37m)
D feet
(meters)
10,000ft
(3048m)
10.85ft
(3.31m)
7.13ft
(2.17m)
4.58ft
(1.40m)
4.37ft
(1.33m)
3.03ft
(0.92m)
2.59ft
(0.79m)
2.16ft
(0.66m)
1.78ft
(0.54m)
1.28ft
(0.39m)
D feet
(meters)
11,000ft
(3352.8m)
11.13ft
(3.39m)
7.35ft
(2.24m)
4.74ft
(1.44m)
4.53ft
(1.38m)
3.14ft
(0.96m)
2.7ft
(0.82m)
2.25ft
(0.69m)
1.86ft
(0.57m)
1.34ft
(0.41m)
*As designated by the Reliability Coordinator
FAC-003-2 Technical Reference
October 22, 2008
27
NERC Standard FAC-003-2 Technical Reference
Likewise, a minimum clearance distance table for high voltage direct current lines may be
derived using alternating current methods [7]. Table I is expanded below to provide calculated
distances for various altitudes and system operating voltages.
TABLE I — Minimum Vegetation Clearance Distances (D)
For Direct Current Voltages
sea level
D feet
(meters)
3,000ft
(914.4m) Alt.
D feet
(meters)
4,000ft
(1219.2m)
Alt.
D feet
(meters)
5,000ft
(1524m)
Alt.
D feet
(meters)
6,000ft
(1828.8m)
Alt.
500
13.92ft
(4.24m)
10.07ft
(3.07m)
7.89ft
(2.40m)
4.78ft
(1.46m)
3.43ft
(1.05m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
5.35ft
(1.63m)
4.02ft
(1.23m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
5.55ft
(1.69m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
5.75ft
(1.75m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
5.95ft
(1.81m)
4.34ft
(1.32m)
Pole to Pole
Nominal
Voltage
(kV)
D feet
(meters)
7,000ft
(2133.6m)
Alt.
D feet
(meters)
(8,000ft
(2438.4m)
Alt.
D feet
(meters)
9,000ft
(2743.2m)
Alt.
D feet
(meters)
10,000ft
(3048m)
Alt.
D feet
(meters)
11,000ft
(3352.8m)
Alt.
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
6.15ft
(1.87m)
4.5ft
(1.37m)
16.9ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
6.36ft
(1.94m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
6.57ft
(2.00m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
6.77ft
(2.06m)
5ft
(1.52m)
17.97ft
(5.48m)
(13.54ft
4.13m)
10.92ft
(3.33m)
6.98ft
(2.13m)
5.17ft
(1.58m)
( DC )
Pole to Pole
Nominal
Voltage
(kV)
1500
1200
1000
800
1500
1200
1000
800
500
D feet
(meters)
FAC-003-2 Technical Reference
October 22, 2008
28
NERC Standard FAC-003-2 Technical Reference
Critical Clearance Zone
The best management practice for the Transmission Owner is to always exercise its maximum
legal rights with regards to Active Transmission Line Right of Way vegetation clearing work.
Doing so minimizes the possibility of incurring any conflicts between energized conductors and
vegetation. Since this is not always possible, Table I in FAC-003-2 identifies the minimum
radial distances, derived using the Gallet equations, which are required to prevent a flashover
(sparkover) at the corresponding line voltage ratings.
The minimum radial distance values in Table I represent a radial zone (or shell) around a
conductor within which there is a high probability that a flashover event will occur. However,
the minimum radial distance concept should not be mistaken to suggest that a static condition is
being managed; in fact, the reality is a very dynamic situation. The use of the Critical Clearance
Zone concept as set forth by the Standard attempts to simplify and address this complex dynamic
management requirement to aid in field applications.
The conductor’s position in space at any point in time is continuously changing as a reaction to a
number of different loading variables affecting the conductor’s movement within each line span.
Changes in vertical and horizontal conductor positioning are the result of thermal and physical
loads applied to the line. Thermal loading is a function of line current and the combination of
numerous variables influencing ambient heat dissipation including wind velocity/direction,
ambient air temperature and precipitation. Physical loading applied to the conductor affects sag
and swing by combining physical factors such as ice and wind loading.
As a consequence of these loading variables, the conductor’s position in space is dynamic and
continuously moving. Over some period of time, the conductor will ultimately pass through all
possible positions it can occupy in space. This full range of positions can be thought of as the
conductor’s “flight path”.
As the conductor moves throughout its flight path, the minimum clearance shell surrounding the
conductor obviously moves with it. Therefore, this shell also maps out an area in space called
the “Critical Clearance Zone”. Any conductive item (such as a tree) that has encroached within
this Critical Clearance Zone has the potential to cause flashover when the conductor enters a
corresponding location in its flight path.
The shape and size of the Critical Clearance Zone around the conductor is irregular and will
change depending on where a conductor segment is located within the span. At mid-span, where
the potential for conductor movement is the greatest due to sag and wind deflection, the
corresponding Critical Clearance Zone is also the largest and most irregular. Conversely, the
Critical Clearance Zone is at its smallest near the conductor attachment to the transmission line
structure insulator assembly. In the most extreme case, the Critical Clearance Zone again
becomes a simple radial circle at a rigidly fixed insulator attachment point such as with a Vstring or standoff insulator type of installation. Figures 4 through 7 below demonstrate these
concepts.
With the size, shape and area of the Critical Clearance Zone dramatically changing as one
progresses along a span, identifying the precise location and boundary of the Critical Clearance
Zone around the conductor in the field becomes very problematic. First, all the variables
involved make it very complicated and difficult to calculate the exact shape and size of the
Critical Clearance Zone at any particular location in any one, and ultimately all, of the many
spans of a transmission line. Second, at the time of field measurement, it is very difficult to
precisely know where the conductor is within its wide range of all possible flight path positions.
FAC-003-2 Technical Reference
October 22, 2008
29
NERC Standard FAC-003-2 Technical Reference
Therefore, even if the exact size and shape of the Critical Clearance Zone is known, it becomes
nearly impossible to field correlate and accurately “superimpose” the Critical Clearance Zone
around the conductor.
There are also operational adjustments that must be made to the Critical Clearance Zone as well
when managing vegetation. When transmission lines are initially designed, basic engineering
assumptions and calculations are made with regard to the maximum environmental and physical
forces to which the facility will be exposed as well as anticipated electrical loads. Again, these
assumptions include the consideration of things like the maximum wind and ice loading, thermal
heating and dissipation, span lengths, conductor strength, associated stringing and sagging
conditions, etc. All of these design considerations are combined to define the anticipated “design
flight path” for the conductor within each span. However, transmission facilities are not always
available to be operated at their full Rating for numerous reasons. For example, transmission
facilities can sometimes be built to a higher design voltage than they are currently operated at to
reserve capacity that will be utilized with other future system upgrades. Consequently in cases
such as these that do not subject a facility to its maximum design capacity, the “operational flight
path” of the conductor can be anticipated to be somewhat smaller than the full range of the
“designed flight path”. Subsequent decisions regarding vegetation management, therefore, need
only be made with regard to ensuring the integrity of the actual anticipated operational flight
path for the conductor.
Given all of the complicated considerations outlined above, vegetation management around near
the Critical Clearance Zone can be very challenging. It is important that the full conductor flight
path, within the appropriate limits defined by the lesser of the design parameters or the
operational constraints for the line, be available at all times to accommodate the full range of
power system operational requirements. Even with the best planning and execution of the
vegetation management program, including the use of frequent inspections, vegetation can still
unintentionally approach or even encroach into the Critical Clearance Zone without a
Transmission Owner’s immediate awareness. Such an event does not always result in a
flashover if the conductor is not simultaneously occupying that same area of the Critical
Clearance Zone. An example of this would be when the conductor is not currently being blown
to the extreme edge of its designed flight path from a maximum anticipated wind loading event.
However, in such a case it is imperative - and required by the Standard - that the Transmission
Owner’s Imminent Threat process be implemented immediately upon discovery to correct the
approaching or encroaching situation. Failure to do so is a violation of Requirement R2 of the
standard.
An accurate representation of the Critical Clearance Zone in the field, correctly positioned
around the conductor, is critically important if the Critical Clearance Zone is to be used as an
essential parameter for vegetation management and Standards regulation. Because of all of the
variables and difficulties in determining the Critical Clearance Zone, as well as the consequences
associated with Requirement R4 for failure to maintain Critical Clearance Zone clearances, it is
anticipated and expected that Transmission Owners will manage vegetation at distances greater
than the Critical Clearance Zone. Given the variation of the Critical Clearance Zone’s size and
shape at various locations along the line span, it is anticipated that many Transmission Owners
will establish a work trigger well outside the Critical Clearance Zone.
Further, to ensure adequate field monitoring and detection of incompatible vegetation conditions,
Standard FAC 003-2 requires inspections on a frequency that is appropriate to verify and ensure
there are no undiscovered Critical Clearance Zone approaches or encroachments. The
FAC-003-2 Technical Reference
October 22, 2008
30
NERC Standard FAC-003-2 Technical Reference
anticipated growth rates of the vegetation surveyed in relationship to its speed of approach and
distance from the Critical Clearance Zone is a very important consideration during inspection.
At a minimum, the inspection frequency can not be less than once per year.
Figure 4
Figure 5
FAC-003-2 Technical Reference
October 22, 2008
31
NERC Standard FAC-003-2 Technical Reference
Figure 6
Figure 7
FAC-003-2 Technical Reference
October 22, 2008
32
NERC Standard FAC-003-2 Technical Reference
Conduct Vegetation Inspections
R3.
Each Transmission Owner shall conduct inspections of all applicable lines in
accordance with the frequency specified in its transmission vegetation
management program.
The Requirement is self explanatory and no additional information is necessary.
FAC-003-2 Technical Reference
October 22, 2008
33
NERC Standard FAC-003-2 Technical Reference
Encroachments within Critical Clearance Zone
R4. Each Transmission Owner shall prevent encroachments within the Critical Clearance
Zone of its applicable transmission lines with the following exceptions:
1. Encroachments of the Critical Clearance Zone that result from natural disasters 4
2. Encroachments of the Critical Clearance Zone that result from human or animal
activity 5
The presence of vegetation in the Critical Clearance Zone presents a state of reduced
transmission system reliability and is a violation of Requirement R4. A Critical Clearance Zone
encroachment incident is defined as the presence in the Critical Clearance Zone of vegetation
from a single tree, or a group of trees or vegetation in a single span or adjacent spans. The
exposure to Critical Clearance Zone encroachment incidents varies widely among transmission
systems owned by large and small Transmission Owners.
4
Examples include, but are not limited to, earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale,
major storms as defined either by the Transmission Owner or an applicable regulatory body, ice storms, and floods.
5
Examples include, but are not limited to, logging, animal severing tree, vehicle contact with tree, arboricultural
activities or horticultural or agricultural activities, or removal or digging of vegetation.
FAC-003-2 Technical Reference
October 22, 2008
34
NERC Standard FAC-003-2 Technical Reference
Sustained Outages— Vegetation Growth
R5.
Each Transmission Owner shall prevent Sustained Outages of applicable lines 6
due to vegetation growing into a conductor operating between no load and its
Rating with the following exceptions:
1. Sustained Outages of applicable lines that result from natural disasters.
2. Sustained Outages of applicable lines that result from human or animal
activity.
The most significant vegetation related reliability risk to the transmission system involves
Sustained Outages due to vegetation growing into transmission lines. This is commonly referred
to as a grow-in or sag-in. These events could lead to widespread cascading failures, such as the
August 10, 1996 West Coast Blackout and the August 14, 2003 US-Canada blackout.
These blackouts occurred during the summer months when the transmission system is more
vulnerable to cascading events which can lead to blackouts. A review of NERC disturbance
reports related to blackouts indicates that most major blackouts attributed to vegetation were
caused by grow-in or sag-in events during the summer.
Since grow-in events have historically resulted in several major blackouts the standard
recognizes that they present a high risk to the system. Sustained Outages due to sag-ins that
occur due to natural disasters are beyond the control of the Transmission Owner. In addition it is
often not possible in the aftermath of a natural disaster to do the forensics to determine what
happened. Therefore such outages are not considered violations of this requirement.
Sustained Outages due to sag-ins that occur due to human (such as new plantings of tall
vegetation, automobile collisions into towers) or animal activity are beyond the control of the
Transmission Owner. Therefore such Sustained Outages are not considered violations of this
requirement.
The standard recognizes that multiple Sustained Outages on an individual line can be caused by
the same vegetation. As such, the Standard recognizes these events as a single Sustained Outage.
For example a Sustained Outage could be caused by a tree but be mistakenly attributed to
something else (e.g. contaminated insulator string or a different tree). After that situation is
addressed the line would be re-energized and would suffer another Sustained Outage from
contact with the tree.
Investigations are often hampered by weather conditions, darkness and/or other factors that lead
to a misdiagnosis of the cause of the fault as noted in the above example.
6
Multiple Sustained Outages on an individual line, if caused by the same vegetation, shall be considered as one
outage regardless of the actual number of outages within a 24-hour period.
FAC-003-2 Technical Reference
October 22, 2008
35
NERC Standard FAC-003-2 Technical Reference
Sustained Outages— Blowing Vegetation
R6. Each Transmission Owner shall prevent Sustained Outages of applicable lines6 due to
the blowing together of vegetation and a conductor with Active Transmission Line
Right of Way (operating within design blow-out conditions) with the following
exception:
1. Sustained Outages of applicable lines that result from sustained winds or gusts
due to natural 4
4
Unlike grow-ins which are addressed in Requirement R5, a review of NERC disturbance reports
related to blackouts indicates major blackouts were rarely if ever attributed to vegetation-related
Sustained Outages due to blowing together of vegetation and transmission conductors. These
events are known as blow-ins.
The standard recognizes that multiple Sustained Outages on an individual line can be caused by
the same vegetation. As such, the Standard considers these multiple events caused by the same
vegetation as a single Sustained Outage.
FAC-003-2 Technical Reference
October 22, 2008
36
NERC Standard FAC-003-2 Technical Reference
Sustained Outages— Falling Vegetation
R7.
Each Transmission Owner shall prevent Sustained Outages of applicable lines6
due to vegetation falling into a conductor from within an Active Transmission
Line Right of Way with the following exceptions:
1. Sustained Outages of applicable lines that result from natural disasters.4
2. Sustained Outages of applicable lines that result from human or animal
activity.5
Unlike grow-ins which are addressed in Requirement R5, a review of NERC disturbance reports
related to blackouts indicates major blackouts were rarely if ever attributed to vegetation-related
Sustained Outages due to vegetation falling into transmission lines. These events are known as
fall-ins.
Sustained Outages due to fall-ins resulting from natural disasters are beyond the control of the
Transmission Owner. In addition, it is often not possible in the aftermath of a natural disaster to
perform the forensics necessary to determine what happened. Therefore, such Sustained Outages
are not considered violations of this requirement.
Sustained Outages due to fall-ins that occur due to human or animal activity are beyond the
control of the Transmission Owner. Therefore, such Sustained Outages are not considered
violations of this requirement.
The Standard recognizes that multiple Sustained Outages on an individual line can be caused by
the same vegetation. As such, the Standard recognizes these events as a single Sustained Outage.
FAC-003-2 Technical Reference
October 22, 2008
37
NERC Standard FAC-003-2 Technical Reference
Implement Annual Work Plan
R8.
Each Transmission Owner shall implement its annual work plan for vegetation
management to accomplish the purpose of this standard within the extent of its
easement and/or legal rights.
This standard requires that the Transmission Owner implement the annual work plan and
document this implementation. The annual work plan should allow sufficient time for
reasonable procedural requirements to permit work on federal, state, provincial, public, tribal
lands, such as permits for National Forest, Department of Transportation work, etc.
This Standard requires that the annual work plan be flexible to allow the Transmission Owner to
change priorities during the year as conditions or situations dictate. For example, weather
conditions (drought) could make herbicide application ineffective during the plan year. Another
situational variance could be a major storm that redirects local resources away from planned
maintenance. This situation may also include complying with mutual assistance agreements by
moving resources off the Transmission Owner’s system to work on another system. Examples of
documented adjustments may include deferrals or additions to the annual work plan.
A measure for how this requirement was met may include documentation or other evidence of
the work performed. Documentation may consist of signed-off work orders, signed contracts,
printouts from work management systems, spreadsheets of planned versus completed work,
timesheets, QA work form, paid invoices, etc. to verify that the work has been completed. In
addition, documentation of planned work that was deferred or not completed is needed.
Documentation of deferred or incomplete work may include the reasons that the planned work
was not completed. Where specific work on a line or lines was postponed, the expected
completion date of the work may be included, if known. Other evidence may include
photographs, inspection reports, walk-throughs, etc.
FAC-003-2 Technical Reference
October 22, 2008
38
NERC Standard FAC-003-2 Technical Reference
Designating Sub-200kV Lines
R9.
Each Reliability Coordinator in consultation with its Transmission Owner(s) and
neighboring Reliability Coordinator(s) shall jointly prepare and keep current, a
list of designated applicable lines that are operated below 200kV, if any, which
are subject to this standard.
Requirement R9 assigns to the Reliability Coordinator the task of designating sub-200kV lines
that are subject to this standard. It can be seen that this Standard has departed from use of the
term “critical” and replaced it with criteria that are more descriptive of the large disturbances this
Standard intends to prevent.
The Standard places the responsibility on the Reliability Coordinator for the identification of
specific sub-200kV circuits to which the Standard is to be applied. Identification of such sub200kV circuits is to be done in consultation with the Reliability Coordinator’s Transmission
Owners and neighboring Reliability Coordinators.
Reliability Coordinators can offer documentation that they have consulted with their
Transmission Owners and neighboring Reliability Coordinators and that they have kept current a
list of designated sub-200kV transmission lines that are subject to the Standard. Documentation
may include letters, e-mails, spreadsheets, etc.
FAC-003-2 Technical Reference
October 22, 2008
39
NERC Standard FAC-003-2 Technical Reference
Documenting Method of Identifying Sub-200kV Lines
R10.
Each Reliability Coordinator shall document its method for assessing the
reliability significance of sub-200kV lines considering all of the following:
R10.1 Transmission lines whose loss would result in the exceedance of an
Interconnection Reliability Operating Limit (IROL)
R10.2 Transmission lines whose loss would place the grid at an unacceptable
risk of instability, separation, or cascading failures.
Requirement R10 assigns to the Reliability Coordinator the task of documenting its methods for
assessing the reliability significance of sub-200kV lines.
FAC-003-2 Technical Reference
October 22, 2008
40
NERC Standard FAC-003-2 Technical Reference
List of Acronyms and Abbreviations
ANSI
American National Standards Institute
IEEE
Institute of Electrical and Electronics Engineers
IVM
Integrated Vegetation Management
NERC
North American Electric Reliability Corporation
FAC-003-2 Technical Reference
October 22, 2008
41
NERC Standard FAC-003-2 Technical Reference
References
[1] Andrew Hileman, Insulation Coordination for Power System, Marcel Dekker, New York,
NY 1999
[2] EPRI, EPRI Transmission Line Reference Book 345 kV and Above, Electric Power Research
Council, Palo Alto, Ca. 1975.
[3] IEEE Std. 516-2003 IEEE Guide for Maintenance Methods on Energized Power Lines
[4] G. Gallet, G. Leroy, R. Lacey, I. Kromer, General Expression for Positive Switching
Impulse Strength Valid Up to Extra Long Air Gaps, IEEE Transactions on Power Apparatus
and Systems, Vol. pAS-94, No. 6, Nov./Dec. 1975.
[5] IEEE Std. 1313.2-1999 (R2005) IEEE Guide for the Application of Insulation Coordination.
[6] 2007 National Electric Safety Code
[7] EPRI, HVDC Transmission Line Reference Book, EPRI TR-102764 , Project 2472-03, Final
Report, September 1993
[8] ANSI. 2001. American National Standard for Tree Care Operations – Tree, Shrub, and
Other Plant Maintenance – Standard Practices (Pruning). Part 1. American National
Standards Institute, NY
[9] ANSI. 2006. American National Standard for Tree Care Operations – Tree, Shrub, and
Other Plant Maintenance – Standard Practices (Integrated Vegetation Management a.
Electric Utility Rights-of-way). Part 7. American National Standards Institute, NY.
[10] Cieslewicz, S. and R. Novembri. 2004. Utility Vegetation Management Final Report.
Federal Energy Regulatory Commission. Commissioned to support the Federal
Investigation of the August 14, 2003 Northeast Blackout. Federal Energy Regulatory
Commission, Washington, DC. pg. 39.
[11] Kempter, G.P. 2004. Best Management Practices: Utility Pruning of Trees.
International Society of Arboriculture, Champaign, IL
[12] Miller, R.H. 2007. Best Management Practices: Integrated Vegetation Management.
Society of Arboriculture, Champaign, IL.
[13] Yahner, R.H. and R.J. Hutnik. 2004. Integrated Vegetation Management on an electric
transmission right-of-way in Pennsylvania, U.S. Journal of Arboriculture. 30:295-300
FAC-003-2 Technical Reference
October 22, 2008
42
Standards Announcement
Comment Period Open
October 27–November 25, 2008
Now available at:
http://www.nerc.com/filez/standards/Vegetation-Management_Project_200707.html
First Draft of FAC-003-2 and Reference Document (Project 2007-07)
The Vegetation Management Standard Drafting Team (Project 2007-07) has posted its first draft
of standard FAC-003-2 — Transmission Vegetation Management Program and an associated
technical reference document for a 30-day comment period. The comment period is now open
until 8 p.m. on November 25, 2008.
The drafting team revised the vegetation management standard in accordance with the Standard
Authorization Request, which reflects comments from the FERC Order 693 and from
stakeholders as well as procedural updates. The compliance elements, which are also part of the
Standard Authorization Request, are not included in this initial posting. The drafting team has
prepared and posted a technical reference document to supplement the FAC-003-2 standard
along with a document comparing FAC-003-1 to FAC-003-2.
Please use this electronic form to submit comments. If you experience any difficulties in using
the electronic form, please contact Barbara Bogenrief at 609-452-8060.
The status, purpose, and supporting documents for this project — including an off-line,
unofficial copy of the questions listed in the comment form — are posted at the following site:
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Shaun Streeter,
Standards Program Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Individual or group. (66 Responses)
Name (43 Responses)
Organization (43 Responses)
Group Name (23 Responses)
Lead Contact (23 Responses)
Contact Organization (23 Responses)
Question 1 (62 Responses)
Question 1 Comments (66 Responses)
Question 2 (60 Responses)
Question 2 Comments (66 Responses)
Question 3 (61 Responses)
Question 3 Comments: (66 Responses)
Question 4 (59 Responses)
Question 4 Comments (66 Responses)
Question 5 (61 Responses)
Question 5 Comments (66 Responses)
Question 6 (58 Responses)
Question 6 Comments: (66 Responses)
Question 7 (59 Responses)
Question 7 Comments (66 Responses)
Question 8 (59 Responses)
Question 8 Comments (66 Responses)
Question 9 (59 Responses)
Question 9 Comments (66 Responses)
Question 10 (60 Responses)
Question 10 Comments (66 Responses)
Question 11 (58 Responses)
Question 11 Comments (66 Responses)
Question 12 (59 Responses)
Question 12 Comments (66 Responses)
Question 13 (56 Responses)
Question 13 Comments (66 Responses)
Question 14 (59 Responses)
Question 14 Comments (66 Responses)
Question 15 (60 Responses)
Question 15 Comments (66 Responses)
Question 16 (60 Responses)
Question 16 Comments (66 Responses)
Question 17 (58 Responses)
Question 17 Comments (66 Responses)
Question 18 Comments (66 Responses)
Individual
JAMES W. SMITH
ITC HOLDINGS
Disagree
ITC does not agree with the new purpose statement. The NERC Glossary of terms states that the BES
….generally operated at voltages of 100kV or higher and the Applicability in Section 4 clearly states
the standard is intended to apply to all line voltages of 200kV and above and those lines designated
by the Reliability Coordinator (4.2.1) as being subjected to this standard. Using the term Bulk Electric
System (BES) clearly sends a confusing message and should be eliminated. Thus the term of "electric
transmission system" is appropriate for the standard
Agree
ITC agrees that the Reliability Coordinator is the appropriate entity to identify and designate any sub
- 200kV lines deemed applicable to the standard with the concurrence of the Transmission Owner.
Agree
The standard doesn't actually explain or define the Active Transmission Line Right of Way.
Agree
Agree
Agree
Disagree
Agree & Disagree with the question: Agree with the need to have an Imminent Threat Procedure and
upon discovery of an IT, the Transmission Operations (TO) should be notified. We Disagree however,
with the requirement as written as its too prescriptive and is open to interpretation, from an audit
perspective, with use of the term “immediate†communication and a partial list of activities
that the TO may consider. Decisions on what specific system operating actions that could be taken
are beyond the responsibility of the vegetation management personnel. Disagree with the need to
implement the imminent threat procedure merely because a CCZ is being approached. It is possible
that the CCZ is being approached by vegetation at the lowest point of the CCZ where the conductor
may be at its highest point in the CCZ, (potentially 20 or 30 feet from vegetation) and wouldn’t
necessitate notification to the TO. Is there a desired distance from the CCZ where this procedure
must be implemented since all vegetation within a Right-of-Way will approach the CCZ as it grows?
R1.4 should be changed to “Require a process for response to vegetation related imminent threat
to applicable lines and not the CCZ
Agree
Agree
Agree
Disagree
Just because vegetation is approaching the CCZ doesn't represent an imminent threat and should not
be set to an imminent threat procedure. Implementation of R2 would require field personnel to
determine the speculative position of the line during inspections to decide whether to engage the
imminent threat procedures. While we agree that an imminent threat procedure should be
implemented to address vegetation related imminent threats as soon as they are identified, we
believe that an approach of the CCZ should not be used to generate implementation. The term
"approached" does not identify a specific distance, so it’s not clear to what extend vegetation
would have to approach the CCZ to require implementation of the imminent threat process. ITC
agrees that the implementation of an imminent threat procedure may be a valid concept, but
visualization of the CCZ and determining approaching vegetation is a practice in hypothetical
conductor locations in real time. This may be a good imaginary concept in understanding conductor
movement but it's impractical for field applications.
Agree
Agree
Agree
Disagree
First, it’s impossible to determine that no encroachments into the CCZ have occurred at any time
and determination of the CCZ from the field perspective is problematic. The standard is ambiguous
and it seems like clear cutting is the underlining message that is wanted. Determining an
encroachment into the CCZ is problematic due to the need for survey accuracy measurements and
engineering evaluations. This will also lead to questions about the ability to audit this requirement.
The CCZ changes in size and shapes continuously in each and every span and will be difficult to
monitor. This would require field personnel to spend numerous hours estimating and attempting to
measure potential encroachments of the CCZ. The way R4 is currently written the Transmission
Owners would be required to self-certify compliance with R4, and which we don’t think this is
possible. This will lead to audit issues with more scrutinizing and potentially more penalties or fines. It
is important to recognize that the ultimate goal of the standard is to ensure that vegetation
management is conducted in order to maintain an adequate level of reliability, and not to precisely
measure clearance zones. Alternative 2 would be the most logical choice, depending on
easement/legal rights, with changes that would eliminate any reference to a trigger point into the
encroachment zone of the CCZ to; measuring encroachment to a fix distance (Gallet tables) observed
by field personnel
Agree
Agree
Clarifying the intent for the annual plan is to focus on the Active Rights of Way will prevent
interpretation conflicts
V1 was a better written standard and had clear requirements on reporting and who was to report
violations etc. When and how are violation to be reported is not mentioned in the V2. The standard
should clearly identify all reporting requirements. Standard development should focus on practicality
for the field personnel in terms of implementing the standard and enforceability. Version 2 is not as
user friendly for field personnel and ambiguous at best which requires an impractical and unrealistic
level of performance from the industry. This standard needs to stress that it applies to vegetation
within the Active Transmission Right of Way. Vegetation from outside the active ROW, falling through
the CCZ should not be a violation. V2 needs further clarification of the definition of the active ROW.
Individual
Richard Dearman
Tennessee Valley Authority
Disagree
TVA feels the use of the term Bulk Electric System will cause unnessesary confusion to the industry
concerning applicability of this standard. TVA recommends the continued use of the undefined term
"electric transmission systems. TVA recommends changing the phrase "by preventing vegetationrelated outages that could lead to Cascading" to "by preventing those vegetation-related outages that
could lead to Cascading", this removes the improper inference that each vegetation-related outage
leads to Cascading
Agree
TVA agrees with Comment question 2
Agree
TVA agrees with Comment Question 3
Agree
TVA agrees with Comment Question 4
Disagree
TVA suggests that R1.2 be changed by adding "except in cases where lines or significant sections of
lines are over terrain which is void of vegetation(such as bodies of deep water)or over terrain void of
any vegetation that can grow to a mature height that could threaten the conductors, then longer
cycles will be acceptable". This would avoid unecessary expenses in such cases.
Agree
TVA agrees with Comment Question 6 and proposes that the Annual Plan be a defined term.
Disagree
TVA recommends that R1.4 and R2 both be removed from this Standard. This is a "zero tolerance"
Standard with significant penalties for outage violations. These penalty conditions are the necessary
and sufficient conditions for the Transmission Owner to immediately react to any discovered threats
to prevent potential outages.
Agree
TVA agrees with Comment Question 8
Agree
TVA agrees with Comment Question 9
Agree
TVA agrees with Comment Question 10
Disagree
TVA recommends that R2 be removed from this standard. Since this is a "zero tolerance" standard
there is a very significant incentive for the Transmission Owner to inspect and plan maintenance to
prevent potential outages. The Gallet Equations should be kept within the white paper solely for the
TO to reference for developing maintenance and inspection cycles.
Disagree
TVA agrees with this concept however as stated in Comment Question 11 response, this should be an
element of the White Paper and should not be in the Standard Requirement.
Disagree
TVA agrees with this concept however as stated in Comment Question 11 response, this should be an
element of the White Paper and should not be in the Standard Requirement.
Agree
TVA agrees with Comment Question 14
Disagree
TVA recommends that R4 be removed from this standard. Since this is a "zero tolerance" standard
with substantial penalties for controllable vegetation related outages there is an overwhelming
incentive for the Transmission Owner to proactively perform inspections, preventative maintenance,
inpections and corrective maintenance to prevent potential outages. As such, R4 does not add any
value to improving reliablity while causing numerous unresolvable problems.
Agree
TVA agrees with Comment Question 16.
Agree
TVA agrees with Comment Question 17
Group
Associated Electric Cooperative Inc.
John Neagle
Associated Electric Cooperative Inc.
Disagree
The definition of Bulk Electric System includes most transmission lines operated at 100 kv and above.
While Section A.4.2.1 limits the applicability of FAC-003-2 to 200 kv and higher transmission lines,
the use of the term Bulk Electric System could cause unnessary confusion. Associated Electric
Cooperative Inc recommends the continued use of the term "electric transmission systems."
Disagree
Associated Electric Cooperative Inc does not believe the Reliability Coordinator (RC) is the appropriate
entity to determine whether or not selected sub-200 kv transmission lines should be subject to this
standard. The planning horizon for the RC is typically much shorter than the time needed to
incorporate a sub-200 kv transmission line into a vegetation management program. Associated
recommends Planning Coordinator be designated as the applicable functional entity and be
substituted wherever Reliability Coordinator appears in the Standard.
Disagree
Associated Electric Cooperative Inc agrees with the changes described in Question 3 except for the
definition of Active Transmission Line Right of Way. Associated suggests the term be revised to
"Active Right-of-Way" for consistency with the present Glossary term "Right-of-Way" and that the
definition of Active Right-of-Way be revised to explicitly permit the Transmission Owner to solely
determine the appropriate width. A suggested definition is "Active Right-of-Way: The portion of Rightof-Way utilized for active transmission facilities. The width of the Active Right-of-Way, as determined
by the Transmission Owner, shall be consistent with the Transmission Owner’s normal standards
and practices and shall be consistent with good utility practice for other transmission lines of similar
voltage and configuration. Inactive or unused portions of the Right-of-Way, intended for future
transmission lines or other facilities, may be excluded from the Active Right-of-Way."
Agree
Disagree
While Associated Electric Cooperative Inc agrees with this requirement in general, there may be areas
(e.g. highly arid terrain, open water, etc.) where an annual interval is unnecessary and adds little or
nothing to reliability.
Agree
Disagree
The language in R1.4, requiring notification of the Transmission Operator, is inconsistent with the
Applicability in Section A.4.1.1 which designates the Transmission Owner as the responsible entity.
Agree
Agree
Agree
Disagree
The phrase “…Critical Clearance Zone is approached…†in R2 is nebulous and probably
unenforceable. The determination and visualization of the Critical Clearance Zone and approaching
vegetation encroachment, under field conditions, is a practice in application of theoretical conductor
locations in real time. Would the Transmission Owner be found in noncompliance if evidence showed
vegetation had “approached†within 20 feet, 2 feet, 2 inches or some other arbitrary distance
of the CCZ and the TO failed to implement its imminent threat procedure?
Agree
Agree
Agree
Disagree
Associated Electric Cooperative Inc believes this requirement, as written, is unreasonable since it
would prevent (or at least result in noncompliance) the intrusion within the Critical Clearance Zone
(CCZ) of anything or anyone, including qualified line workers and their tools. It is suggested the
words “of vegetation†be added between encroachment and within. The requirement would
then read, “Each Transmission Owner shall prevent encroachment of vegetation within the Critical
Clearance Zone of its applicable lines with the following exceptions:†The complexity of
determining an encroachment into the Critical Clearance Zone is overly burdensome, requiring
engineering calculations and possibly the need for precision measurements. The Transmission Owner
(TO) cannot demonstrate compliance with the Requirement and its companion Measure, M4, since a
negative cannot be proven. Therefore, since the TO must demonstrate compliance (guilty until proven
innocent), it is automatically in violation of the Standard.
Disagree
Requirements 5, 6 and 7, as written, compel the Transmission Owner to allocate precious resources to
ensuring a vegetation related outage will NEVER occur on any applicable transmission line, regardless
of the line's true importance to maintaining electric transmission system reliability. All lines are not
created equal; only those which are an IROL or contribure to IROLs should be held to a zero tolerance
standard.
Agree
R9 and R10: Associated Electric Cooperative Inc does not believe the Reliability Coordinator (RC) is
the appropriate entity to determine whether or not selected sub-200 kv transmission lines should be
subject to this standard. The planning horizon for the RC is typically much shorter than the time
needed to incorporate a sub-200 kv transmission line into a vegetation management program.
Associated recommends Planning Coordinator be designated as the applicable functional entity and be
substituted wherever Reliability Coordinator appears in the Standard. M1.4: The language in M1.4,
requiring immediate communication of an imminent threat to the Transmission Operator, is
inconsistent with the Applicability in Section A.4.1.1 which designates the Transmission Owner as the
responsible entity. M4: The preparation and retention of inspection reports, imminent threat reports,
quality assurance reports, etc. is appropriate. These reports would not, however, absolutely
demonstrate the Transmission Owner had experienced no vegetation encroachments into the Critical
Clearance Zone. A negative cannot be proven. M6 and M7: The Transmission Owner is again expected
to demonstrate a negative to prove compliance. Section C: Associated Electric Cooperative Inc
recognizes the Standard, as posted, is a first draft for comments and will likely be revised before
submittal for ballot. However, the Compliance section should be posted for an adequate comment
period prior to balloting.
Group
NPCC
Guy Zito
NPCC
Agree
Disagree
While we agree with the suggested changes, we believe that the TVMP should be focused on removal
of incompatible vegetation from the Active Right of Way. We recommend using the following phrase in
R1: "designed to remove incompatible vegetation on its Active Transmission Lines' Rights 0f Way"
instead of "designed to control vegetation on its Active Transmission Lines' Rights of Way".
Incompatible vegetation should be defined as any vegetation which has the potential to grow tall
enough to jeopardize the integrity of an applicable transmission line by growing into the CCZ or falling
into the CCZ. This would provide clear guidance to all stakeholders, support long term vegetation
management philosophies, and complement methods such as IVM where incompatible vegetation is
completely removed, and compatible vegetation is encouraged to proliferate, thereby helping to
control incompatible vegetation in an environmentally positive manner. Removal of incompatible
vegetation is superior to pruning, topping, and trimming in terms of short and long term reliability of
the Bulk Electric System. This language would also serve to align NERC and FERC with Transmission
Owners who attempt achieve the highest degree of reliability by exercising their full easement rights
in cases where strong opposition from landowners and public officials is encountered. If such
language is adopted it should apply to R1 and the TVMP. It should be made clear in the technical
reference document that removal, rather than pruning of incompatible vegetation is the philosophy
that must be incorporated into the TVMP. It must be clearly explained that Transmission Owners have
the flexibility to perform removals gradually over several treatment cycles in sensitive areas as long
as pruning is performed as an interim measure to ensure that CCZ encroachments and on-Right of
Way fall overs do not occur. It must also be made clear that the presence of incompatible vegetation
on the Right of Way will always occur and does not in itself constitute a violation of the Standard.
Agree
Disagree
There were differing opinions within the group. Those entities with extensive overhead transmission
felt the once a year requirement was overly prescriptive and would not improve reliability, others
were in agreement with the "at least once per calendar year" requirement.
Disagree
R1.2 and R1.3 should specifically state calendar year, and the Annual Plan and inspection follow the
same calendar year timing.
Disagree
While we strongly agree that an imminent threat procedure should be required in the TVMP, we
disagree with some specific wording in R1.4. R1.4 requires immediate communication of an imminent
threat to the Transmission Operator, which we would normally agree with. R2 however requires that
the imminent threat procedure be implemented when the Critical Clearance Zone (CCZ) is approached
by vegetation. "Approached" is not defined as a specific distance, so this part of the requirement is
left up to the individual's interpretation. In cases where the CCZ is approached by vegetation no
threat to the system is possible if the vegetation is removed before it actually grows into the CCZ. In
many cases the vegetation can be removed without taking clearance outages because the CCZ is
large, and the conductor and vegetation are still relatively far apart. In such cases there is no need to
notify the Transmission Operator, although there is a need to remove the vegetation immediately. We
recognize that the opposite is also true, and that in some cases it will be necessary to notify the
Transmission Operator because a clearance outage or line de-rating may be required to remove the
vegetation. We therefore suggest a simple change to the wording of the second sentence of R1.4.
Change "…. specify actions which shall include immediate communication of the threat to the
Transmission Operator, and may include actions such as a temporary reduction in line Rating,
switching lines out of service, or other actions" to "... specify actions which may include immediate
communication of the threat to the Transmission Operator, a temporary reduction in line Rating,
switching lines out of service, or other actions". This change will address the issue which is described
above and will allow each Transmission Operator to develop an imminent threat procedure that best
fits their system. It should also be noted that many Transmission Operators have imminent threat
procedures in place to address all imminent threats to their transmission system, not just threats due
to vegetation. It makes sense for Transmission Owners to have only one imminent threat process,
therefore the flexibility that can be achieved in the context of this standard would be helpful.
Agree
Agree
We agree but believe that the TVMP should target removal of all incompatible vegetation on the
Active Right of Way as described in the response to question 3.
Agree
Agree
Agree
Agree
Agree
Disagree
The purpose of the standard is "To improve the reliability of the Bulk Electric System by preventing
vegetation related outages that could lead to Cascading". We believe that R4 is not the most effective
way to achieve this purpose because it does not provide incentive for Transmission Owners to take
advantage of modern technology, such as aerial laser survey (ALS) using Light Detection and Ranging
technology (LIDAR), that is capable of accurately identifying vegetation which is approaching the CCZ
or has encroached into it. In fact R4 provides an incentive not to utilize this technology because
Transmission Owners who identify encroachments would be in violation of R4 for each identified
encroachment. On the other hand, Transmission Owners who choose to be less proactive often would
not identify such encroachments because the CCZ and encroachments of it are generally not easy to
determine without taking precise measurements. Unless the line is heavily loaded or the vegetation is
significantly overgrown, encroachments of the CCZ would not be readily noticed. In most cases these
Transmission Owners would simply remove or cut back incompatible vegetation without taking
measurements. The threat to the line would have been eliminated with no encroachment having been
identified. R4 presents a dilemma for Transmission Owners that are considering making the significant
investment in ALS technology. While the technology would allow them to identify any potential growin or fall-in conditions, it would also expose them to the risk of identifying violations of R4, that would
otherwise not have been identified. Violation Risk Factors (VRFs), Violation Severity Levels (VSLs),
and Time Horizons are not included in this Draft, but after making a significant investment in ALS,
Transmission Owners could be faced with significant additional cost in terms of NERC penalties. In
addition, even if the penalties were relatively low they would be exposing themselves to violations
that less proactive Transmission Owners would not be exposed to. In our view R4 as written would, in
some cases, have the opposite effect of what is intended because the business case for using ALS is
more difficult to make. This will result in less use of ALS and other emerging technology that is likely
to be developed. This would result in fewer problems being identified, a small percentage of which will
not be discovered until they result in a line trip. Still we believe that the concept of the CCZ is a good
one and recommend that R4 be changed so that Transmission Owners are provided with an incentive
to invest in the best technology available in order to ensure the highest level of reliability. The
opportunity exists to develop the standard in a manner that encourages the industry to take
advantage of new technology and manage vegetation in a very proactive way. We recommend that
R4 be changed as follows: Modify R4 to require Transmission Owners to immediately implement the
imminent threat process defined in R1.4 when they identify instances where the CCZ is approached or
encroached upon. Failure to do so would be a violation of R4. Eliminate encroachment of the CCZ as a
violation of R4. This would eliminate R2 and incorporate implementation of the imminent threat
process into R4. Require Transmission Owners to report to the Regional Entity on a quartely basis any
instances where the imminent threat process was implemented due to an encroachment of the CCZ.
This would add a reporting requirement for Transmission Operators. Require Transmission Owners to
report to the Regional Entity on a quarterly basis any instances where either a momentary or
sustained outage was caused by grow-ins, Active Transmission Line Right of Way blow-ins, or Active
Transmission Line Right-of-Way fall-ins. This would add three additional reporting requirements for
Transmission Operators. Require Regional Entities to perform additional audits of Transmission
Owners that exceed metrics for violations of the CCZ . The metrics would be established in this
Standard based upon 100 circuit miles of applicable lines. This would add an additional requirement
for Regional Entites. This concept would result in a more rigorous standard than FAC-003-01 because
of the additional reporting and auditing requirements. It would drive proactive behavior throughout
the industry and provide a significant incentive for Transmisison Owners to invest in new technology
such as ALS that is capable of accurately identifying vegetation that has approached or encroached
upon the CCZ. We believe that this change would result in the identification of more incipient
vegetation-related problems and fewer vegetation-related outages as soon as it was implemented and
would best support the purpose of the Standard.
Disagree
NPCC participating members request clarification if violations of R5, R6, and R7 result in outages that
must be reported.
Agree
NPCC requests that the Standard Drafting Team review the compliance and reporting requirements
for consistency and adequacy.
Individual
Chris Scanlon
Exelon
Agree
Agree
Agree
Agree
Refer to footnotes in R1.1 and 1.2. Are applicable entities to be held accountable to ANSI A300
(footnote 2) and for providing documentation to support analysis that "local factors" were accounted
for (footnote 3)? These footnotes should be requirements or they should be removed and included in
a Reference Document not subject to compliance audit.
Agree
Agree
Agree
Agree
Disagree
We do not understand the reference to "fill in the blank" requirement for Clearance 1. As commonly
understood, a "fill in the blank" standard /requirement is one that was assigned to the RRO. Clearance
1 in FAC-003-1 is a TO requirement. The reference to a clearing zone should be retained, as each TO
will need to define this in their program so as to avoid encroachments into the CCZ.
Agree
Agree but same comment as above,we do not understand the reference to "fill in the blank"
requirement for R1.3. As commonly understood, a "fill in the blank" standard /requirement is one that
was assigned to the RRO.
Disagree
Comments: 1) In spite of the rigor associated with the Gallet equations, the definition of CCZ is
imprecise as the Ratings to be used are not specified. In addition, Exelon is concerned that it will be
difficult to determine the CCZ for each span under all possible operating conditions. Implementing an
imminent threat procedure (R2) in combination with the CCZ may be unworkable under actual field
conditions. 2) We are concerned that CCZ is only fully defined in the Technical Reference
documentation and not in the standard itself. As stated in the NERC Standards Process Manual,
Elements of a Reliability Standard, "Supporting documents to aid in the implementation of a standard
may be referenced by the standard but are not part of the standard itself." There needs to be enough
specificity as to the definition of CCZ in FAC-003-2 so that adequate documentation and evidence of
compliance can be developed.
Disagree
Comments: By using the Gallet equations, the draft standard appears to support reducing the
clearance requirements as compared to IEEE 516. Given what we believe would be the difficulties in
applying the clearances as developed using the Gallet equation method, we question if dropping the
IEEE 516 guidance could have the unintended consequence of reducing reliability.
Disagree
We disagree with the T factors that are proposed as our design is more conservative.
Agree
Disagree
The first bullet is unworkable in the real world. It will be virtually impossible to prove that "no
encroachments of the CCZ have occurred anywhere at any time during the compliance period". The
effort to do this will not enhance reliability. In fact, in may harm reliability by requiring unnecessary
investments and O&M expenditures that could be better spent on real reliability enhancements.
Exelon agrees, subject to the development of a workable definition of the CCZ, that the second bullet
is the preferred approach.
Disagree
It appears to Exelon that the requirements of the standard have been written and modified at
different times and as a result the document lacks a degree of consistency and coherence. While the
Standard mentions encroachment of the CCZ and Sustained Outages as potential violations, it is
completely silent on how momentary outages should be addressed. Exelon views the following events
as a risk continuum that should be addressed in the Standard and handled as a part of the VRFs and
VSLs - encroachment of the air gap distance, momentary outages and Sustained Outages.
Disagree
Strike "within the extent of it's easement and / or legal rights." This is unnecessary and will cause
confusion. The annual work plan as required to be developed per R1.3 requires consideration of
permitting, scheduling and regulatory limitations.
Applicability. 4.2.2 is unclear. If 4.2.2 is intended to cover Generator Owner interconnections, say so
uniquivocally. Do not rely on future changes to the NERC Registry Criteria or other "global" solutions if
the intent is to make the standard applicable to Generation Owners who own generator leads. Exelon
would like to reemphasize our concern with implementing the requirements if the Gallet equation
derived CCZ is used. ANSI A300 part 1 and part 7 should be part of the standard as they provide
independently recognized valid methods and guidance to conduct maintenance on the ROW corridor.
Individual
Weston Davis
Central Maine Power Company
Disagree
Central Maine Power suggests that a definition be provided for Bulk Power.
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Disagree
Central Maine Power Company disagrees with removal of clearance 1. The clearance 1 was included
so that professional arborists could establish the clearanace necessary for a transmission owner to
reduce the risk of a tree caused power outage. The transmission owner should use ANSI- Standard
A300, including PART 7, and other publications to develop best management practices which include
clearances at time of maintenance. Clearance 1 provides leverage for Transmission Owners to achieve
the clearances stated in their TVMP.
Disagree
Central Maine Power Company disagrees with the removal of the qualification statement. The
individual responsible for this critical program must be qualified through experience, training, and
education. The International Society of Arboriculture has a certification program that can help with
guidelines for qualified arborists.
No comment
Agree
Agree
Agree
Disagree
Central Maine Power Company suggests the second alternative to R4 as recommended above, which
is to require immediate removal of the vegetation or immediate implementation of the imminent
threat procedure upon discovery of a possible encroachment of the critical clearance zone, thus
preventing an outage. This alternative is similar to R2, therfore R4 may not be required.
Agree
Central Maine Power Company suggests that R8 read as A Transmission Owner shall implement its
annual work plan within the Active Right of Way to the the extent of its easements or legal rights.
The White paper is an important support document and should remain as an attached reference to
FAC 003. The white paper should clarify that capable tree species should always be removed from the
border zone, except in selected areas where topography includes deep ravines.
Individual
Thad Ness
American Electric Power (AEP)
Disagree
American Electric Power ("AEP") does not agree with this purpose statement. First, it is clear from the
Applicability (in Section 4) that the standard applies only to certain lines, not to the entire Bulk
Electric System (BES). Reference to the BES in the Purpose statement tends to muddy the water,
potentially leading to an assumption that the Standard indeed applies to the entire BES. AEP suggests
that the term BES used herein be replaced with "electric transmission system" or "transmission grid".
Second, the phrase "by preventing vegetation-related outages that could lead to Cascading" should
be changed to "by preventing those vegetation-related outages that could lead to Cascading", to
remove any suggestion that all vegetation-related outages could lead to Cascading.
Agree
AEP concurs with the drafting team that the Reliability Coordinator is the appropriate entity for
identifying sub-200kV lines (if any) that would be subject to the Standard.
Agree
While Requirement R1 does not actually define "Active Transmission Line Right of Way" (it is defined
on page 2 of the Standard), AEP concurs with R1, except as noted below for R1.4.
Agree
AEP agrees with these changes from Version 1.
Agree
AEP agrees with this change.
Agree
AEP agrees with these changes.
Disagree
AEP agrees with the need for a TO to have an Imminent Threat Procedure and that the Transmission
Operator should be immediately notified of imminent threats. However, AEP disagrees with the
requirement that the Transmission Operator be notified merely because the Cricitical Clearance Zone
(CCZ) has been approached. It is possible that the CCZ is encroached by vegetation at the lowest
point of the CCZ whereas the conductor may be at its highest point in the CCZ (potentially 20 or 30
feet away from the vegetation). This situation does not merit notification to the Transmission
Operator. Please also refer to our comments regarding CCZ in AEP's responses to Questions 15 and
18.
Agree
Agree
AEP agrees with the removal of Clearance 1 from the Standard.
Agree
AEP agrees that the Standard should not stipulate or require personnel qualifications.
Disagree
AEP agrees with the need for a TO to have an Imminent Threat Procedure and that the Transmission
Operator should be immediately notified of imminent threats. However, AEP disagrees with the
requirement that the Transmission Operator be notified merely because the CCZ has been
approached. Vegetation approaching the CCZ does not necessarily constitute an imminent threat. It is
possible that the CCZ is encroached by vegetation at the lowest point of the CCZ whereas the
conductor may be at its highest point in the CCZ (potentially 20 or 30 feet away from the vegetation).
This situation does not merit notification to the Transmission Operator. Please also refer to our
comments regarding CCZ in AEP's responses to Questions 15 and 18.
Agree
AEP agrees that the Gallet Equation method is a reasonable and appropriate replacement for the IEEE
516 method.
Agree
AEP agrees that the choice of transient overvoltage factors is sufficiently sound.
Agree
AEP agrees with this change.
Disagree
AEP disagrees with the proposed requirement that violations be automatically declared if the CCZ is
encroached. Instead, AEP would support a standard utilizing the first alternative proffered in these
comment questions. While the CCZ is an interesting theoretical concept, it is not realistically feasible
in the field to implement a concept that depends on accurate measurements and calculations.
Further, the proposed requirement offends common notions of reliable maintenance methods,
because it demands that forestry crews stop work if they see a potential encroachment and that
surveyors and engineers be brought in to take detailed measurements and perform complex
calculations to determine whether an encroachment has in fact occurred. The need for a reliable
transmission grid would be much better served by a standard utilizing the first alternative, in which
no violation occurs in the event of an encroachment as long as the TO implements its imminent threat
procedure and removes the vegetation. While seemingly technically appealing, the CCZ concept is
fraught with implementation difficulties. It should not be used as a Pass/Fail zero-tolerance decision
point to determine whether a violation has occurred. After all, a zero-defect condition has not been
achieved in many other aspects of electric utility operation. For instance, the utility industry attempts
every year to conduct its business without any workplace deaths, yet deaths occur every year. Many
millions of dollars are spent by North American utilities to promote safety programs and safe work
procedures, but some work-related vehicle accidents and personal injuries still occur. Also, utilities
aggressively investigate electric switching errors and have instituted rigorous dispatcher-training
programs, but a few switching errors still occur. For an industry in which billions of stems of
vegetation must be managed, even a high six-sigma level of quality would still result in a few cases
annually of imperfectly managed vegetation. It is unreasonable to expect zero-tolerance perfection
with the CCZ concept. Also, with the way R4 is worded, a tree falling from outside the right of way
would result in a violation if it passed through the CCZ, whether it resulted in an outage or not. It is
not appropriate to place a burden on the TO for such circumstances outside the TO's control. As R4 is
written, it appears that there is no way that a TO could certify at the end of the year that it has
maintained a CCZ free of encroachments, even if no outages occurred. AEP believes a more effective
and reliability-centered approach would be one where TOs are expected to implement their imminent
threat procedure if vegetation is encroaching upon the Gallet equation distance. If TOs act accordingly
and remove the vegetation without incurring an outage, then they would not be in violation. However,
if the TOs knew of vegetation encroaching upon the Gallet equation distance but failed to implement
their imminent threat process, they would be in violation and be obliged to report the event.
Agree
AEP is in agreement with these changes.
Agree
AEP agrees with this change.
The definition for Critical Clearance Zone (CCZ) on page 2 of the proposed draft Standard does not
specify the Rating (summer, winter, normal, emergency, etc.). This suggests that different CCZs
apply at different times of the year and thus that vegetation in the area might be outside the CCZ at
certain times of the year and inside the CCZ at other times. AEP suggests that this may not have
been the intent of the drafting team. Also, the term "design blowout" is not defined; thus, it appears
that it will be up to the TO and the auditor to determine the bounds of the CCZ. AEP again suggests
that this may not have been the intent of the drafting team. Requirement R8 contains the clause
"within the extent of its easement and/or legal rights". This intent of this clause is unclear and its
rationale is not obvious. AEP suggests that this clause be removed or at least reworded for clarity.
Individual
Deborah Schaneman
Platte River Power Authority
Agree
The use of the approved terminology, Bulk Electric System, from the NERC Glossary of Terms is
better than the undefined term electric transmission systems.
Agree
The Reliability Coordinator is better able to identify lines under 200 kv that would exceed an
Interconnection Reliability Operating Limit (IROL), cause instability, uncontrolled separation, or
cascading outages resulting from a vegetation related outage than the Regional Entity.
Agree
The list of terms, "objectives, practices, approved procedures and work specifications," from version 1
provides more clarity thatn the one word "methodology" and should bot be replaced. The newly
defined term "active transmission line ROW" provides clarity to the portion of the ROW requiring
vegetation management and is a valuable addition to the standard.
Agree
The separation allows lower sanctions and penalties to be assessed for weak documentation and
higher sanctions and penalties to be assessed for weak inspection programs and weak vegetation
management. However, the standard would be easier to follow if the two elements were kept together
in the document.
Agree
The inspection frequency is reasonable.
Agree
Under the new working in R1., the TVMP no longer has a requiremnt to include objectives. However,
there is a phrase in R1.3. to "support the objectives... and methodologies outlined in the TVMP".
R1.3. should be consistent with the wording in R1.
Agree
Imminent threat is not a defined term in the NERC Glossary of Terms so it could be construed as a
fill-in-the-blank requirement by FERC as each Transmission Owner could define Imminent Threat
differently. Imminent threat should be defined or the requirement should be reworded to define what
types of situations would require a procedure. Also, the language, "and may include actions such as a
temporary reduction in line rating, switching lines out of service, or other actions" should be removed
from the standard but could be included in the imminent threat procedure or definition.
Agree
The term corrective action plan adds clarity.
Disagree
Clearance 1 could be defined in the standard in tables developed using IEEE Standards for various
voltages, line spans and altitudes. Clearance 1 provides justification and leverage for operational
clearances when dealing with organizations such as municipalities. Without Clearance 1, utilities could
be mandated in specific situations to clear so that the vegetation is just beyond the CCZ at all times.
This could result in pruning at six month intervals, which is not feasible or cost-effective.
Agree
The requirement should be removed because it is a "fill-in-the-blank" requirement. Defining the
proper amount of personnel qualifications and training would be too prescriptive for utilites with small
vegetation management programs and not prescriptive enough for utilities with large vegetation
management programs.
Disagree
Changing to the Gallet equation will not have a large impact on vegetation management operations,
keeping Clearance 1 and 2 with tables developed using IEEE Standards for various voltages, line
spans and altitudes is preferable. Actions should be taken to prevent an outage when vegetation
encroaches Clearance 2.
Agree
Changing this will not have a large impact on vegetation management operations, so we have no
concerns.
Agree
Changing this will not have a large impact on vegetation management operations, we have not
concerns.
Agree
The separation allows lower sanctions and penalties to be assessd for a weak schedule and higher
sanctions and penaltites to be assessed for not implementing schedules. However, we feel that the
sandard itself would be easier to follow if it was re-organized so that the requirement to have the
schedule is kept together with the requirement to implement it.
Disagree
This requirement should be removed completely. It is too stringent and it is impossible to prove
compliance through documentation. Encroachemnt of Clearance 2 (or CCZ) should be addressed in
the imminent threat procedure.
Disagree
The requirement under R7 should be changed from "shall prevent sustained outages" to "shall
minimize sustained outages due to vegetation falling into a conductor." We note the word "minimize"
was present in earlier drafts of the docuement. We are concerned about the requirement for utilities
to prevent sustained outages from vegetation falling into the conductor from within the active
transmission ROW. It is operationally almost impossible to know precisely where the edge of the ROW
is in all situations under all conditions. This could lead to an incident where utilities are charged
unreasonably - for example, for an outage from a tree that was one foot within the active ROW line.
We should not be held liable when reasonable due diligence is practiced.
Agree
The separation allows lower sanctions and penalities to be assessed for a weak plan and higher
santions and penalties to be assessed for not implementing an annual plan. However, we feel that the
standard itself would be easier to follow if it was re-organized so that the requirement to have a plan
is kept together with teh requirement to implement it.
The white paper ensures consistent interpretation of the standard. Perhaps the lack of such a paper in
the first version of the standard contributed to the varying interpretations.
Group
WECC Reliability Coordination
Linda Perez
WECC RC
Agree
Agree
This would be a new function in WECC RC, we are not currently staffed to perform this function.
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
R9 Should a dispute arise, how are thoes disputes resolved. Who keeps the list. R10 What is
acceptable methodology given the lack of interpetation of of unacceptable risk of instability(R 10.2) or
cascading failures. There is no definition of the consequences if a sub 200kv line is left off the list for
vegitation management, and caused a cascading outage or placed the grid at an unacceptable risk of
instability.
Individual
Alan Gale
City of Tallahassee
Agree
Agree
Agree
Agree
See Question 6 and 17.
Disagree
While TAL's specific conditions and current process would meet this requirement, I can envision where
some conditions may not require an annual inspection. These might include desert conditions, crop
fields, over water, etc. To dictate a specific one-year requirement could be burdensome to some
utilities with no improvement to the relibility of the BES.
Disagree
While I can agree with a separate requirement (R8) to implement the plan developed in R1.3, they
need to both have the flexibility desired in R1.3. I do not see that flexibility in R8. See response to
question 17.
Agree
Disagree
The use of the term "interim corrective action" implies that a permanent solution or return to the
original plan must be pursued. I would change this to "alternate maintenance" process to prevent
non-compliance if the TO is constrained and has reached an agreement with the land owner that
works to maintain the reliability of the line.
Agree
Agree
Agree
As long as we do not have to have evidence of using the calculation! We should be able to use Table I
as provided.
Agree
Agree
As long as we do not have to have evidence of using the calculation! We should be able to use Table I
as provided.
Agree
Disagree
VEHEMENTLY DISAGREE! The purpose of the standard is to prevent vegetation related outages. A
violation should occur if an outage occurs. As written, R4 and M4 would be impossible to prove or
disprove. It is not like we can get up there with a tape measure and measure it. R2 requires action if
the CCZ is "approached". This is undefined and subject to a myriad of interpretations. Evidence is
hard enough to obtain to the satisfaction of the Compliance Monitor. To require sufficient evidence to
prove that something didn't occur is a tremendous burden and is not a wise expenditure of vegetation
management dollars. Let us spend the money on trimming and not on paperwork. As an alternative
replace "encroachment within the Critical Clearance Zone" with "vegetation caused outages". This
would allow the same exceptions and is much easier to prove or disprove with a breaker operation.
Although this would result in the cause of every breaker operation being tracked, it is a tangible
evidence requirement and leaves very little room for interpretation. The levels of fines have already
shown that vegetation management is a serious standard and we had better comply.
Agree
Why have we gone backwards with only "Sustained Outages" being a violation? Even a momentary
outage indicates that a violation has occured if the cause was vegetation related (with the same
exceptions). This would seem to contradict the proposed R4. If it wasn't a Sustained Outage it wasn't
a violation? If you have a sustained outage due to vegetation, you must have violated the CCZ.
Disagree
Combined with Question 6. R8 needs to have the same flexibility that R1.3 has. As written, it could be
argued that you have to do everything in your annual plan, AND anything in addition due to the
changing conditions. This contradicts what is put forth in the white paper. I would add "as modified
per R1.3" after "implement it's annual work plan for vegetation management"
Attachment I. Titles are different between page 8 and 9. Page 8 should have (D) after Distances.
Page 9 should have indication that it is "continued" since the table spans multiple pages.
Individual
Fred Young
Northern California Power Agency (NCPA)
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Section A. 5. Effective Dates: This is extremely vague and I would not know the actual effective date.
Whose regulatory approval is needed? If this is meant to leave flexibility between FERC and the
Canadian entities, please write it that way. Most effective dates are clear and concise, i.e., "the first
month following apporval by FERC". Let's clear this up and avoid a subsequent interpretation request.
Individual
Jason Lietz
Northern Indiana Public Service Company
Agree
Agree
Disagree
Use of the term "have" is a notable and unnecesssary weakening versus the terms "prepare and keep
current". One of the key lessons learned from past vegetation related outages and subsequent
investigations and reports is that successful UVM programs must continually adapt to changing
circumstances which means practices and procedures must be kept current. Why weaken this
expectation in the standard? Also, I disagree with the elimination from the revised standard the
present requirement R1 that all TVMPs include certain essential components (objectives, practices,
approved procedures & work specifcations). Why make changes that imply TVMP's without these key
components are acceptable?
Agree
I agree with the seperation and re-ordering of documenation and implementation requirements into
two distinct groups. This is a welcome improvement to the standard.
Agree
Disagree
I disagree with the elimination of the present requirement R2 (last sentence) that requires a TO to
have proper quality control (QC) systems and procedures in place to document & track planned UVM
work so as to verify it was completed properly to work specifications. The need for this requirement
was demonstrated as recently as last year when a grow-in outage occurred at BG&E due to a
contractor trimming the wrong tree at the wrong location, a situation that could have been prevented
with effective QC.
Agree
Disagree
The existing R1.4 is focused on identifying where vegetation clearance objectives cannot be met at
the time UVM work is performed due to restrictions outside of the TO's immediate control. The
proposed revised standard is focused on situations where work scheduled in the annual plan cannot
be performed as planned for any reason. Can a constraint on planned work be internal such as budget
related? Why bother with a corrective process for constrained planned work if the work not completed
as planned poses no risk of causing an outage? I stongly believe that the sole focus of this provision
must specifically address individual locations where, due to restrictions outside of the TO owner's
control, vegetation clearances specified in the TVMP cannot be obtained. This section of the standard
should be about trees being closer to conductors than they should be due to factors beyond the TO's
control, rather than whether or not planned work was performed.
Disagree
I am strongly opposed to the removal of Clearance 1 from the standard. Being able to point to this
provision has been invaluable to internal communications with upper management and external
discussions with land owners and the public concerning UVM. In fact, other than the patrol/inspection
requirements, no other provision in the standard has been as essential to preventing grow-in tree
contacts than Clearance 1. It has forced TO's across the country to re-claim overgrown ROW and recommit to consistent UVM practices. We all know how easy it is for TO's to get weak in the knees in
the face of public opposition to proper and prudent UVM work even when it is clear what needs to be
done. This dynamic is what led us to the 2003 blackout to begin with. I would like to see the drafting
team consider expanding upon the existing model and create three clearances: 1. A clearance at the
time work is performed, 2. An action threshold clearance which would trigger the TO would take
immediate action to clear encroaching vegetation posing an unacceptable outage risk, and 3. A no
closer than clearance in which vegetation would never be allowed to encroach in order to prevent
flashover.
Disagree
If the standard continues to allow T.O.'s to design and implement their own TVMPs and expect them
to use BMPs, ANSI A300, develop menthods and practices, adapt schedules and plans to changing
conditions, etc., then it is reasonable to expect that T.O. personnel responsible for the TVMP to be
experts in the field of utility vegetation management with appropriate training, certifications, licenses
and credentials. I do not agree with eliminating this requirement. Quite the opposite, I believe that
the requirement needs to be more specific as to minimum qualifications key personnel must meet.
There are more requirements & qualifications to drive a semi-truck than to design and implement a
program (UVM) critical to the operation of the nation's electric grid. Does that make sense?
Disagree
While I agree with the argument that the Gallet equatiion is a better technical or scientific method
than IEEE 516 for determining realistic conductor to tree flashover distances, I do not agree that the
new proposed clearance tables serve any useful purpose as a vegetation clearance standard from an
operational perspective. The FAC-003-2 Technical Reference itself points to this fact when it states,
"even if the exact size and shape of the C.C.Z. is known, it becomes nearly impossible in the field to
correlate and accurately superimpose the C.C.Z. around the conductor." The Tech. Ref. goes on to say
that "it is anticipated that many T.O.s will establish a work trigger well outside the C.C.Z." I agree
wholeheartedly with that concept and believe that the Gallet clearance tables should be used by TO's
to develop the more important "work trigger" or "action threshhold" clearances. This revision is overly
focused on C.C.A.'s that have no practical operational application while being silent to the more
critical to reliability issue of "work trigger/action threshold" clearances. This needs to be addressed if
we hope to be successful at achieving the goal of zero preventable tree related outages.
Disagree
If T.O.'s are serious about public safety and potential electrical hazards or are required to comply with
NESC/IEEE safety standards, then the greater, more conservative clearance distances must apply. On
an complex issue where the aerial distances between live conductors and trees are dynamic and
changing, I would prefer to be on the side of caution and on the side of safety. Given the history of
cascading blackouts due to preventable tree contacts, there is a need to be conservative with the
standards. I don't see it being in the public interest to argue that established minimum air insulation
distances are inappropriately restrictive when applied to UVM.
No comment.
Agree
Disagree
It will be impossible for a T.O. to provide "evidence" that no encroachments of the C.C.Z. occured at
any time during the year. This approach will be a compliance nightmare and is unworkable. How does
one prove this never happens? You can't monitor every span of every line at all times. Obviously,
whenever a T.O. has a preventable outage, that should be a violation. To address the issue of
preventing outages before they occur and penalizing T.O.'s who don't take proper steps to prevent
them, I prefer the approach of immediate removal of threatening vegetation that encroaches within a
"threat trigger/action threshold" clearance distance per the T.O.'s formal imminent threat procedure.
This "threat trigger/action threshold" clearance would be established by the T.O. and be a specific
requirement under a revised FAC-003.
Agree
While being more specific & explicit, I don't interpret the overall requirement as being any different
from the current standard.
Agree
While I very much respect the industry commitment and expertise of the drafting team members, the
resulting revised standard reflects an effort to "revolutionize" the standard, when an "evolution" of
the current standard would better serve the interests of system reliability. The kinds of wholesale
changes proposed in this revision evoke real concerns about governmental regulations being a
moving target and in many aspects, backs away from requirements that have led to real progress in
UVM made since the 2003 blackout. For example, our company has invested tens of thousands of
dollars and countless man-hours to comply with provisions of the existing standard only to see them
simply done away with under the proposed revised standard. These investments were made based on
an industry consensus standard as well as a realization that the requirements were reasonable and
essential to improving system reliability. Where is the evidence that the current standard is not
working as intended? What has changed in the last few years to warrant a complete re-write of the
current standard? Most UVM professionals will agree there are some changes that need to be made to
address FERC's concerns and to clarify intent. However, as presently written, I will recommend our
T.O. vote against adoption of FAC-003-2.
Group
Western Area Power Administration, Upper Great Plains Region
Jerry Paulson
Western Area Power Administration, Upper Great Plains Region
Agree
Western (UGPR) agrees with the objective of using the FERC/NERC defined term "Bulk Electric
System", but believe that the FERC/NERC definition includes lines above 100 kV. It needs to be
clearly understood that use of the generic term in the Purpose section does not supersede the specific
definitions (greater than 200 kV, etc.) contained in the Facilities section.
Agree
Western's (UGPR) agreement is contingent upon maintaining the requirements for consulting with
Transmission Owners and neighboring Reliability Coordinator(s) and documenting the method for
assessing the reliability significance of each included line as contained in R9 and R10.
Agree
A question that has surfaced during discussions within the industry is "Can the Transmission Owner
designate an active R/W width that is less than the easement width even with a single-circuit line with
no R/W set aside for vegetation buffer or future development?" OR, does the easement width equate
to "Active T-Line ROW" under the situation described above.
Agree
Agree
Agree
The description of the annual plan now appears to require a detailed plan for each line. Under FAC003-1, Western (UGPR) identified higher priority vegetation during aerial inspection and handled
those expediciously. We then addressed a percentage of the lower priority trees based upon a number
of agency defined factors (vegetation priority, ground conditions, resource availability, etc). The less
rigid annual plan allowed us the freedom to cut the lower priority trees that made the best sense to
cut. We are concerned that the additional rigidity will create a ever-changing annual plan because we
may have to adjust dozens of lines based on inspections. We question whether it is prudent to occupy
finite resources in continually modifying the annual plan when the real benefits accrue from actually
performing the vegetation management activities.
Agree
Agree
Agree
While Western (UGPR) agrees with the removal of Clearance 1, we believe it is advantageous for
Transmission Owners to have a "trigger distance" in order to have some additional time to plan and
schedule vegetation work. The trigger distance is advantageous only if the Regulators do NOT
interpret it to be an extended CCZ and do NOT enforce based on "trigger distance" instead of the
CCZ.
Agree
Disagree
The CCZ as defined would very specifically outline a zone that needs to remain clear of vegetation to
avoid a violation, but that specificity could be an overly burdensome concept to implement and/or
monitor. Theoretically, there could be an infinite number of allowable vertical and horizontal (for
outside phases) clearances depending on your location within each span. Theoretically, you may need
to clear cut at mid-span (depending on retreatment intervals, growth rate, etc.) while allowing a 40
foot tree closer to the structure, along with everyting in between depending on your location within
the span. To fully comply with the CCZ as defined, each Transmission Owner would have to have a
table of allowable vertical and horizontal clearances for every few feet on every available span length
within each line section. Producing such tables would be a significant burden to each Transmission
Owner, but without them, the Transmission Owner could not verify that vegetation had not
encroached within the CCZ. In order to produce the tables outlined above, the Transmission Owner
would need to identify what design parameter(s) are applicable for the "correct" CCZ? We remain
concerned that weather conditions in excess of those parameters could lead to a vegetation
contact/outage and proving that weather conditions were in excess of design criteria would be
extremely difficult or impossible for all spans on a lengthy transmission line. It is not uncommon to
have weather stations 50 or more miles away from points on our transmission system. In order to
certify/verify compliance, the Transmission Owner would have to physically take their table to the
field and verify vertical and horizontal clearances from the edge of the theoretical envelope (not the
actual conductor position) for all vegetation within the span. This would be a time-consuming,
burdensome, cumbersome process if Regulators are going to require specific evidence in order for the
Transmission Owner to document their annual certification.
Agree
Agree
Agree
Disagree
R4 as proposed would do nothing to improve the reliability of the BES. In fact, we believe that R4 (as
currently proposed) would impose significantly more stringent requirements than most Transmission
Owners have interpreted FAC-003-1 to require. We believe that if the proposed interpretation would
have been offered under FAC-003-1 that there would have be a great backlash against that Standard.
It is our believe that current annual certifications of compliance for FAC-003-1 by Transmission
Owners don't use "any infringement of the CCZ by any piece of vegetation at any time" as their
measure for compliance. It could be argued that this proposal would actually do more to curtail
accurate reporting of potential violations. We believe that making an infringement into the CCZ a
violation and having that violation carry a six (or seven) figure fine would do more to discourage
accurate reporting than any other system under discussion. Making the Transmission Owner prove
that an incursion into the CCZ didn't happen would force an inventory of every inch of the R/W which
is a gigantic waste of resources. Being tasked with proving that something didn't happen could be
compared with our justice system declaring suspects will be considered guilty until they are proven
innocent. This is a flawed and blatantly unfair concept and not a productive way of attaining the
Purpose stated in this document. Western (UGPR) is disappointed by the "zero tolerance" nature of
this document and its interpretation that "any infringement of the CCZ by any piece of vegetation at
any time" constitutes a violation. We are not aware of any other NERC standard that is zero tolerance
and question why vegetation is singled out to bear the brunt when several other factors could
contribute to a system cascading event (i.e. relay problems, system configuration, operator issues,
etc). In summation, we believe that a zero tolerance document being applied with "guilty until proven
innocent" principles would do much to create an increasingly adversarial relationship between
regulators and the industry.
Agree
Agree
1) Proactive utilities are implementing policies that call for the removal of all vegetation that could
grow into the CCZ. Such policies are not without resistance from landowners, environmental groups,
etc. One of the arguments used by such groups is that NERC/FERC do not require removal of the
trees. It would very helpful if this document included the practice of removing vegetation capable of
encroaching within the CCZ as a reasonable or acceptable practice under this Standard. 2) We can
forsee a possible public backlash if this Standard is adopted as written. We see many utilities needing
rate increases to cover the additional costs of implementing and monitoring the more stringent
requirements of this proposal. We also believe that the more stringent requirements will have no
noticeable impact on reliability. So you'll have the public paying more and seeing no change in
reliability and questioning why.
Group
SERC Vegetation Management Subcommittee (VMS)
Jack Gardner (Chairman) Joe Spencer (SERC staff)
SERC Reliability Corporation
Disagree
The definition of the Bulk Electric System generally does not include radial transmission lines directly
serving load and, in addition, includes all lines operated at 100 kV and above. Use of the term Bulk
Electric System will cause unnecessary confusion to the industry concerning applicability of this
standard. Therefore, we recommend the continued use of the undefined term "electric transmission
systems."
The SERC Vegetation Management Subcommittee (VMS) abstains on this question. However, we
believe that this comment form should provide an option to abstain in addition to the options to
agree/disagree.
Agree
Agree
Agree
While the SERC VMS agrees in general, there may be areas (i.e. desert terrain) where an annual
interval would be unnecessary and not cost effective.
Agree
Disagree
The Requirement as written is too prescriptive and is open to interpretation, from an audit
perspective, with use of the term “immediate†communication and a partial list of activities.
Many conditions or threats, requiring immediate removal, would not require communication with the
Transmission Operator, who is not an applicable entity for this standard. The SERC VMS recommends
that R1.4 be deleted. Since this is a "zero tolerance" standard any Transmission Owner will remove
any discovered threats to prevent outages. If R1.4 is not deleted, the SERC VMS believes that
imminent threats should be a defined term. The definition should be as follows: “Imminent Threat:
A vegetation condition which, if not addressed, will place a transmission line at a significant risk of a
Sustained Outage.â€
Agree
Agree
Agree
Disagree
The SERC VMS recommends that R2 be deleted. Since this is a "zero tolerance" standard any
Transmission Owner will remove any discovered threats to prevent outages. While we agree that the
implementation of an imminent threat procedure may be a valid concept, visualization of the Critical
Clearance Zone (CCZ) and determining an approaching encroachment is a practice in application of
theoretical conductor locations in real time.
Agree
Developing minimum sparkover distances in this standard is a superior approach for the stated reason
in question 12. In addition, referring to tables and values in another standard is problematic if the
referenced standard is revised and the tables are re-numbered or deleted altogether. We suggest that
the tables based on the Gallet equations be removed from the standard and be kept in the technical
white paper solely to assist in developing a common understanding of the threshold for taking actions.
Agree
See comments in #12 above.
Agree
Disagree
The concept of the CCZ is useful as a mental model to visualize required vegetation management
work. While this is a good conceptual tool to drive consistent terminology and proper vegetation
management practices, it remains theoretical in nature and impractical to measure on a span by span
basis. The complexity of determining an encroachment into the CCZ is overly burdensome due to the
need for survey accuracy measurements and engineering evaluations. In addition, this complexity
leads to questions about the ability to audit this requirement. These complexities introduce reliability
and audit issues when encroachments into this conceptual area are defined as violations. The SERC
VMS believes the Sustained Outage, as defined by other measures in this standard, should be the
non-compliance measure. We suggest that the CCZ concept be kept in the technical white paper and
that all references to the CCZ be removed from the body of the standard.
Agree
Disagree
While the SERC VMS agrees in principle, we believe that the Requirement, as written, is “open
ended†and could be interpreted to be in conflict with the "Active Rights of Way" concept.
Clarifying the intent for the annual plan to focus on the Active Rights of Way will prevent incorrect
interpretations. The SERC VMS suggest that the Requirement be reworded to read: “Each
Transmission Owner shall implement its annual work plan for vegetation management within the
Active Right of Way to accomplish the purpose of this standard within the extent of its easements and
or legal rights.â€
Group
Progress Energy Florida
John Pinney
Transmission Operations and Planning Department
Disagree
The intent of the revision of the standard was to bring clarity to the standard. Referring to the BES in
the purpose creates confusion as to the applicability of the standard. Therefore, Progress Energy
recommends the continued use of the term "electric transmission systems."
Agree
While Progress Energy agrees that the RC is the appropriate entity, the drafting team should consider
including a dispute resolution requirement for those instances when the Transmission Owner and the
Reliability Coordinator disagree as to which lines below 200 kV should be included.
Agree
Disagree
The sub-requirements should be moved up to requirement level if the team desires to have different
VRFs and VSLs.
Agree
Agree
Annual Plan should be a defined term in the standard. Without a definition, the term may be
interpreted differently by industry and the regulator. The drafting team should raise the prominence
of annual plan and define the attributes of an annual plan.
Disagree
Progress Energy agrees with the need for a Transmission Owner to have an Imminent Threat
Procedure and that the Transmission Operator should be immediately notified of imminent threats but
only when it is appropriate as defined by the TO's imminent threat procedure. We disagree with the
requirement to immediately communicate with the Transmission Operator whenever the Critical
Clearance Zone is approached. Not every scenario is an issue that requires action by the Transmission
Operator: It is possible that the CCZ is being approached by vegetation at the lowest point of the CCZ
whereas the conductor may be at its highest point in the CCZ (potentially 30 feet away from the
vegetation) -- This typical situation does not merit notification to the Transmission Operator (which is
required by FAC-003-2 as currently written).
Agree
Agree
Agree
Disagree
The Critical Clearance Zone as currently defined is too academic. Implementation of R2 would require
field operations staff to determine the theoritical position of the line during inspections to decide
whether to engage the imminent threat procedures. The academic/theoretical aspects of the Critical
Clearance Zone definition are not practical or enforceable. The criteria for a violation needs to be
limited to the position of the conductor in real time.
Agree
Agree
Disagree
The standard has established a threshold of compliance. For consistency, compliance should be
measured at the threshold not a Registered Entities program requirement.
Disagree
The definition of Critical Clearance Zone includes too many academic and theoretical elements. It is
impossible to provide evidence that vegetation did not encroach into the the Critical Clearance Zone
during TVMP cycles. Furthermore, the operations staff performing periodic ground and aerial
inspections would need to determine the CCZ for each foot of transmission line to assure compliance
with the standard as it is currently written. The CCZ concept can neither be implemented or enforced
as written. The CCZ refers to Ratings which is defined in the Glossry of Terms as "The operational
limits of a tranmsission system element under a set of specified condiditons." This definition is too
broad to be a consistently enforceable term from one utilitly or region to the next. As it is currently
written, no exemption exists for vegetation falling from outside the Active Transmission Line Right of
Way into, or lodging in, the theoretical CCZ.
Agree
Agree
While Progress Energy agrees with the change, the term ‘annual plan’ should be a defined term
including threshold elements.
To avoid interpretation errors and provide clarity, the Applicability section for Facilities (4.2) of FAC003 should include a statement that the standard only applies to vegetation within the Active
Transmission Line Right of Way. For example, a fall-in from outside of the Active Transmission Line
Right of Way that causes a sustained outage is not a violation of this standard. Any
encroachment/outage initiated by vegetation falling from outside of the Active Transmission Line
Right of Way should be excluded from violations. The CCZ concept is academically elegant, but when
applied in the field, it presents significant implementation, interpretation and enforcement issues: the
complexity of determining compliance could have the unintended negative consequences to reliability;
removal of vegetation will likely be delayed because of the complexity and accuracy required to
determine compliance prior to tree removal; certification that no violations have occurred will require
lengthy and costly calculations and survey measurements; the standard refers to Ratings in the
determination of line sags and Ratings is not a tightly defined term, PRC-023 requires relays to hold
lines in beyond the line Ratings; how will PRC-023 requirements be factored into the CCZ concept.
The CCZ concept introduces more complexity and ambiguity into the standard than it resolves. The
drafting team needs to develop an alternative to the CCZ concept that is simple, easy to apply and
clearly defines at what point a violation occurs. There are over 158,000 line miles of AC Transmission
above 200kV in the United States, covering a Right of Way area potentially as large as 3,000 to 4,000
square miles (an area roughly equivalent to Rhode Island and Delaware combined). With billions of
stems of managed vegetation, in and along the right of way, even six-sigma performance would
result in a number of outages on a system this large. With countless VM processes and assessments
that take place daily, it is unrealistic/unreasonable to expect zero-tolerance for random vegetation
events (the transmission system is planned/operated to handle at least any single contingency).
Group
Kansas City Power & Light
Michael Gammon
Kansas City Power & Light
Disagree
The definition of the bulk electric system does not match the scope of the systems covered by the
vegetation management standard. If the term bulk electric system is used , it should exclude the
areas not covered by the standard.
Agree
I agree with the qualification that the Reliability Coordinator identify sub-200kv facilities in
consultation with its Transmission Owner(s) and neighboring Reliability Coordinator(s).
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Disagree
As proposed, Requirement R4 and corresponding Measure M4 will be highly subjective and impractical
for the industry to implement. The determination of a violation due to encroachments into the Critical
Clearance Zone will be subjective in nature due to field judgments, is random and not initiated by a
known system event. It also will not be feasible for utilities to fulfill R4 requirements to ensure and
provide evidence that any encroachments into Critical Clearance Zones have not occurred on their
system throughout the year. Requirement R4 is not required since in the remaining requirements of
FAC-003-2 contain the principal elements for compliance in ensuring the reliability of the bulk power
system related to vegetation management of the transmission system. Specifically, the remaining
requirements provide that a transmission vegetation plan be maintained, implemented and regularly
reviewed whereby utilities must perform the requisite vegetation clearance work in order to prevent
any sustained outages on the bulk power system. A sustained outage due to vegetation is a known,
measurable event to which a penalty sanction will be invoked and therefore provides the required
impetus for adherence to standard FAC-003-2. Requirement R4 and the associated measure M4
should therefore be removed from the proposed standard language.
Disagree
Exceptions should include flying debris including vegetation.
Agree
The title and explanation for Table 1 in Attachment 1 is not clear as to it’s usage and applicability.
It is being confused with the correlation with a minimum clearance and not as a component or
building block of the Critical Clearance Zone. Under R10, there may be other methods for
consideration of assessing reliability significance of the sub-200 kV lines other than what is listed.
Suggest the Drafting Team consider other criteria that an RC should condsider in its processes. R10.2
is redundant with R10.1. IROL by definition are those operating limits that represent instability,
uncontrolled seperation or cascading. Suggest removing R10.2. Under M1.3 the measure requires the
annual plan to cover a calendar year. An annual plan may cover a cycle growing season to growing
season using the inspection to verify the next seasons work. Suggest removing the language for
calendar year. M5, M6, M7 The measures should be requesting the evidence that it has violated the
requirements. Good standing programs should not have to defend good practice by providing useless
reports. The FAC-003-1 existing requirement R4 for reporting sustained outages is a reasonable and
sustainable method that should be retained. R9 should include a periodic review period of annually.
Any requirement to maintain current documentation should have a review period.
Individual
Chip Turner
Tampa Electric Company
Disagree
NERC glossary of terms defines the Bulk Electric System as "the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated equipment, generally
operated at voltages of 100 kV or higher." This, at a mimimum, could lead to confusion over what
impacts the reliability of the Grid by potentially including facilities less than 200 kV.
Agree
Agree
Agree
Agree
Agree
Disagree
TECO aggres with the need for the Imminent Threat Procedure. However, the use of the new Critical
Clearance Zone could create a "fill in the blank" standard. We we need to lock these clearances down
as an industry so as to define what is an imminent threat and what the CCZ is in terms of specific
distances.
Disagree
The phrasing above references a "corrective action plan". However, the standard as written is stated
as an "interim corrective action process". These are not one and the same. Interim implies a truly
temporary condition. As described on page 21 of the Technical reference, however,some of these
operational issues may not be "interim".
Agree
Agree
While we agree with the removal of "fill-in the blank" requirements, we recommend the inclusion of
professional qualifications for staff involved in this Standard. Reading the 42 page technical reference
and the attached comment form, all involved need to really understand the Standard as well as
industry practices.
Disagree
This is a good start. The Critical Clearance Zone (CCZ) is a very real and practical concept; however,
it is not transferable to field conditions. This could result in a "fill in the blank" standard relative to
what the Critical Clearance Zone will be in terms of distance. As I read this, it will be a sliding scale
from insulator to mid span and back for each designated line voltage. The max wind speed to be used
and other assumptions behind the determination of this zone may be as involved a Gallet's formula.
This will lead to complications during operational inspection and verificaiton of these clearances.
Agree
Agree
Agree
Disagree
This is a good start. The Critical Clearance Zone (CCZ) is a very real and practical concept; however,
it is not transferable to field conditions. This could result in a "fill in the blank" standard relative to
what the Critical Clearance Zone will be in terms of distance. As I read this, it will be a sliding scale
from insulator to mid span and back for each designated line voltage. The max wind speed to be used
and other assumptions behind the determination of this zone may be as involved a Gallet's formula.
This will lead to complications during operational inspection and verificaiton of these clearances.
Agree
Disagree
Good start. R8 must also address the flexability which is addressed in R1.3. As written, R8 does not
do this. In addition, R8 states "within the extent of its easement and/or legal right...". This could
create another set of conflicting criteria, where the utility has a long term "interim corrective action
plan".
Good start. However, this will need additional work and reivew predicated on the above comments.
Individual
Edward Bedder
Orange and Rockland Utilities Inc.
Disagree
The use of the term "Bulk Electric System" (BES) could lead to confusion. In most regions BES
includes lines with operating voltages equal to or greater than 100kV. The Standard is intended to
apply to all lines with operating voltages equal to or greater than 200kV, and only those sub-200kV
lines which are designated by the Reliability Coordinator (paragraph 4.2.1). Use of the words "electric
transmission systems" rather than BES would eliminate this potential source of confusion.
Agree
Agree
Agree
Agree
Agree
Disagree
While we agree that the imminent threat procedure should be included in the TVMP, the requirement
is overly prescriptive and should be revised to allow Transmission Owners flexibility to develop
imminent threat procedures which best fit their systems and protocols. We recommend that R1.4 be
reworded as follows: "Require a process or procedure for response to vegetation-related imminent
threats to applicable lines. The imminent threat procedure shall require action to eliminate
vegetation-related imminent threats, and shall be implemented upon discovery of such conditions". In
addition, the definition of "Imminent Threat" should be defined. We suggest the following: "A
condition which places a transmission line at significant risk of an outage in the very near term". An
example of a vegetation-related imminent threat would be an uprooted tree leaning precariously
toward a conductor which is certain to make contact with the conductor as the tree falls. Many
Transmission Operators have imminent threat procedures in place to address all imminent threats to
their transmission systems, not just imminent threats due to vegetation. In many cases it would
make sense for Transmission Owners to have one imminent threat process that covers all imminent
threat conditions. The flexibility being recommended would facilitate this.
Agree
Agree
We generally agree, however please see comments included in question 18.
Agree
Disagree
While we agree that the imminent threat procedure should be implemented to address vegetationrelated imminent threats as soon as they are identified, we believe that an "approach" of the CCZ
should not be used to trigger implementation. The term "approached" does not identify a specific
distance, so it is not clear to what extent vegetation would have to approach the CCZ in order to
require implementation of the imminent threat process. This is left to the discretion of individual
interpretation, is confusing to field personnel, and presents compliance and auditing problems.
Imminent threats which are based on vegetation clearances should be identified based on specific
clearances, not undefined approach distances. In practical field application the CCZ is an invisible area
that changes shape and size along the length of the conductor. It is impossible to readily identify in
the field without engineering calculations and precise measurements or the use of technology such as
Aerial Laser Survey (ALS) using Light, Detection and Ranging (LIDAR) technology. Therefore under
normal circumstances the location, size, and shape of the CCZ and vegetation encroachments of the
CCZ can only be roughly estimated. Even with the use of ALS, which is relatively accurate,
information is often not available for months after the survey flight. We believe that under normal
circumstances imminent threats which are based on vegetation clearances should be identified in
terms of specific distances from the conductor. While it is not possible for an inspector to readily
identify a vegetation encroachment of the CCZ in the field, an inspector could more easily estimate a
specified short distance between a conductor and vegetation in real time and initiate implementation
of the imminent threat procedure based on that assessment. This assessment would be significantly
more accurate than attempting to measure the distance between vegetation and the CCZ, which is
not visible and constantly changes size and shape throughout the span. In cases where the
Transmission Owner chooses to deploy ALS, the CCZ rather than the conductor could be used as the
reference because in most cases the CCZ could be identified relative to approaching vegetation with a
reliable degree of accuracy. Still a specific distance should be used to trigger implementation of the
imminent threat procedure because of the issues previously raised with the use of the word
"approached".
Agree
Agree
Agree
Disagree
We believe that R4 is not the most effective way to achieve the purpose of the Standard. As
previously stated the CCZ and encroachments of it are generally not possible to identify in the field
without taking precise measurements. The CCZ changes in size and shape continuously throughout
each and every span. In many cases the CCZ can be very large, and the position of the conductor
with respect to encroaching vegetation within the CCZ can be relatively far apart. Such cases would
typically not be identified as encroachments of the CCZ by visual inspections. Only those instances
where the vegetation is significantly overgrown would be readily identifiable. R4, as written presents a
problem in terms of compliance, certification of compliance, and auditing because precise
measurements of every span are impractical and costly to perform. Certification of compliance would
require field personnel to spend valuable time estimating and attempting to measure potential
encroachments of the CCZ. R4 does not provide incentive for Transmission Owners to deploy modern
technology that is better able to identify encroachments of the CCZ with a reasonable amount of
accuracy, such as ALS and LIDAR which are described in the response to Question 11. In fact R4
might provide an incentive not to utilize this technology because Transmission Owners who identify
encroachments using ALS which would otherwise not have been identified would be in violation of R4.
Transmission Owners that choose to be less proactive often would not identify such encroachments
and would be at less risk of violating R4. The effect could be less frequent use of ALS and other
technology that may emerge. This would result in fewer problems being identified, a small percentage
of which may not be discovered until they result in a line trip. We believe that the best way to achieve
the purpose of this Standard is to encourage proactive behavior which prevents vegetation-related
outages throughout the entire industry. R4 does not achieve this in the most effective way. We
recommend the following: Eliminate encroachment of the CCZ as a violation of R4. Require
Transmission Owners to immediately implement the imminent threat process defined in R1.4 when
they identify instances where vegetation has grown within a specific distance as described in the
response to Question 11 regarding R2. This would essentially combine R2 and R4. Require
Transmission Owners to report to the Regional Entity any instances where the imminent threat
process was implemented due to a vegetation-related clearance encroachment. This would add a
reporting requirement for Transmission Owners. Require Regional Entities to perform additional audits
of Transmission Owners that exceed metrics for vegetation-related clearance encroachments. The
metrics should be established in the Standard based upon 1000 circuit miles of applicable lines. This
would add an additional requirement for Regional Entites. Modify R5, R6, and R7 to include include
preventing momentary outages as well as Sustained Outages. We believe that this concept would
result in a more rigorous standard because of the additional requirements, but would focus the
industry's attention in a more effective fashion. We believe it would result in fewer vegetation-related
interruptions and a higher level of reliability soon after implementation, and would therefore best
support the purpose of the Standard.
Agree
We agree, but recommend that momentary outages be included as violations of all three
requirements as well. Also, the Standard does not directly require reporting of vegetation-related
outages although implicitly, outages which are violations of the Standard must be reported. This has
lead to some confusion during this comment phase and we suggest that the reporting requirements
be directly stated in the Standard.
Agree
Clearance 1 has been eliminated from this draft. Version 2 as drafted only requires that Transmission
Owners address vegetation that approaches the CCZ. This is essentially equivalent to Clearance 2 in
version 1, a minimum clearance. Although unlikely this could result in some Transmission Owners
adopting a just in time vegetation management concept that focuses on maintaining minimum
clearances, rather than removing incompatible vegetation or achieving greater clearances. Although
R1 requires Transmission Owners to design their TVMPs to control vegetation there is no clear
requirement to address incompatible vegetation early and aggressively. The drafting team should
revisit this and consider returning to some form of Clearance 1 or requiring the TVMP to address
removal of incompatible vegetation within their easement rights
Individual
Jason Shaver
American Transmission Company
Disagree
ATC disagrees with changing the term "electric transmission systems" to "Bulk Electric System". This
standard applies to 200 kV and higher transmission lines not all BES facilities. Suggested Purpose
statement: To maintain the reliability of the electric transmission system by requiring entities to have
and implement a transmission vegetation management plan.
Disagree
Requirements 9 and 10 should be deleted and replaced with the following language. Proposed
Language The TO shall include those transmission lines below 200 kV that that are associated with an
established IROL. (This language could either be uses as a requirement or inserted into the
Applicability section.) Our statement provides a clear decision on which lower voltage lines have to be
included in an entities transmission vegetation management program.
Agree
We agree with the idea but the term "active transmission facilities" needs additional clarity. This
clarity could be accomplished with a footnote. Proposed Footnote: A transmission facility that contains
a transmission line to which FAC-003 is applicable. The proposed footnote aids in the indentification of
applicable transmission facilities.
Agree
Agree
We agree with a minimum inspection frequency, but believe that the additional verbiage "… that
takes into account local and environmental factors" should be deleted. The additional verbiage does
not provide greater reliability only more documentation. Proposed Language: Specify a vegetation
inspection frequency of at least once per calendar year.
Agree
ATC agrees with separating the implementation Requirements from the Annual Plan Requirements.
Disagree
We agree that entities should have a Vegetation Imminent Threat Procedure, but that the term should
be defined. Also see related comments to Question #11.
Agree
ATC agrees with the concept but disagrees with the proposed language. ATC believes the term
"interim" should be removed from R 1.5. In some cases, a corrective action can end up being a long
term/normal fix. Proposed Language: Specify a corrective action process that will be used when
estabilshed clearances or methodologies are altered.
Agree
Agree
Disagree
ATC believes that the Critical Clearance Zone (CCZ) is a good theoretical concept to aid industy in
understanding the overall movement of conductors, but it is an impractical concept for field
application. Due to the variability in the size of the CCZ as you move along a conductor, as well as
changes from span to span or even line to line due to design parameters, loading or weather-related
issues, the CCZ concept should not be tied to an imminent threat procedure. Vegetation approaching
the CCZ does not constitute an imminent threat. It may be months to years before this vegetation
ever gets to a proximity distance from the conductor to be within a "spark-over" distance as defined
by the Gallet equations. Requirement R2 should support the purpose of this standard by requiring
implementation of the Vegetation Imminent Threat Procedure when the Transmission Owner has
visual, field knowledge that vegetation is encroaching upon a conductor within some specific distance
that is a multiple of the Gallet distances referenced in Table I of FAC-003-2 (to be conservative we
suggest two to three times the Gallet distances). Failure to implement the Vegetation Imminent
Threat Procedure in such instances would be a violation of R2. As R2 is currently written, a
Transmission Owner cannot comply with R2 unless the imminent threat procedure is continuously
being implemented or monitored, because vegetation that is growing is always approaching the CCZ.
"Approaching the CCZ" cannot be the trigger for implementation of the Vegetation Imminent threat
Procedure. Instead, the trigger should be an encroachment within some observed field distance.
Requirement R2 could be rewritten as follows: “Each Transmission Owner shall implement its
Vegetation Imminent Threat Procedure when the Transmission Owner has knowledge, obtained
through normal operating practices or notification from others, that vegetation is encroaching upon a
conductor within a distance that is twice the Gallet clearance distances referenced in Table I." Using a
multiple of the Gallet distances provides a safety factor. Assessing a violation for failure to
appropriately implement the Vegetation Imminent Threat Procedure or for a sustained vegetationrelated outage would promote the proper behavior.
Agree
Disagree
While the CCZ is valuable to understanding the movement of conductors, it cannot be readily applied
in the field. This field application challenge is noted in the Technical Reference Document (pages 29 &
30). The way R4 is currently stated, the Transmission Owner would be in violation of R4 for any CCZ
encroachment not due to natural disasters or human or animal activity. This would include a tree
falling from outside the right of way corridor that passes through the theoretical CCZ. Furthermore,
Transmission Owners would be required to self-certify compliance with R4, and ATC does not think
there is a practical way to do that. Clearly, the approach of assessing violations for CCZ
encroachment is unworkable. ATC believes that R4 should be deleted.
Agree
Agree
ATC agrees with the requirement to implement the annual work plan, but recommends striking the
words "within the extent of its easement and/or legal rights". The emphasis for this requirement is to
execute the annual work plan. The white paper already speaks to the point that it is a best practice
for utilities to exercise their legal rights. If we agree that the goal is to prevent outages, then we can
simply end this requirement with "implement its annual work plan for vegetation management."
Propose Changes to R8: Each Transmission Owner shall implement its annual work plan for vegetation
management.
FAC-003-1 lacks clarity that is essential for understanding what is necessary for compliance. The
proposed FAC-003-2 needs to be simplified to aid with field implementation and compliance
interpretation. Currently, it does not provide the clarity and simplification needed by Transmission
Owners and regulatory bodies to enhance reliability. Requirement 1.3: The proposed requirement
does not allow enough flexibility for making changes to the Annual Plan. We believe that changes to
the Annual Plan should be allowed even if that means delaying something until the next Annual Plan.
Our Proposed Changes: Have an annual plan that identifies the applicable lines to be maintained and
associated work to be performed. Adjustments to the annual plan are permissible. We believe that our
proposed language accomplishes the SDT's intent while allowing for appropriate flexibility.
Group
Western Area Power Administration, Rocky Mountain Region
Ron Turley
Western Area Power Administration, Rocky Mountain Region
Disagree
Use of the general term Bulk Electrical System creates unintentional confusion regarding the
applicability of this standard to lines operated at 200 kV or higher and designated lines operated
below 200 kV.
Agree
Agree
Agree
Disagree
Some areas such as highly developed urban areas, deserts, or grassland prairie may not be conducive
to tall vegetation growth and require frequent (annual) inspection.
Agree
Agree
The Technical Reference document could be expanded to explain that a well rounded Imminent Threat
Procedure should contain many mitigation alternatives to appropriately address a wide range of field
situations, including a "no immediate field action is required" option. For example, further
investigation of a potential imminent threat situation may reveal that the situation has been
erroneously reported or incorrectly measured and therefore no immediate vegetation removal actions
are required. A utility's Imminent Threat Procedure may also address situations beyond just
vegetation related incidents.
The specifics of a "plan" as required by R1.4 in version 1 of the Standards has been replaced with the
generalities of a "process" required by R1.5 in version 2 of the Standards. At the time of an audit, the
adequacy of a general process is harder to measure than the adequacy of the specific mitigation
measures that were previously required by R1.4 in version 1 of the Standards. It is unclear what an
auditor will be looking for to determine compliance with R1.5 - will the auditor be looking for
generalities or specifics? Further, if a utility has documented their interim corrective action process,
but it is not followed, is this a violation of the Standards?
Agree
Agree
Disagree
As discussed in the Technical Reference document, the CCZ is a complicated theoretical envelope
surrounding all rated operating positions of the conductor. Its dynamic shape is constantly changing
and is contingent upon location within the span. Calculation of the size and shape of CCZ is based, in
part, upon the design parameters of the transmission facility. However, as-built or long term
maintenance conditions can often diverge from the original design requirements over time. Ground
elevations can also change as a result of man made or natural causes from the original design
elevations recorded on plan and profile engineering drawings. Consequently, precise field
measurement of the as-built CCZ is extremely problematic and strategies that utilize the calculation
of allowable right-of-way tree heights can be hindered by unrecorded deviations from the original
design criteria. Allowable tree height strategies also become increasingly more difficult and
impractical with increasing extremes in terrain. While the CCZ is a very important concept for an
effective vegetation management program it is far to theoretical, dynamic, and impractical to field
measure for use as a clear and precise boundary for regulatory purposes. In addition, the R2
requirement for action when the imprecise and theoretical CCZ boundary is "approached" by
vegetation is an even more subjective and unmeasurable. The "rate of approach" is really the key
issue of concern. The rate of vegetation approach is a function of many variables including species
type and site specific growing conditions. For example, a Century Plant which can grow six inches a
day is obviously a much greater concern than a Lodgepole Pine on a dry mountain top which grows
only a few inches a year. As such, there is no practical way to define or measure for regulatory
purposes those "approach" situations that legitimately require immediate action from those
"approach" situations that do not. The wording and concepts of R2 are therefore to imprecise to be
used as clear requirements for Standards compliance.
Agree
Agree
Agree
Disagree
As discussed in the Technical Reference document and question #11 above, the CCZ is a complicated
theoretical envelope surrounding all rated operating positions of the conductor. Its dynamic shape is
constantly changing and is contingent upon location within the span. Calculation of the size and shape
of CCZ is based, in part, upon the design parameters of the transmission facility. However, as-built or
long term maintenance conditions can often diverge from the original design requirements over time.
Ground elevations can also change as a result of man made or natural causes from the original design
elevations recorded on plan and profile engineering drawings. Consequently, accurate field
measurement of the as-built CCZ is extremely problematic and strategies that utilize the calculation
of allowable right-of-way tree heights can be hindered by unrecorded deviations from the original
design criteria. Allowable tree height strategies also become increasingly more difficult and
impractical with increasing extremes in terrain. While the CCZ is a very important concept for an
effective vegetation management program it is far to theoretical, dynamic, and impractical to field
measure for use as a clear and precise boundary for regulatory purposes. As such, R4 as written
should be deleted from the Standards. Further, the requirement to provide evidence of something
that has not occurred (no vegetation encroachments of the CCZ) is also impractical. General industry
interpretation of R1.2.2 in version 1 of the Standards is that the specific Clearance 2 distance is the
precise boundary that is not to be encroached verses the broader area that is ultimately mapped out
as the conductor moves through "all rated electrical operating conditions". Only the Clearance 2
distance value is a clear, precise number that can be accurately observed and measured in the field.
If there is a persistence to retain the CCZ concept as a requirement within the Standards, the second
bullet option above regarding the initiation of the imminent threat process upon discovery of a
possible encroachment is the preferred option. Since a potential encroachment into the CCZ is not a
violation under this option, exact determination of the CCZ boundary is no longer as essential. Rather,
the focus is on triggering mitigation to vegetation problems to prevent outages. However, as with
question #11 above, there is still no practical way to determine for regulatory purposes those
"potential encroachment" situations that legitimately require initiation of the imminent threat process
from those "potential encroachment" situations that do not. Under this option the utility is really
motivated to initiate the imminent threat process to avoid an impending outage. As such, the
occurrence of an outage becomes the only clear, precise and observable means to determine a
Standards violation. A proposed alternative to ensure a level of reliability equal to or better than FAC003-1 is to retain the Clearance 2 requirement (without the imprecise "all rated electrical operating
conditions" language) in combination with the sustained outage requirements of R5, R6 and R7. If an
additional margin of safety is determined to be required, industry performance can be adjusted to
become more proactive by increasing the minimum Clearance 2 distance to a value greater than the
proposed version 2 Gallet equation (table 1) values. Thinking in terms of the CCZ concept, it is
obvious that a larger Clearance 2 value translates into a larger CCZ envelope. A larger CCZ envelope
in turn triggers mitigation for possible CCZ encroachments sooner.
Agree
Agree
1. Further clarification of the definition of the active right-of-way appears to be required. For example,
if a tree falls from an area controlled by the utility which is outside of the normal width of the actively
managed right-of-way, but this area is not reserved or "intended for other facilities", could this be a
violation of a Standards requirement? The narrative discussion within the white paper seems to imply
that it is not, but the "intended for other facilities" requirement within Standards definition implies
that it would be. 2. As currently presented, FAC-003-2 requires an impractical and unrealistic level of
performance from the industry. This level of performance is unwarranted for the overwhelming
number and expanse of transmission facilities to which the Standards are applicable. Many of these
facilities, such as radial load lines, are not critical TOT or IROL facilities and have a minimal impact on
overall grid reliability. The rigorous zero tolerance level of performance is only warranted for those
lines that are critical TOT or IROL facilities. 3. The Standards should clearly identify any and all
reporting requirements.
Individual
test
test
Agree
Disagree
Agree
Individual
Alice Druffel
Xcel Energy
Agree
Disagree
We propose adding the following language to the end of the definition for "Active Transmission Line
Right of Way": OR OTHER PURPOSES, REGARDLESS OF THE PREMISES DIMENSIONS IN ANY
EASEMENT, LICENSE AGREEMENT OR OTHER LAND RIGHT DOCUMENT.
Disagree
Add a note of exception to the requirement for inspections on those lines that do not have vegetation
management issues (e.g. lines that traverse desert areas only).
Disagree
The way this requirement is written may require a utility to prove a negative. In other words, prove
that we did not have trees encroaching into the CCZ at any time. This is impossible to prove. We
propose the following language: “The TO shall not have a encroachment within the CCZ which was
not dealt with by utilizing the imminent threat procedure before experiencing a Sustained Outage,
with the following exceptions 1) Encroachment of the CCZ that result for natural disasters 2)
Encroachment of the CCZ that result from human or animal activity."
Agree
We agree, however please add a reference to “wind gusts 45 miles per hour or greater†to the
exception note for this requirement. The exception would read “1) Sustained Outages of
transmission lines that result from sustained winds (45 miles per hour or greater) or gusts due to
natural disasters.â€
Attachment 1, Table I- Change the title of the table from "Proposed Minimum Vegetation Clearance
Distances" to "Critical Clearance Zone Distances". The reason being is that the general public could
interpret this table to mean that this is all the clearance that is required by a utility at the time of
pruning. Section C, Violation Severity Levels- There is some inconsistency between the C.2 chart and
the contents of the Standard and the White Paper. For example, the White Paper specifies that an
exception to an R6 blowing together violation would exist for sustained winds of gusts of 45 miles per
hour or greater. As to R7, the Standard itself notes that a violation only occurs if the vegetation
falling into the line is from within the ROW – C 2 does not incorporate that requirement. There are
two approaches: either note the exemptions within the C 2 chart, or add a footnote to the chart along
these lines: "This chart summarizes various provisions, the details of which are more fully set forth in
the Standard and White Paperâ€. We would recommend the later approach. General suggestions:
1) It appears that the FAC-003 Standard is the only "zero tolerance" standard, in some respects. Is
this reasonable? 2) There appears to be "advisory" language in this version of the Standard. This type
of language should be part of the White Paper, not the Standard itself. 3) Utilities need more support
from FERC to deal with regional roadblocks within the USFS regarding the implementation of IVM. The
Memorandum of Understanding is not universally accepted within all regions of the USFS.
Individual
Jeff Hackman
Ameren
Disagree
By definition, the capitilized term, Bulk Electric System, is defined to include most facilities 100 kV
and above. The previous version of this standard appropriately restricted the applicability of the
standard to those facilities operating above 200kV and any additional facilites identified by the
Regional Reliability Organization as critical. This new version of the standards attempts to limit the
100-200 kV class applicability by having the RC identify the critical facilities. We believe the change
creates unnecessary and undesirable confusion in that one requirement of the standard says that it
applies to all the BES and then another requirement limits the application. Leaving the term "electric
transmission systems" in the definition is preferable to that proposed.
Disagree
While the RC would seemingly have the wide area view to make the assignment appropriate, the
standard is really trying to determine the entity who can assess the risk to the BES of a vegetationrelated outage. The management of that risk is in the venue of the Transmission Planner who, in the
long term, designs the system and, in the Operating Horizon, establishes the parameters of operation
that will lead to reliability. Certainly, the RC is preferable to the RE (RRO). However, the TP is
preferable to the RC.
Agree
Agree
This is a good change from a compliance perspective; the documentation requirements can now be
assigned lower VRFs than the implementation requirements
Agree
Agree
Disagree
Transmission Owners should have a Vegetation Imminent Threat Procedure, and "Vegetation
Imminent Threat" should be a defined term, defined as: "Vegetation observed in the field encroaching
upon a conductor within a distance defined in the Vegetation Management plan." In this case, the
threat would require an immediate response and would include communication to the Transmission
Operator. From there, the actions that the operator decides to take will be dependent on the incident
and system conditions. We do not need to be prescriptive with this requirement but rather allow the
Transmission Operator and appropriate field personnel the flexibility to make the right decisions to
safely, promptly and appropriately remove the vegetation threat. From a Transmission Owner's
perspective, many situations can constitute an imminent threat but this approach will clearly define a
"Vegetation Imminent Threat" as it relates to the Purpose of this standard. While a definition of
"Vegetation Imminent Threat - Vegetation observed in the field encroaching upon a conductor within
a distance that is twice the Gallet clearance distances referenced in Table I of the draft standard FAC003-2" would be acceptable and far superior to that which is proposed, it will still be difficult for field
personnel to identify, at each foot of a transmission circuit, wherein twice the Gallet distance would be
found. See comment on #11 below.
Agree
Agree
Agree
Disagree
The CCZ is a good theoretical concept to aid industy in understanding the overall movement of
conductors, but it is an impractical concept for field application. Due to the variability in the size of
the CCZ as you move along a conductor, as well as changes from span to span or even line to line
due to design parameters, loading or weather-related issues, the CCZ concept should not be tied to
an imminent threat procedure. Vegetation "approaching" the CCZ does not constitute an imminent
threat. In fact, the moment after vegetation is cut, it begins again to "approach" this zone. It may be
months to years before this vegetation ever gets to a proximity distance from the conductor to be
within a "spark-over" distance as defined by the Gallet equations. Requirement R2 should support the
purpose of this standard by requiring implementation of the Vegetation Imminent Threat Procedure
when the Transmission Owner has visual, field knowledge that vegetation is encroaching upon a
conductor within some specific distance. As R2 is currently stated, a Transmission Owner cannot
comply with R2 unless the imminent threat procedure is continuously being implemented, because
vegetation that is growing is always approaching the CCZ. "Approaching the CCZ" cannot be the
trigger for implementation of the Vegetation Imminent threat Procedure. Instead, the trigger should
be an encroachment within some observed field distance.
Agree
Agree
Agree
Disagree
The second bulleted alternative above is the best approach, but it should be improved by changing
the imminent threat trigger from "encroachment of the CCZ" to "encroachment within some observed,
field distance that is defined in the Plan. This would allow Transmission Owners to define for field
personnel a CCZ that accomplishes some multiple of the Gallet distances referenced in Table I" but is
easy to determine and apply. We have recommended changes to accomplish this in Requirement R2
(see our response to Question #11 above), and R4 should simply be deleted. While the CCZ is
valuable to understanding the movement of conductors, it cannot be readily applied in the field. This
field application challenge is noted in the Technical Reference Document (pages 29 & 30). The way R4
is currently stated, the Transmission Owner would be in violation of R4 for any CCZ encroachment not
due to natural disasters or human or animal activity. This would include a tree falling from outside the
right of way corridor that passes through the theoretical CCZ. Furthermore, Transmission Owners
would be required to self-certify compliance with R4, and we don't think there's any way to do that.
Clearly the approach of assessing violations for CCZ encroachment is unworkable. Likewise, the third
alternative listed above is untenable. The tiered approach could have a mitigating effect on violations,
but it would require the same inspection effort and postponement of vegetation management that
makes the first alternative unworkable. Both the first and third alternatives would require very
significant additional expenditures for surveys and documentation in an impossible attempt to certify
compliance - money that would be better spent controlling vegetation.
Agree
Agree
We recommend striking, or modifying, the words "within the extent of its easement and/or legal
rights" as they may be introducing an unintended compliance quagmire. For example, if the easement
is extraordinarily wide but reliability and the work plan do not dictate that the work plan apply to the
entire easement, how will compliance be measured? The work plan should recognize easement or
legal rights issue. Therefore, the emphasis for this requirement shoudl be to execute the annual work
plan. The white paper already speaks to the point that it is a best practice for utilities to exercise their
legal rights. By tagging the words on to the requirement, we are adding unnecessary compliance
validation to this requirement for both industry and the regulators. If a clarifying sentence is required,
we would suggest that R8 stop with the word standard and a new sentence be added, "The work plan
should address easement or legal/rights"
While FAC-003-1 lacks clarity that is essential for understanding what is necessary for compliance,
the proposed FAC-003-2 needs to be simplified to aid with field implementation and compliance
interpretation. Currently, it does not provide the clarity and simplicity needed by Transmission
Owners to implement and regulatory bodies to monitor in a manner that will enhance reliability.
Individual
John Humphrey
Nebraska Public Power District
Disagree
NPPD disagrees with the change to bulk electric system, because it creates confusion on the
applicability. This standard only applies to certain lines and not the entire (bulk) system.
Agree
NPPD agrees that the Reliability Coordinator is the correct body for identification of any sub 200kV
lines that would be subject to this standard.
Agree
Agree
Agree
Agree
Disagree
NPPD agrees that a Transmission Owner should have an imminent threat procedure and the TO be
immediately notified of any threats. NPPD disagrees with prescribing what needs to be done as a
result of the threat. This is condition based and staff can make the right decision as to what corrective
actions are necessary.
Agree
Agree
Agree
Disagree
The CCZ is a good concept to explain the flight path of a conductor under all conditions but it would
be impractical to use in the field. There are too many variables to consider and an encroachment does
not constitute an immediate threat.
Agree
Agree
Agree
Disagree
NPPD disagree with an encroachment being a violation. A lot of time would need to be spent to
determine if an encroachment occured and in a self regulating environment, reporting would be
miminal if any. The Transmission Owner would be in violation for any non natural event. Even a tree
falling into the ROW passing through CCZ would be in voilation of R4. Difficult at best to enforce. We
need to spend time keeping the ROW cleared and less time inspecting for possible encroachments.
Agree
Agree
Group
Progress Energy Carolinas
Jack Gardner
Transmission Operations and Planning Department
Disagree
The intent of the revision of the standard was to bring clarity to the standard. Referring to the BES in
the purpose creates confusion as to the applicability of the standard. Therefore, Progress Energy
recommends the continued use of the term "electric transmission systems."
Agree
While Progress Energy agrees that the RC is the appropriate entity, the drafting team should consider
including a dispute resolution requirement for those instances when the Transmission Owner and the
Reliability Coordinator disagree as to which lines below 200 kV should be included.
Agree
Disagree
The sub-requirements should be moved up to requirement level if the team desires to have different
VRFs and VSLs.
Agree
Agree
Annual Plan should be a defined term in the standard. Without a definition, the term may be
interpreted differently by industry and the regulator. The drafting team should raise the prominence
of annual plan and define the attributes of an annual plan.
Disagree
Progress Energy agrees with the need for a Transmission Owner to have an Imminent Threat
Procedure and that the Transmission Operator should be immediately notified of imminent threats but
only when it is appropriate as defined by the TO's imminent threat procedure. We disagree with the
requirement to immediately communicate with the Transmission Operator whenever the Critical
Clearance Zone is approached. Not every scenario is an issue that requires action by the Transmission
Operator: It is possible that the CCZ is being approached by vegetation at the lowest point of the CCZ
whereas the conductor may be at its highest point in the CCZ (potentially 30 feet away from the
vegetation) -- This typical situation does not merit notification to the Transmission Operator (which is
required by FAC-003-2 as currently written).
Agree
Agree
Agree
Disagree
The Critical Clearance Zone as currently defined is too academic. Implementation of R2 would require
field operations staff to determine the theoritical position of the line during inspections to decide
whether to engage the imminent threat procedures. The academic/theoretical aspects of the Critical
Clearance Zone definition are not practical or enforceable. The criteria for a violation needs to be
limited to the position of the conductor in real time.
Agree
Agree
Disagree
The standard has established a threshold of compliance. For consistency, compliance should be
measured at the threshold not a Registered Entities program requirement.
Disagree
The definition of Critical Clearance Zone includes too many academic and theoretical elements. It is
impossible to provide evidence that vegetation did not encroach into the the Critical Clearance Zone
during TVMP cycles. Furthermore, the operations staff performing periodic ground and aerial
inspections would need to determine the CCZ for each foot of transmission line to assure compliance
with the standard as it is currently written. The CCZ concept can neither be implemented or enforced
as written. The CCZ refers to Ratings which is defined in the Glossry of Terms as "The operational
limits of a tranmsission system element under a set of specified condiditons." This definition is too
broad to be a consistently enforceable term from one utilitly or region to the next. As it is currently
written, no exemption exists for vegetation falling from outside the Active Transmission Line Right of
Way into, or lodging in, the theoretical CCZ.
Agree
Agree
To avoid interpretation errors and provide clarity, the Applicability section for Facilities (4.2) of FAC003 should include a statement that the standard only applies to vegetation within the Active
Transmission Line Right of Way. For example, a fall-in from outside of the Active Transmission Line
Right of Way that causes a sustained outage is not a violation of this standard. Any
encroachment/outage initiated by vegetation falling from outside of the Active Transmission Line
Right of Way should be excluded from violations. The CCZ concept is academically elegant, but when
applied in the field, it presents significant implementation, interpretation and enforcement issues: the
complexity of determining compliance could have the unintended negative consequences to reliability;
removal of vegetation will likely be delayed because of the complexity and accuracy required to
determine compliance prior to tree removal; certification that no violations have occurred will require
lengthy and costly calculations and survey measurements; the standard refers to Ratings in the
determination of line sags and Ratings is not a tightly defined term, PRC-023 requires relays to hold
lines in beyond the line Ratings; how will PRC-023 requirements be factored into the CCZ concept.
The CCZ concept introduces more complexity and ambiguity into the standard than it resolves. The
drafting team needs to develop an alternative to the CCZ concept that is simple, easy to apply and
clearly defines at what point a violation occurs. There are over 158,000 line miles of AC Transmission
above 200kV in the United States, covering a Right of Way area potentially as large as 3,000 to 4,000
square miles (an area roughly equivalent to Rhode Island and Delaware combined). With billions of
stems of managed vegetation, in and along the right of way, even six-sigma performance would
result in a number of outages on a system this large. With countless VM processes and assessments
that take place daily, it is unrealistic/unreasonable to expect zero-tolerance for random vegetation
events (the transmission system is planned/operated to handle at least any single contingency).
Group
Southern California Edison Company
Samuel Stonerock
Transmission / Distribution Business Unit
Agree
Q1: SCE agrees in part with the proposed revisions to the purpose statement. However, we believe
the phrase "vegetation related outages" is unnecessarily vague. Based on the content of certain
requirements in Version 2, the intent of this standard is and should be to prevent sustained outages
due to vegetation-to-line contacts. SCE respectfully suggests the purpose statement (A3) be revised
to read: "To improve the reliability of the Bulk Electric System by preventing vegetation-to-line
contacts that could lead to Cascading.â€
Agree
Q2: No comments.
Agree
Q3: No Comments.
Disagree
Q4: SCE does not agree with separating the documentation and implementation aspects of the TVMP
into separate requirements R3 and R8 (respectively). SCE believes that proposed R3 and
corresponding M3 should be eliminated and replaced with a modified version of proposed R8. SCE
respectfully suggests that proposed R8 be revised to read: "Each Transmission Owner shall implement
and follow its Vegetation Management Program to the extent allowed by existing easement and/or
legal rights."
Disagree
Q5: SCE does not agree with imposing a one-size-fits-all inspection frequency of “at least once per
calendar year†upon all U.S. Transmission Owners. The associated technical paper presents no
credible evidence or statistical corroboration to support the proposed inspection frequency. Until such
time as a thorough industry study or similar evidence is presented that demonstrates the proposed
inspection frequency is cost effective and will enhance system reliability, Transmission Owners should
be allowed to establish their own inspection frequency rate. Regarding the enforcement of a nonstandardized inspection frequency, should a Transmission Owner incur a vegetation-to-line contact
that results in a Sustained Outage, upon review of the investigation results, the responsible Reliability
Coordinator and/or NERC could then impose a more stringent inspection frequency requirement upon
the infracting Transmission Owner. The imposition of more stringent inspection frequencies could be
applied on a temporary or permanent basis, depending on the severity of the outage, but lacking a
demonstrated need, good performing Transmission Owners should be allowed to establish their own
inspection frequencies based upon their individual needs and operating conditions. SCE respectfully
suggests R1.2 be revised to read: "Specify a vegetation inspection frequency that takes into account
local and environmental factors."
Agree
Q6: SCE agrees in part. Proposal R1.3, requiring Transmission Owners to establish an annual
maintenance plan is generally acceptable. However, SCE disagrees with including peripheral
information in R1.3 and the institution of a separate implementation requirement (R8). Further, we
note that some portions of FAC-003-1 (R2) appear to have been transplanted into proposed R1.3 and
that the word “shall†has been replaced with the word “shouldâ€. SCE believes that
inserting the word “shall†into statements that are clearly advisory in nature does not
necessarily create enforceable requirements. As proposed, an enforcement auditor might incorrectly
determine that the new “requirement†statements in proposed R1.3, describing the need for
“flexibilityâ€, “consideration of permitting and scheduling requirementsâ€, and selfdetermined “methodologies†is a comprehensive list of items for the maintenance plan.
Because this list of program elements is not complete, SCE recommends all text following the opening
sentence be removed from R1.3 and inserted into the supporting technical paper. SCE respectfully
suggests that R1.3 be revised to read: "Specifies a plan that identifies the applicable lines to be
maintained and associated work to be performed."
Agree
Q7: SCE agrees in part with the content of R1.4 because of its similarity to existing requirement R1.5
in FAC-003-1. However, we disagree with the drafter’s inclusion of peripheral information
following the first sentence. We also note that the second sentence of proposed R1.4 includes both a
requirement and a recommendation. SCE believes this and similar recommendations are best suited
for the supporting technical paper. SCE respectfully suggests that R1.4 be revised to read: "Specify a
process or procedure for communicating an impending vegetation-to-line contact that may result in a
sustained outage and the appropriate response measures.â€
Agree
Q8: SCE agrees in part with the revisions to R1.5, including the proposed phrase "corrective action
process". However, we do not believe it is necessary to include the term "Transmission Owner" in the
sentence because the entire standard is clearly applicable to Transmission Owners. SCE respectfully
suggests that proposed R1.5 be revised to read: "Specify an interim corrective action process for use
when planned vegetation maintenance is deterred."
Agree
Q9: No comments.
Agree
Q10: No comments.
Agree
Q11: SCE agrees in part with proposed R2. The use of the Gallet equation and the replacement of the
existing Clearance 2 requirement with the Critical Clearance Zone is acceptable. However, SCE
strongly disagrees with establishing a separate requirement for implementing an imminent threat
procedure should there be an encroachment of the Critical Clearance Zone because it forms the basis
of an unnecessary zero-tolerance enforcement policy. Read in context with corresponding Measure 2,
R2 appears to require Transmission Owners to prove that a Critical Clearance Zone encroachment did
or did not occur and also prove that that an imminent threat procedure was or was not properly
invoked. Although SCE agrees that CCZ encroachments should be addressed timely, we disagree with
the notion and underlying assumption that a CCZ incursion will always lead to a flash-over or a
vegetation-to-line contact. If the goal of FAC-003-2 is to prevent sustained outages (due to
vegetation-to-line contacts) that could lead to Cascading, emphasizing “prevention†is
understandable, however, enforcing prevention measures is an entirely different matter. Under the
proposed requirements, a vegetation-to-line contact could conceivably represent two distinct
violations of FAC-003-2. SCE believes this type of regulatory double jeopardy is patently unfair and
forcing Transmission Owners to prove a CCZ encroachment did or did not occur is equally unfair and
unenforceable. Because R1.4 adequately addresses the Transmission Owner’s responsibility
regarding the implementation of an imminent threat procedure, SCE respectfully recommends that
proposed R2 and corresponding M2 be removed from FAC-003-2.
Agree
Q12: No comments.
Agree
Q13: No comments.
Disagree
Q14: SCE does not agree with the inclusion of proposed R3 and believes it should be replaced with a
modified version of proposed R8. SCE respectfully suggests that proposed R8 be revised to read:
"Each Transmission Owner shall implement and follow its Vegetation Management Program to the
extent allowed by existing easement and/or legal rights."
Disagree
Q15: SCE does not agree that proposed R4 was written in the most effective way because it
establishes a zero tolerance enforcement policy. SCE agrees that a CCZ incursion should be addressed
promptly, but we do not agree that a CCZ incursion is equivalent to a vegetation-to-line contact, or
that a CCZ incursion represents an imminent threat of flash-over. As written, proposed R4 would
require Transmission Owners to prove that a Critical Clearance Zone incursion has not occurred. Short
of a daily ground or aerial inspection of every applicable transmission line, it is clearly impossible for a
Transmission Owner to monitor their active Right of Way on a 24/7/365 basis to ensure a CCZ
incursion will not or has not occurred. Bearing in mind that even the most robust of Transmission VM
programs may occasionally identify an anomalous condition (in or outside the active ROW) that left
untreated could lead to a flash-over or vegetation-to-line contact, the identification of such conditions
typically occur during scheduled aerial or ground patrols and addressed timely. Of the two alternatives
offered, SCE finds the first option (second bullet item) to be the most palatable. However, even that
option leaves significant doubt as to practical enforcement, because a Transmission Owner could still
be found in violation of two separate requirements (R4 and R5, R4 and R6 or R4 and R7) should a
vegetation-to-line contact (resulting in a sustained outage) occur. This situation amounts to
regulatory double jeopardy. SCE believes that by any reasonable legal or regulatory measure,
requiring a Transmission Owner to prove that a CCZ incursion did not occur is impractical and virtually
impossible to enforce in a fair and impartial manner. Further, SCE believes that proposed R4 and
corresponding M4 detracts from the purported goal of FAC-003-2 and should be removed.
Agree
Q16: SCE agrees in part with the establishment of R5, R6 and R7, however, we note that the opening
of each requirement repeats a slightly altered version of the FAC-002-2 purpose statement. We find
such repetitiveness unnecessary and note that as written, Requirements 5-7 presents a near identical
compliance conundrum for Transmission Owners as Requirement 4. Again, Transmission Owners
would be required to prove that they did not incur a sustained outage due to a vegetation caused
flash-over or vegetation-to-line contact whether it be a grow-in, blow-in or fall-in. Although proving a
sustained outage (for cause) did not occur will be difficult and unwieldy, it is not impossible. The
simple difference between a Transmission Owner disproving the occurrence of a CCZ incursion and
their disproving vegetation caused sustained outages, is that Transmission Owners do in fact keep
records of “outagesâ€. Because a Transmission Owner’s record keeping prowess is the only
viable option for proving a vegetation caused outage did not occur, SCE respectfully suggests R5, R6
and R7 be revised to read: R5 - "Each Transmission Owner shall document Sustained Outages of
applicable lines due to vegetation growing into a conductor operating within its Rating with the
following exceptions:" R6 - "Each Transmission Owner shall document Sustained Outages of
applicable lines due to vegetation blowing into a conductor operating within its Rating and located
within an Active Transmission Line Right of Way with the following exceptions:" R7 - "Each
Transmission Owner shall document Sustained Outages of applicable lines due to vegetation falling
into a conductor operating within its Rating and located within an Active Transmission Line Right of
Way with the following exceptions:" We also note that Footnote 6 is misplaced in the draft and should
follow the word “Outages†in each of these requirements.
Agree
Q17: SCE agrees in part with the inclusion of R8, however, we believe R8 should be revised and
renumbered to replace proposed R3. In SCE’s view, the act of implementing a Transmission VM
program encompasses both inspection and maintenance activities. SCE respectfully suggests that
proposed R8 be revised to read: "Each Transmission Owner shall implement and follow its Vegetation
Management Program to the extent allowed by existing easement and/or legal rights."
SCE notes that Section C (Compliance) is incomplete and that the associated levels of NonCompliance listed in FAC-003-1 may be different from those proposed for FAC-003-2. SCE reserves
the right to revise its initial comments and submit additional comments regarding the requirements,
measures and compliance portions of FAC-003-2.
Group
SERC OC Standards Review Group
Jim Griffith
Southern Company
Disagree
The following comments are supplied by the SERC OC Standards Review Group (OCSRG): The
definition of the Bulk Electric System generally does not include radial transmission lines directly
serving load. The current standard covers all 200 kV and above transmission lines along with those
lower voltage lines designated by the RRO while the BES includes all lines 100 kV and above. Use of
the term Bulk Electric System will cause unnessesary confusion to the industry concerning
applicability of this standard. Therefore, the SERC OCSRG recommends the continued use of the
undefined term "electric transmission systems."
Disagree
The SERC OCSRG does not believe that the RC is the appropriate entity to identify sub-200 kV
transmissions to be subject to this standard. Vegetation Management programs are longer than the
normal operating horizons of RCs. We believe that the proper function to identify sub-200 kV
transmission lines subject to this standard is the Planning Coordinator. This must be consistent with
PRC-023, Requirement 3. We also recommend that a process be established for dispute resolution.
NERC should develop a comprehensive approach to the determination of "critical" facilities rather than
pushing a piecemeal approach as evidenced by this standard and PRC-023, among others.
Agree
Agree
Disagree
While the SERC OCSRG agrees with this requirement in general, there may be areas (e.g., desert
terrain) where an annual interval would be unnecessary and not cost effective.
Agree
Disagree
The Requirement as written is too prescriptive and is open to interpretation from an audit perspective
with use of the term “immediate†communication and a partial list of activities. Due to
limitations of communication capabilities in the field, "immediate" may not be practical. While the
White Paper provides insight into what is accceptable communications to the Transmission Operator,
the standard is less prescriptive in describing what is an acceptable communication path to the
Transmission Operator. We recommend better descriptions in VSLs, measures and the RSAW as to
what is acceptable. Many conditions or threats, requiring immediate removal, would not require
communcation with the Transmission Operator, who is not an applicable entity for this standard. The
SERC OCSRG recommends that R1.4 be deleted. Since this is a "zero tolerance" standard any
Transmission Owner will remove any discovered threats to prevent outages. If R1.4 is not deleted,
the SERC OCSRG believes that imminent threats should be a defined term. The definition should be as
follows: “Imminent Threat: A vegetation condition which, if not addressed, will place a
transmission line at an immediate risk of a Sustained Outage.â€
Agree
Agree
Agree
Disagree
The SERC OCSRG recommends that R2 be deleted. Since this is a "zero tolerance" standard any
Transmission Owner will remove any discovered threats to prevent outages. While we agree that the
implementation of an imminent threat procedure may be a valid concept, visualization of the Critical
Clearance Zone and determining an approaching encroachment is a practice in application of
theoretical conductor locations in real time.
Agree
Developing minimum sparkover distances in this standard is a superior approach for the stated reason
in question 12. In addition, referring to tables and values in another standard is problematic if the
referenced standard is revised and the tables are re- numbered or deleted altogether. The SERC
OOCSRG suggests that the tables based on the Gallet equations be removed from the standard and
be kept in the technical white paper solely to assist in developing a common understanding of the
threshhold for taking actions.
Agree
See comments in #12 above.
Agree
Disagree
The requirement, as written, compels the Transmission Operator to allocate precious resources to
ensuring that a vegetation encroachment NEVER will occur on any transmission line, regardless of
that line's true importance to maintaining electric transmission system reliability. All lines are not
created equal; only those that are involved in IROLs should be held to a zero tolerance standard. R4,
if retained, should begin with "Subject to its legal rights," and insert the word "vegetation" between
prevent and encroachment. Vegetation, which falls through the Critical Clearance Zone or falls to
lodge within the Critical Clearance Zone, should not be included as violations of the Critical Clearance
Zone. The concept of the Critical Clearance Zone is useful as a mental model to visualize required
vegetation management work. While this is a good conceptual tool to drive consistent terminology
and proper vegetation management practices, it remains theoretical in nature and impractical to
measure on a span by span basis. The complexity of determining an encroachment into the Critical
Clearance Zone is overly burdensome due to the need for survey accuracy measurements and
engineering evaluations. In addition, this complexity leads to questions about the ability to audit this
requirement. These complexities introduce reliability and audit issues when encroachments into this
conceptual area are defined as violations. The SERC OCSRG believes the Sustained Outage, as
defined by other measures in this standard, should be the non-compliance measure. We suggest that
the Critical Clearance Zone concept be kept in the technical white paper and that all references to the
Critical Clearance Zone be removed from the body of the standard. R5, R6, and R7 ensure that
version 2 of the standard has reliability requirements equal to version 1; therefore R4 should be
removed.
Disagree
R5, R6 and R7 should begin with "Subject to its legal rights,". The requirements, as written, compel
the Transmission Operator to allocate precious resources to ensuring that a vegetation outage NEVER
will occur on any transmission line, regardless of that line's true importance to maintaining electric
transmission system reliability. All lines are not created equal; only those that are involved in IROLs
should be held to a zero tolerance standard. R5, R6, and R7 ensure that version 2 of the standard has
reliability requirements equal to version 1; therefore R4 should be removed.
Disagree
The SERC OCSRG suggests that the Requirement be reworded to read: “Each Transmission Owner
shall implement its annual work plan for vegetation management within the Active Rights of Way."
Any further verbiage is confusing, ambigious or unnecessary.
The SERC OCSRG recommends that the definition of "Active Rights of Way" be revised as follows: "A
strip of land, designated by the Transmission Owner, that is occupied by active transmission facilities.
This corridor does not include the inactive or unused part of the Right of Way set aside by the
Transmission Owner for other facilities or uses." The SERC SOSRG recommends that this standard
should exclude radial to load facilities and, for consistency, all 200 kV and above lines should not be
included in the standard unless they meet the same requirements as sub 200 kV lines.
Individual
Jonathan Appelbaum
Long Island power Autority
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Disagree
The Standard is about preventing outages and having an effective program. An effective program
should allow for the identification of a threat and the removal of the threat prior to a vegetation
caused outage. I prefer alternative 2. If a vegetation caused outage should occur or if the Regional
Entity determines a violation occurred based on a compliance investigation then the entity is in
violation of this requirement.
Agree
Agree
1) Disagree with R1.1. The proposed standard is too lenient on the program documention required for
an effective program. R1.1 should include the words " the program will document the program
objectives, method of site evaluation, the definition of action thresholds, the control methodologies,
and how the monitoring program is established". There is a wide gulf between listing IVM
methodologies and a vegetation proram implementing A300. 2) CHANGE: Within Applicable Facilities
listed in section 4.2 the phrase Transmission Line should be changed to Overhead Transmission Line.
The NERC Glossary definition of transmission Line is: " A system of structures, wires, insulators and
associated hardware that carry electric energy from one point to another in an electric power system.
Lines are operated at relatively high voltages varying from 69 kV up to 765 kV, and are capable of
transmitting large quantities of electricity over long distances." The accompanying white paper states
the standard is addressing the impact of vegetation growth on overhead transmission lines. The intent
of this standard is the development and imlementation of a vegetation management program for
overhead transmission lines only. By specifically stating "overhead transmission lines in Section 4.2
there will be no possibility of an occurrence of an auditor requesting a vegetation management
program for underground lines.
Individual
Robert (Bob) B. Suedkamp
USDA Forest Service, Southwestern Region, Regional Office for AZ and NM
Agree
Agree
Agree
My disagreement with R1
Agree
Disagree
It would seem also that the T.O. should be expected to react to circumstances that create the need
for a more frequent inspection cycle such as conditions that cause widespread vegetation mortality
such as drought and/or beetle infestations.
Disagree
I think that the Transmission Owner should be able to specify the effective period of the plan whether
it is one year or ten years. Arizona utilities are starting to think in terms of multi-year corridor
management plans. A one year planning period could be specified as the minimum planning period.
Agree
The USFS would be expecting the Transmission Owner to be documenting the imminent threat
procedures in an operating plan or corridor management plan that would be approved by the
designated USFS decision maker. If such procedures are documented in the Transmission Owner's
TVMP and are compatible with USFS resource management direction, then the imminent threat
procedures could be incorporated in the agency-approved operating plan by reference. If the
Transmission Owner disputes any restrictions that are placed by the USFS on the imminent threat
procedures, the USFS has an administrative appeals process which the Transmission Owner can use,
but those procedures can be time-consuming and probably would not be perceived by the
Transmission Owner as being neutral for negotiation purposes. It might help if a third federal party
like NERC could help resolve disputes between the Transmission Owner and the USFS on the
imminent threat procedures. Although the USFS would object to unreasonable intrusion of NERC into
normal USFS land management prerogatives, imminent threat procedures would seem to be a topic
for which NERC should take a very strong position, especially with a standard that identifies minimum
vegetation clearances as related to prevention of arcing potential, or in other words, vegetation that
should be considered hazardous and in immediate need of treatment.
Agree
In my opinion, problems between the Transmission Owner and the USFS over the TVMP should be
worked out before a TVMP is ever finalized. A dispute resolution process outside the control of either
party would be very helpful and would probably facilitate quicker solutions than if the Transmission
Owner and the USFS are left to work out problems on their own. If a TVMP is prepared in a vacuum,
the problems may not come to light until some kind of outage actually occurs. It would be much
better to flush any disagreements and deal with them before any outages actually occur.
Disagree
If it is possible for NERC to identify minimum clearance standards as related to arcing potential for
hazardous vegetation, it would definitely help USFS field administrators to have some kind of hard
and fast standards. If that kind of approach is not reasonable in light of the need to adjust standards
for various load conditions and vegetation growth rates, then a prescribed formula for calculating
minimum clearances would be the next best thing.
Disagree
Perhaps standard M8 could be expanded or clarified to require the Transmission Owner to describe
how employees, especially field supervisors, are trained to implement the plan and to prove that the
training was actually provided. Some problems have arisen in the USFS Southwestern Region because
some Transmission Owners are not providing adequate supervision of field work.
Agree
Attachment 1 is very conservative. I think that the clearance distances shown on the attachment
should be expanded to create, in effect, a standard that reflects maximum line loading and maximum
line sag. I would also like to see some flexibility built into the process so that the Transmission Owner
and the USFS could negotiate some consideration for vegetation growth rates. The end result would
generate a standard that would give the Transmission Owner the security of knowing that vegetation
would not grow into the potential arcing zone for some reasonable amount of time - some kind of
entry cycle.
Agree
See comment for Question 11.
Don't know!
Agree
Disagree
The wording appears too strong. Who can predict the unforeseen circumstances that inevitably arise.
If the standards require the reporting of encroachments, the ensuing report can help determine if the
Transmission Owner did everything reasonable to avoid the problem. It seems like the standard
should be written to require the Transmission Owner to do everything reasonable to avoid the
problem. A judgement call would still be needed to evaluate the performance.
Disagree
I believe that the text for each element should be re-written with the general philosophy that the
Transmission Owner shall do everything reasonable to prevent such problems in line with the
comment for section 15. Problems should be reported and investigated and a judgement call should
be made about whether the Transmission Owner did everything reasonable to avoid the problem.
Disagree
This standard needs to be broadened to include evaluation of the good faith efforts by the
Transmission Owner to coordinate with the USFS on development of the work plan. A mechanism
should be developed to allow the Transmission Owner to evaluate the good faith efforts of the USFS.
I'm having trouble getting comments to "stick" in this section of the form. I have a general concern
with the opening paragraph of R1. The wording seems to encourage a Transmission Owner to develop
a TVMP in a vacuum. The US Forest Service defintely wants input into the development of an annual
work plan and USFS land use authorizations include a requirement for USFS approval of vegetation
management plans. It seems much more reasonable to require the TVMP to reflect USFS or any other
landowner resource management considerations. This tactic would require more "up front" work, but
the end result is a plan which would reflect reasonable landowner input and where the disagreements
could be settled ahead of time rather than being left for the night shift. I also believe that some kind
of dispute resolution process is needed outside the control of either the Transmission Owner or the
USFS. I think that NERC could fill that role very well.
Individual
Kris Manchur
Manitoba Hydro
Disagree
Manitoba Hydro disagrees with changing "electric transmission systems" to "Bulk Electric System"
because BES applies to facilities 100kV and above which may not have an impact on system
reliability.
Disagree
Manitoba Hydro disagrees that the RC is appropriately positioned to identify and designate any sub200kV lines that should be subject to this standard. Lines below 200kV should include only those that
are currently classified as Interconnection Reliability Operating Limit (IROL) lines which are already
defined and listed for registered entities. As such R9 and R10 should be eleiminated from this
standards along with the RC in the applicability section.
Agree
Agree
Agree
Agree
Agree with the seperation - but suggest that the time horizon of one year be removed as some
changes may push the work beyond the curent planning year.
Agree
Suggest removing, "and may include actions such as a temporary reduction in line rating, switching
lines out of service, or other actions", as this is outside the scope of a vegetation management
program.
Disagree
Agree with the change in terminology - but would suggest that wording clarify that this is not only for
situations where the utiity is unexpectedly prevented from implementing its annual plan - but also for
areas where it is unable to implement its clearance requirements due to property rights limitations.
Agree
Agree
Disagree
The imminent threat process trigger should be well defined, and the vague "approaching" terminology
needs to be changed. Imminent threat implies and that an elevated risk of contact exists. That is not
the case if the vegetation is merely approaching the CCZ. The objective of the overall Vegetation
Management program is to prevent an encroachment. The imminent threat procedure should be
triggered by discovery of an encroachment into the CCZ. Even when an actual encroachment into the
CCZ occurs - while the odds of an outage event have increased - the likelihood of a contact is still
minimal, as other environmental factors still need to be in place (ie. high temperature and/or high
wind conditions). If this approach to an imminent threat process trigger, then the violation of this
requirement implies a violation of R4, which prohibits the encroachment of the CCZ, and therefore
either R2 or R4 could be removed, or they could be combined into one requirement.
Agree
Disagree
Manitoba Hydro has historically designed the ROW clearance requirements based on an operating
limitation of not switching during extreame wind conditions, therefore, beyond a wind presure of 230
Pa, our design doesnot account for switching surge overvoltages. We do howerver, agree with the use
of overvoltage factors as described above for wind conditions of less than 230 Pa.
Agree
Disagree
Manitoba Hydro asserts that the reliablity of the system is measured by outage, not by the possiblity
of an outage, and therefore if the overall vegetation management system (plan-patrol-discovermitigate) is effetive in preventing an outage, then the reliablity of the system has been maintained,
and the intnent of the reliablity standard achieved. Therefore, we propose that the second bullet
above is the prefered alternative, and that R2 and R4 be combined as the violation of R4 would then
imply a violation of R2.
Agree
Agree with splitting the various events. We note that there is no specific requirement to actually
report an outage. The Requirements say that we should Prevent Sustained Outages, but not actually
report sustained outages should they occur. In version 1, R3 clearly stated that the Transmission
Owner shall report.
Agree
Individual
Jianmei Chai
Consumers Energy Company
Disagree
Consumers Energy disagrees with changing the current "electric transmission systems" to "bulk
electric system". This change will create confusion and can lead to a discrepency concerning lines
operating below 200kV that may be included in the "bulk electric system" but are otherwise excluded
from this standard.
Agree
Agree
Agree
Disagree
FERC required NERC in Order 693 to develop appropriate inspection cycles based on local factors.
Potential annual tree growth varies considerably within the geography of the United States and FAC003-1 recognized this factor and left it up to the utility to determine the most appropriate inspection
cycle for their system. This was in lieu of having proper data readily available to determine inspection
cycles for various areas that could be incorporated into the standard. FAC-003-2 greatly decreases
the minimum separation distance between conductors and vegetation. Table 1 shows the minimum
distance at sea level for a 345 kV line a 3.12 feet. This is considerably less than the potential annual
growth rate of many tree species in many areas of the United States. Therefore, the annual inspection
cycle would not be acceptable to identify tree growth that can violate the minimum distance before it
occurs. Consumers Energy strongly believes that using the Gallet formula to determine the minimum
clearance between conductors and vegetation will decrease the reliability of the system compared to
the minimum clearance requirements in FAC-003-1.
Agree
Disagree
Consumers Energy believes that each Transmission Owner/Operator should have a Vegetation
Imminent Threat Procedure. We disagree with this requirement because "vegetation imminent threat"
is not defined in the standard. As interperted, the "vegetation imminent threat" is only what is needed
to avoid violating the Gallet formula minimum distance which would allow vegetation approaching
close to 3 feet of separation on 345 kV conductors. At this distance, removal of the tree cannot occur
without removing the line from service per OSHA rules. Therefore, the tree can "cause" an outage but
be acceptable under this standard. Consumers Energy believes that vegetation must be maintained so
that extraordinary measures needed to remove the vegetation threat do not have to occur in order to
complete the work. Thus, the minimum distance to "trigger" an imminent threat must be greater than
the OSHA minimum working distance and therefore the Gallet formula does not provide the protection
that FERC demands. During high load periods options a system operator may have to mitigate the
vegetation threat may not be available; you may not be able to remove the line from service, derate
the line, etc., so the operator must "hope" to get through the high load period without the vegetation
causing a outage. Allowing vegetation to approach the Gallet formula distance is unacceptable and
severely decreases the reliability of the system.
Agree
Agree
Agree
Disagree
Absolutely disagree! The Gallet formula distances do not provide adequate protection of the system.
The "Critical Clearance Zone" concept is not workable in the field. Every foot of every span would
have a different CCZ that cannot be measured in the field without survey type equipment and
knowledge of current line loadings. The clearance requirement needs to be uniform along the span for
field crews to effectively achieve compliance. It appears that the drafting team hopes to minimize
violations of vegetation violating FAC-003-1 Clearance 2 distances by decreasing the clearance
distance between the conductor and vegetation using the Gallet formula. If NERC believes that FAC003-1 Clearance 2 distances are too conservative, then the Gallet formula distance needs to be
increased by some multiplier (2 or3) to achieve adequate safeguard for growing vegetation. Most
trees in the United States in the size range that could exist beneath conductors achieve height growth
of 3 feet or more annually. A tree in May may have adequate clearance per the proposed CCZ and in
July violate that clearance causing an outage. Therefore, if the CCZ is to remain as is then the
transmission owner/operator must have a defined imminent threat distance considerably greater than
the CCZ and must be great enough that field personnel can safely remove the threat without deenergizing or de-rating the line.
Disagree
The Gallet distances severely lessen the reliability of the tranmission system since there is not a
define imminent threat distance and the Clearance 1 distances have been removed from this draft.
The IEEE 516 distances provided a safety margin to allow for vegetation to grow and not be a
reliability risk. A transmission owner/operator of a moderate size could not effectively inspect often
enough during the growing season to protect lines from outages when trees are permitted to
approach the Gallet formula distance and not be a violation. Such close distances would permit utility
management to severely cut vegetation management budgets and allow trees to grow for 1-2 years
beyond their scheduled maintenance cycle and not be in violation. But, 2-3 years after the budget
cut, the field operation would be faced with an insurmountable amount of trees needing addressed
and limited timeframes to complete the work. This is basically how the blackout occurred and this
standard decreases the requirements to allow this to happen again.
Agree
Agree
Disagree
The CCZ does not provide adequate clearance and the imminent threat procedure if successfully
implemented only works IF YOU KNOW ABOUT THE VEGETATION THAT THREATENS THE CCZ which
cannot be ensured with yearly inspections. Consumers Energy believes that the Clearance 2 distances
in FAC-003-1 provide more reliability than the CCZ proposed in this draft or any of the alternatives
disussed above.
Disagree
R5, R6 and R7 should be rewritten as a single requirment for vegetation within the "Active
Transmission Line Right of Way" and the exceptions listed. Additionally, a requirement for hazardous
trees outside of the "Active Transmission Line Right of Way" should be incorporated into this draft and
similar exceptions listed for natural disasters, third-party, and animal causes.
Agree
The annaul work plan should be designed to avoid vegetation growing into a violation of the CCZ or
whatever minimum distance is acceptable. Since the plan can change throughout the year, it needs to
be flexible, it should be stated that the plan at a minimum must provide adequate funding to prevent
vegetation growth from violating the minimum clearance distance. The flexibility of change should be
limited to changing to address emergent needs for vegetation management and not reductions in
funding that delay maintenance in the hopes that additional funding at some future point in time will
be adequate to remove the backlog of vegetation maintenance. The Purpose of the standard should
be revised to state "(To maintain minimum clearance sufficient to avoid any vegetation-related
Sustained Outages for all applicable conditions) for all Transmission Lines covered by this Standard"
as provided by FERC in Order 693, Paragraph 731. The purpose as stated in FAC-003-2 waters down
the intent of FERC to "improve the reliability" and is only applicable to "outages that could lead to
cascading".
Individual
Dawn Travalini
National Grid
Disagree
Use of the term Bulk Electric System will cause unnessesary confusion to the industry concerning
applicability of this Standard.
Disagree
No opinion.
Agree
Defining "Active Transmission Line Right-of-Way" solves the Right-of-Way definition problem within
the SAR.
Agree
These revisions and separation make it easier to match requirements and measures.
Disagree
R1.2, M1.2 and M1.3 in the Standard all refer to calendar year. National Grid objects to inspections
being based on a calendar year. Transmission Owners should be able to define their own "year". (See
Question No. 18.)
Agree
Agree
Disagree
National Grid agrees replacing mitigation plan with corrective action process. However, National Grid
questions the use of "interim" for a corrective action process in R1.5, and suggests striking "interim".
Disagree
National Grid takes exception to the term "fill-in-the-blank". National Grid disagrees with the
elimination of Clearance 1. The Clearance 1 requirement in FAC-003-1 was meant to allow a
Transmission Owner to establish clearances to be achieved at the time of vegetation management
work, and be sensitive to local and regional conditions. National Grid believes that Clearance 1 is
needed for public education and safety reasons. Clearance 1 standards allow utilities to specify a
cyclic programmatic approach, and gives the utility leverage with local and state regulators and the
public to achieve significantly larger than minimal clearances.
Disagree
National Grid takes exception to the term "fill-in-the-blank". National Grid would like Personnel
Qualifications to remain in Standard FAC-003-2.
Agree
Agree
Disagree
No opinion.
Agree
Agree
National Grid agrees that there should be no encroachments into the CCZ. However, encroachments
in the CCZ should NOT be considered a violation. Violations should only be for sustained transmission
outages.
Agree
National Grid agrees with the proposed change, however, Standard FAC-003-2 does not provide
outage reporting requirements in R5, R6, R7, or anywhere else in the Standard.
Agree
National Grid has the following comments: 1. Transmission Owners should be able to define their own
inspection "year" and not be locked into a calendar year time frame. National Grid performs
inspections at least once per vegetation growth year. Under our Vegetation Management Program,
growth years are not skipped, and our inspections occur prior to new growth every year. For example,
a transmission right-of-way may be inspected in December 2008 and the right-of-way is next
inspected in February 2010. Under this scenario, the inspections occurred 14 months apart, but only
one growth year occurred between inspections, and each inspection is ahead of the next year's
growth. Transmission Owners need this flexibility to deal with regional growth rate differences and
climate. 2. Section C., Compliance, of Draft Standard FAC-003-2 states "To be added". Issuance of
Draft Standard FAC-003-2 should have been delayed for comments until all sections were complete.
This section is likely to include the outage reporting and self-certification requirements. Transmission
Owners need the opportunity to comment on these items. 3. With the elimination of Clearance 1 and
reducing Clearance 2 clearances, there is concern that FERC will view Standard FAC-003-2 as a
watered down version of Standard FAC-003-1.
Individual
Stephen Tankersley
Pacific Gas & Electric Co.
Agree
Agree
Agree
Agree
Agree
This requirement is appropriate to ensure adequate inspection frequencies, however, a clear definition
of "inspection" should be contained in either the standard or white paper.
Agree
Agree
PG&E agrees an imminent threat procedure is a critical component of the standard and should be
contained in the TVMP. See additional comments for Q11.
Agree
Agree
Agree
Disagree
PG&E agrees the Gallet equation is superior to IEEE 516 and the imminent threat procedure is a
critical component of the standard but disagrees that initiation of the procedure be based on such
ambigous language as "approaching the CCZ". Approaching could be any and all vegetation that is
live and growing and CCZ is a theoritical calculation not a real time event. As written, the standard
would require the TO to initiate an emergency action when such action may not be warrented or
necessary to prevent an outage. PG&E recommends using a clearly defined and measureable
threshold to determine when the imminent threat procedure must be initated. A reasonable threshold
would be 3 times the Gallet clearance distances referred to in Table 1 or when vegetation is
threatening to fall into or otherwise impact a line.
Agree
Agree
Agree
Disagree
PG&E believes a "minimum clearance distance" or "do not encroach zone" is a critical element of this
standard and necessary to achieve the stated purpose of preventing vegetation caused outages.
Preventing vegetation encroachments will prevent outages. However, PG&E disagrees with using the
CCZ as a minimum clearance requirement because it is ambigous and subject to wide variations and
intrepretation. CCZ is a good concept to aid in understanding movement of conductors but is a
theoretical calculation and would be very difficult if not impossible to enforce. PG&E suggests using a
clearly defined distance such as Gallet equation plus a safety margin to assure there is no chance of
spark over. Two times Gallet would be a reasonable clearance requirement to assure a spark over
does not occur and eliminate the ambiguity of the CCZ as the "do not encroach zone".
Agree
M5, M6 and M7 do not explcity exclude the exceptions in R5, R6 and R7 and should do so.
Agree
PG&E agrees with the requirement to implement the annual work plan, but recommends removing the
language "within the extent of its easement and/or legal rights".
1) The standard should be clear that it applies to all Federal and Non-Federal land. PG&E further
recommends additional language specifically dealing with Federal land such as application of ANSI
A300. 2) The standard should specify applicability inside substations.
Group
Western Utility Arborists
Mike Neal
Western Utility Arborists
Agree
Yes, we agree.
Agree
Yes, we agree.
Agree
Yes, we agree, subject to the qualification about “active†rights-of-way under Comment #16.
Under R1.1, it says “Specify the methodologies that the Transmission Owner uses to control
vegetation.†The single word “methodologies†does not adequately replace “objectives,
practices, approved procedures, and work specifications.†The Western Utilities recommends
keeping the original wording. We would also like to point out that the original intent of the standard
was to ensure that utilities had a complete vegetation management program. The new standard is
evolving towards an outage control program, and no longer encourages programs or behaviours that
would ensure the causes of outages are prevented long before they become a problem. The standard
now redirects efforts to avoiding outages instead of managing vegetation.
Although it’s important to have these two separate aspects – documentation and
implementation – separating them spatially in the document itself makes the standard longer than
necessary and creates redundancy. It seems obvious that if you prepare elements of the TVMP, they
also need to be implemented. The document would be easier to follow if the two elements were kept
together.
Clarification is required on exactly what an inspection is, which should perhaps be outlined in the
white paper. There are areas where inspections are not necessary at all, such as lines over a parking
lot, or in a remote desert area. The Western Utilities need some assurance that this inspection will not
constitute a dedicated, comprehensive vegetation management inspection. Inspections are currently
often part of a routine line patrol, where the lineman looks for vegetation concerns in addition to
undertaking maintenance work. Therefore, the Transmission Owner needs the ability within their
TVMP to define what an inspection is in the context of their utility operations.
The document would benefit from keeping the two requirements together, since they relate to the
same topic. Under the new wording in R1, the TVMP no longer has a requirement to include
objectives. However, there is a phrase in R1.3 to “support the objectives…and
methodologies…outlined in the…program.†To be consistent with R1.3, the Western Utilities
recommends that R1.1 be reworded to specify the methodologies and objectives that the
Transmission Owner uses to control vegetation.
Agree
We agree with 1.4, with the following qualification: Any standard that is developed should not contain
advisory-type language—it should be declarative in tone. For example, in R1.4, the ending clause
that begins “…and may include actions…†should be removed because it is advisory in
nature. The suggested actions are not even the responsibility of the vegetation management
program.
Agree
Yes, we agree.
Disagree
The Western Utilities do not agree with the removal of Clearance 1. We recommend adding it back to
the document, but reworded and moved to include it as a measurement (M), rather than a
requirement (R) under the new standard. Many utilities feel that Clearance 1 provides justification and
leverage for operational clearances when dealing with organizations such as municipalities. Without
Clearance 1, utilities could be mandated in specific situations to clear so that the vegetation is just
beyond the CCZ at all times. This could result in pruning at six month intervals, which is not feasible
or cost-effective.
Agree
The Western Utilities are in agreement with the elimination of this requirement. However, we feel
strongly there must be appropriate knowledge to do the work, and that Transmission Owners must at
least have internal standards related to personnel qualifications.
The Western Utilities feel that changing to the Gallet equation will not have a large impact on its
vegetation management operations, so we have no concerns. We agree with R2, but feel that this
clause makes R4 redundant, as per our discussion under Comment # 15 below. We recommend the
removal of R4 entirely from the standard.
Agree
The Western Utilities feel that changing this will not have a large impact on its vegetation
management operations, so we have no concerns.
Agree
The Western Utilities feel that changing this will not have a large impact on its vegetation
management operations, so we have no concerns.
The Western Utilities understands that it’s possible to have a schedule and not implement it.
However, we feel that the document itself would be easier to follow if it was re-organized so that the
requirement to have the schedule is kept together with the requirement to implement it.
The new requirement in R4 stipulates that the Transmission Owner is in violation if an encroachment
of the CCZ occurs at any time. However, the CCZ changes with each foot of the transmission line
from the insulator to the mid-span, depending on loading, actual operating temperature, wind
loading, ice loading, maximum design rating, maximum operating load, and so on. Further, measure
M4 requires that the Transmission Owner has evidence demonstrating there were no vegetation
encroachments into the CCZ. To provide evidence demonstrating there were no vegetation
encroachments into the CCZ would be an extremely onerous task and an expensive requirement for
the Utilities. The Western Utilities strongly supports the alternative to R4 as recommended in the
Comment Form (#15), which is to require immediate removal of the vegetation or immediate
implementation of the imminent threat procedure upon discovery of a possible encroachment of the
CCZ, thereby proactively preventing an outage. This means a violation would occur only if the
imminent threat process is not successfully implemented. This alternative is essentially the same as
R2. Therefore, the Western Utilities recommend removing R4 from the standard entirely.
The Western Utilities strongly recommend that the requirement under R7 be changed from “shall
prevent sustained outages†to “shall minimize sustained outages due to vegetation falling into
a conductor.†We note that the word “minimize†was present in earlier drafts of the
document. We are concerned about the requirement for utilities to prevent sustained outages from
vegetation falling into the conductor from within the active transmission ROW. It is operationally
almost impossible to know precisely where the edge of the ROW is in all situations under all
conditions. This could lead to an incident where utilities are charged unreasonably – for example,
for an outage from a tree that was one foot within the active ROW line. We should not be held liable
when reasonable due diligence is practiced. Further, it is not economically feasible for utilities to
survey every ROW in the U.S. and Canada to determine precise clearance zones.
The Western Utilities understands that it’s possible to have an annual plan and not implement it.
However, we feel that the document itself would be easier to follow if it was re-organized so that the
requirement to have the plan is kept together with the requirement to implement it.
Any standard that is developed should not contain advisory-type language—it should be declarative
in tone. For example, in R1.4, the ending clause that begins “…and may include actions…â€
should be removed because it is advisory in nature. The suggested actions are not even the
responsibility of the vegetation management program. ADDITIONAL COMMENTS We have prepared,
and will submit via email, additional comments regarding our online submission. If the ability to
submit them electronically is not available on this website, we will send the complete document via
email to Harry Tom and would ask that it be reviewed and considered by the drafting team.
Group
Florida Power & Light
John Tamsberg
Transmission Operations
Disagree
The Purpose Statement of any regulation or standard should be completely consistent with the body
of regulation or standard. Here the use of Bulk Electric System (which is defined as 100 kV and
above) is inconsistent with the language of the Standard that states this Standard applies to 200 kV
and above. One of the primary purposes of re-drafting a Reliability Standard is to clear up any
previous confusion -- here the Purpose Statement instead of adding to clarity, adds an uncessary
element of confusion. Thus, the Purpose Statement should be re-written to state 200 Kv and above.
Agree
Agree
Agree
Agree
Agree
Disagree
The definition of Imminent Threat procedure should be included in the Standard. As FERC has stated
with regard to the definition of sabotage, the industry should come up with a standard definition and
it should not vary from company-to-company. FPL further disagrees with defining Imminent Threat
only in a white paper as proposed by some. The Standard should not refer to other reference
documents, especially when it is to add clarity and should define the Imminent Threat procedure as
well as its requirements within the body of the Standard.
Agree
FPL neither agrees or disagrees with this removal but provides the following comment. FPL's
experience regarding Clearance 1 is that it was an effective way of demonstrating a measurable
requirement for compliance when dealing with public entities. The use of a corrective action process
to mitigate instances where this clearance was not met before violations ocurred is also very effective
in promoting reliability and safety in the Standard.
Agree
Disagree
FPL agrees that the Gallet equation is a better method to determine a Critical Clearance Zone.
However, FPL does not agree with the application of the zone for several reasons outlined below. •
There are many environmental and engineering variables and assumptions included in the calculation
of the Critical Clearance Zone. • These assumptions are not clearly defined in the standard. •
Unless there is a significant intrusion into the Critical Clearance Zone, an engineer and surveyor would
be necessary at all times to determine a violation. • The success of this standard lies with a
standard the field personnel can implement. When making actual trimming or removal decisions, the
field personnel are not adequately skilled to do much more than make a rough guess at the Critical
Clearance Zone. This standard must establish measurable and auditable parameters for field
operations. • In Requirement R2, determination of when to activate the Imminent Threat Procedure
becomes unclear due to the difficulty in determining when the Critical Clearance Zone is encroached.
• As written, off ROW trees falling through the Critical Clearance Zone become a violation of
Requirement R4. Unless an outage occurred, how would the utility determine that a violation
occurred? In FAC 003-1 an outage of this nature is defined as Category 3 and is not a violation. Since
fall-in tree interruptions have never been contributors to cascading events or blackouts they should
not be a violation of a NERC standard. Consequently, as written, it is highly questionable whether this
Standard is sufficiently specific and clear to be enforceable. The many questions and levels of
confusion introduced with the application of the Critical Clearance Zone concept suggests that neither
the industry nor NERC will ever know if compliance is met. Such a high level of ambiguity requires
that the Critical Clearance Zone concept be revisited and most likely replaced with a measure that is
workable for both the industry and NERC. To further this effort, FPL has outlined some alternative
suggestions described in the answer to question 18.
Agree
Agree
Agree
Disagree
NERC standards require the Transmission Owner certify annually that they are in compliance to the
standard for the entire year. Since there is no way that a Transmission Owner could monitor every
span of line every minute of every day, Requirement R4 cannot be certified. A Transmission owner
can only certify that at the time inspected the system met the specification in the standard and that
implementation of its Transmission Vegetation Management Plan maintains these specifications. As
stated earlier, the Critical Clearance Zone is difficult to accurately identify in the field and without an
outage it would be difficult for an auditing body to find and validate. Requirements R4-R7 are reactive
in nature. They are violations after the event has occurred or when the tree - wire relationships are so
close that emergency action is the only recourse for the Transmission Owner. The standard needs to
drive the Transmission Owner to identify and remove trees threatening the system in a proactive
fashion. A Transmission Owner should never be in violation for timely action to remove a threat to the
system.
Disagree
As currently written, Requirements R5, R6 and R7 demand perfection. The only acceptable number for
all 150K miles of affected transmission line in the US is 0. The standard should be achievable and
enable proactively addressing potential threats to facilities from vegetation. Even using a Six Sigma
level of quality and control, processes can achieve a level of 3.4 defects per million opportunities for
defect. Each tree on the ROW represents one of those opportunities. FPL has outlined an alternative
proposal in response to Question 18.
Disagree
The standard goes to great length to specify the Active Transmission Right-of-Way but omits its
reference in requirement R8. The inclusion of this term in Requirement R8 adds consistency to the
application of the standard. FPL suggests the following change: "Each Transmission Owner shall
implement its annual work plan for vegetation management to accomplish the purpose of this
standard within the extent of its easement ans/or legal rights in the Active Transmission Line Rightof-Way."
FPL believes the Vegetation Management standard should concentrate on grow-in tree issues that
contribute to cascading or blackout events as stated in the purpose statement. Fall-in trees from
either on or off ROW do not in-and-of themselves cause cascading or blackout events. Transmission
systems are appropriately designed to handle incidental outages under N-1 conditions which are the
case in fall-in type outages. Requirements relating to fall-in and blow-in outages (R6 and R7), which
deal with incidents resulting from force majeure or acts of God, should be removed to allow resources
to be allocated to addressing events related to grow in interruptions. Because of an utter lack of
control or such situations, no Standard or regulation places a duty on one to control force majeure or
acts of God, yet that is precisely what R6 and R7 intend to do. If R6 and R7 stay in its current form,
this will be yet another reason why this Standard as written will be unenforceable. FPL recommends
the following approach. The entire US Transmission system was built under the National Electric
Safety Code (C2). That code uses the Reference Component as the initial building block for
establishing the lowest height of a conductor for all operating and designed environmental conditions.
Over most open land this distance is 14 feet. FPL recommends creating a new requirement to clearly
define a trimming standard. New Requirement At time of trimming, trees under conductors should be
trimmed or removed so that the average growth would remain below the Reference Component of
Rule 232 in the National Electric Safety Code C2. The wire zone should extend to the blowout distance
calculated at 39 miles per hour (Fresh Gale) not to exceed the Active Transmission Right-of-Way.
Where the Transmission Owner can not achieve that clearance, they shall have a permanent (ex.
raised conductor) or interim (ex. short trim cycles) corrective action plan in place to prevent tree wire
conflicts. Permanent corrective action plans should reside in the Transmission Owner's vegetation
program record keeping system (database) for application when that line is maintained or inspected.
Trees to the side of the ROW should be maintained at the edge of the Active Transmission Right-ofWay. The value in this approach is in its application by arborists and tree trimmers in field conditions.
This approach is clear and measurable without a surveyor or an engineer present. The line design
calculations were made to the NESC Standard at the time the line was built and incorporate all
potential conductor locations within its flight path. As it stands now if there is a violation to R4, R5,
R6, or R7 it is already too late. The standard should seek to identify and correct poor performers
before they create a reliability threat to the system. In the field, a poor performer has many trees
close to the line and will have to do many emergency cuts. It will also have more momentary
interruptions before it has a single Sustained interruption. Sustained Interruptions have a history of
contributing to cascading and blackout events. The standard should measure performance and
penalize poor performance. The changes below reflect performance measurements with a graduated
penalty applied to the metric. Change R2 to read Each Transmission Owner shall implement its
Imminent Threat procedure when the Transmission Owner has knowledge, obtained through normal
operating practices or notification from others, that the tree / conductor distance is less than the
minimum clearance distance as specified in Table 2 of ANSI Z133.1-2006 (the minimum approach
distance for qualified line-clearance arborists or qualified line-clearance trainees). Transmission
Owners are to document and report activation of the Imminent Threat Procedure for violation of Table
2. Activation of the Imminent Threat Procedure for other causes shall not be reportable. The Violation
Severity level should read: Activation of the Imminent Threat Procedure for encroachment of Table 2
of ANSI Z133.1-2006 (the minimum approach distance for qualified line-clearance arborists or
qualified line-clearance trainees) has the following severity level: Lower – Greater than 5 per 1000
miles of line and less than 7 Moderate – Greater than 7 per 1000 miles of line and less than 9 High
- Greater than 9 per 1000 miles of line and less than 13 Severe - Greater than 13 per 1000 miles of
line Trees inside of Table 2 can only safely be trimmed under a clearance from the system operator,
using special techniques under a line right of way from the system operator, or by a lineman with a
live line permit from the system operator. No utility wants to let a tree get so close to energized lines
such that it has to take the line out of service for a tree trim. It should be noted that Table 2
represents an established industry standard which is normally found placarded on the side of every
tree trimming easement truck and bucket truck. It is minimum knowledge for every qualified lineclearance tree person under OSHA regulations. This is a distance that field personnel understand. New
R5 to read: Each Transmission Owner shall minimize Momentary Outages of applicable lines due to
vegetation growing into a conductor with the following exceptions: • Sustained Outages of
applicable lines that result from natural disasters. • Sustained Outages of applicable lines that
result from human or animal Activity. The Violation Severity level should read: Lower – Having
Momentary Outages Greater than 3 per 1000 miles of line and less than 6 Moderate – Having
Momentary Outages Greater than 6 per 1000 miles of line and less than 8 High - Having Momentary
Outages Greater than 8 per 1000 miles of line and less than 12 Severe - Having Momentary Outages
Greater than 12 per 1000 miles of line New R6 to read: Each Transmission Owner shall minimize
Sustained Outages of applicable lines due to vegetation growing into a conductor with the following
exceptions: • Sustained Outages of applicable lines that result from natural disasters. •
Sustained Outages of applicable lines that result from human or animal Activity. The Violation
Severity level should read: Lower – Moderate – High - Having Sustained Outages Greater than 1
per 1000 miles of line Severe - Having Sustained Outages of 2 or greater per 1000 miles of line These
VSL's listed above constitute a strawman for discussion. The drafting team could request historical
performance data from Transmission Owners to statistically evaluate where the VSL should be set. As
time progresses, future performance data could be re-evaluated to reset the limits. These changes
bring the standard back in line with measurable and auditable requirements which provide practical
field measurements to the personnel who can make the difference. These parameters provide
measurements to indicate the tree health of the system. On a separate note, FPL believes that
clarifying information captured in footnotes within the standard should specifically be referenced and
made part of the standard. These notes add clarity and better define the standard requirements.
Individual
Rich Salgo
NV Energy (fka Sierra Pacific / Nevada Power Co.)
Agree
Agree
Agree
Yes, we agree, subject to the qualification about “active†rights-of-way under Comment #16.
We would also like to point out that the original intent of the standard was to ensure that utilities had
a complete vegetation management program. The new standard is evolving towards an outage
control program, and no longer encourages programs or behaviours that would ensure the causes of
outages are prevented long before they become a problem. Instead, it redirects efforts to avoiding
outages instead of managing vegetation. If this is now the preferred approach, the term TVMP is no
longer valid and should perhaps be changed to the Transmission Vegetation Outage Prevention
Program. Under R1.1, it says “Specify the methodologies that the Transmission Owner uses to
control vegetation.†The single word “methodologies†does not adequately replace
“objectives, practices, approved procedures, and work specifications.†We recommend that the
SDT retain the original wording.
Disagree
Although it’s important to have these two separate aspects – documentation and
implementation – separating them spatially in the document itself makes the standard longer than
necessary and creates redundancy. It seems obvious that if you prepare elements of the TVMP, they
also need to be implemented. The document would be easier to follow if the two elements were kept
together.
Disagree
Clarification is required on exactly what an inspection is, which should perhaps be outlined in the
white paper. There are areas where inspections are not necessary at all, such as lines over a parking
lot, or in a remote desert area. We need some assurance that this inspection will not constitute a
dedicated, comprehensive vegetation management inspection. Inspections are currently often part of
a routine line patrol, where the lineman looks for vegetation concerns in addition to undertaking
maintenance work. Therefore, the Transmission Owner needs the ability within their TVMP to define
what an inspection is in the context of their utility operations.
Disagree
The document would benefit from keeping the two requirements together, since they relate to the
same topic. Under the new wording in R1, the TVMP no longer has a requirement to include
objectives. However, there is a phrase in R1.3 to “support the objectives…and
methodologies…outlined in the…program.†To be consistent with R1.3, we recommend that
R1.1 be reworded to specify the methodologies and objectives that the Transmission Owner uses to
control vegetation.
Agree
We agree with 1.4, with the following qualification: Any standard that is developed should not contain
advisory-type language—it should be declarative in tone. For example, in R1.4, the ending clause
that begins “…and may include actions…†should be removed because it is advisory in
nature. The suggested actions are not even applicable under the scope of a vegetation management
program.
Agree
Disagree
We do not agree with the removal of Clearance 1. We recommend adding it back to the document,
but reworded and moved to include it as a measurement (M), rather than a requirement (R) under
the new standard. Many utilities feel that Clearance 1 provides justification and leverage for
operational clearances when dealing with organizations such as municipalities. Without Clearance 1,
utilities could be mandated in specific situations to clear so that the vegetation is just beyond the CCZ
at all times. This could result in pruning at six month intervals, which is not feasible or cost-effective.
Agree
We are in agreement with the elimination of this requirement, but not without some qualifications. We
feel strongly there must be appropriate knowledge to do the work, and that Transmission Owners
must at least have internal standards related to personnel qualifications. It is unfortunate that this
important requirement for an effective vegetation management program has been removed due to
concerns with the auditing program.
Agree
We feel that changing to the Gallet equation will not have a large impact on its vegetation
management operations, so we have no concerns. We agree with R2, but feel that this clause makes
R4 redundant, as per our discussion under Comment # 15 below. We recommend the removal of R4
entirely from the standard.
Agree
We feel that changing this will not have a large impact on its vegetation management operations, so
we have no concerns.
Agree
We feel that changing this will not have a large impact on its vegetation management operations, so
we have no concerns.
Disagree
We understand that it is possible to have a schedule and not implement it. However, we feel that the
document itself would be easier to follow if it was re-organized so that the requirement to have the
schedule is kept together with the requirement to implement it.
Disagree
The new requirement in R4 stipulates that the Transmission Owner is in violation if an encroachment
of the CCZ occurs at any time. However, the CCZ changes with each foot of the transmission line
from the insulator to the mid-span, depending on loading, actual operating temperature, wind
loading, ice loading, maximum design rating, maximum operating load, and so on. Further, Measure
M4 requires that the Transmission Owner has evidence demonstrating there were no vegetation
encroachments into the CCZ. These requirements may result in having to LIDAR the lines annually, to
prove that trees have not encroached upon the CCZ. This would be an extremely onerous and
expensive requirement for utilities. NV Energy strongly supports the alternative to R4 as
recommended in the Comment Form (#15), which is to require immediate removal of the vegetation
or immediate implementation of the imminent threat procedure upon discovery of a possible
encroachment of the CCZ, thereby proactively preventing an outage. This means a violation would
occur only if the imminent threat process is not successfully implemented. This alternative is
essentially the same as R2. Therefore, we recommend removing R4 from the standard entirely.
Disagree
We strongly recommend that the requirement under R7 be changed from “shall prevent sustained
outages†to “shall minimize sustained outages due to vegetation falling into a conductor.â€
We note that the word “minimize†was present in earlier drafts of the document. We are
concerned about the requirement for utilities to prevent sustained outages from vegetation falling into
the conductor from within the active transmission ROW. It is operationally almost impossible to know
precisely where the edge of the ROW is in all situations under all conditions. This could lead to an
incident where utilities are charged unreasonably – for example, for an outage from a tree that was
one foot within the active ROW line. We should not be held liable when reasonable due diligence is
practiced. Further, it is not economically feasible for utilities to survey every ROW in the U.S. and
Canada to determine and document precise clearance zones. Such costly effort would not produce
any benefit to the reliabililty of the bulk electric system.
Disagree
We understand that it is possible to have an annual plan and not implement it. However, we feel that
the document itself would be easier to follow if it was re-organized so that the requirement to have
the plan is kept together with the requirement to implement it.
These comments were made with collaboration with other Western Utilities in a conference on this
topic held in Denver. Any standard that is developed should not contain advisory-type language—it
should be declarative in tone. For example, in R1.4, the ending clause that begins “…and may
include actions…†should be removed because it is advisory in nature. The suggested actions are
not even the responsibility of the vegetation management program. NV Energy and the other Western
Utilities support the development of this white paper as a way to help ensure consistent interpretation
of the standard. Perhaps the lack of such a paper in the first version of the standard contributed to
the varying interpretations by the auditors. The utilities understand however that this document is not
a legal document and is not binding.
Individual
Patricia vanMidde
San Diego Gas & Electric
Agree
Agree
Agree
Yes, we agree, subject to the qualification about "active" rights of way under comment 16. Under
R1.1 it says "Specify the methodologies that the Transmission Owner uses to control vegetation." The
single word "methodologiees" does not adequately replace "objectives, practices, approved
procedures, and work specifications." We recommend keeping the original wording.
Disagree
The document would be easier to follow if kept together. Separation of the recommendations and
implementation will make this a redundant process, because both will say the same thing.
Agree
The term "inspection" needs to be better defined, as well as the term "calendar year."
Agree
To be consistent with R1.3, we recommend that R1.1 be reworded to specify the methodologies and
objectives that the Transmission Owner uses to control vegetation.
Agree
We recommend that any advisory language be removed, and replaced with a declaration to the
utilities.
Agree
Disagree
We do not agree with the removal of Clearance 1. We recommend that it be added back into the
document, but reworded and moved so it be included as a measurement, rather than a requirement.
Without Clearance 1, utilities could be mandated in specific situations to clear so that vegetation is
just beyond the Critical Clearance Zone at all times, which is not feasible or cost effective.
Disagree
We feel there must be appropriate knowledge to do the work, and that Transmission Owners must at
least have internal standards related to personnel qualifications.
Disagree
We do not agree with replacing Clearance Zone 2 with the Critical Clearance Zone. We recommend
the removal of R4 entirely from the standard.
Agree
Agree
Disagree
The information should not be separated. It will be much easier to follow if the requirement to have
the schedule is kept together with the requirement to implement it.
Disagree
The new requirement in R4 stipulates that the Transmission Owner is in violation if an encroachment
of the Critical Clearance Zone (CCZ) occurs at any time. However, the CCZ changes with each foot of
the transmission line from the insulator to the mid-span, depending on loading, actual operating
temperature, wind loading, ice loading, maximum design rating, maximum operating load, and so on.
Further, Measure M4 requires that the Transmission Owner have evidence demonstrating there were
no vegetation encroachments into the CCZ. These requirements may result in having to LIDAR the
lines annually to prove that trees have not encroached upon the CCZ. This would be an extremely
oerous and expensive requirement for utilities. We strongly support the alternative to R4 as
recommended in the Comment Form, which is wto require immediate removal of the vegetation or
immediate implementation of the imminent threat procedure upon discovery of a possible
encroachment of the CCZ, thereby proactively preventing an outage. This means a violation would
occur only if the imminent threat process is not successfully implemented. This alternative is
essentially the same as R2. Therefore, we recommend removing R4 from the standard entirely.
Disagree
We recommend that the requirement under R7 be changed from "shall prevent sustained outages" to
"shall minimize sustained outages due to vegetation falling into a conductor." The word minimize was
present in earlier drafts of the document. We are concerned with the requirement for utilities to
prevent sustained outages from vegetation falling into the conductor from within the active
transmission Right of Way. It is operationally almost impossible to know precisely where the edge of
the ROW is in all situations under all conditions. This could lead to an incident where utilities are
charged unreasonably.
Disagree
We feel that the document itself would be easier to follow if it was re-organized so that the
requirement to have the plan is kept together with the requirement to implement the plan.
We feel that any advisory-type language should be removed from the standard and replaced with
wording that is in a declarative tone. We support the development of the white paper as a way to help
ensure consistent interpretation of the standard.
Individual
David Kiguel
Hydro One Networks Inc.
Agree
Agree
Disagree
We agree in changing the text as proposed only if R1 is expanded as suggested below. The standard
as written is primarily, if not exclusively focussed on outage prevention through one means, to keep
vegetation out of the Critical Clearance Zone. The burden to accomplish this is placed on the
Transmission Owner/Operator as it should be. The first section highlights that a program is required,
but does not provide a requirement above this simplistic view, and from our perspective the Measures
do not introduce any further rigour. This simplistic approach, in our opinion, does not adequately
address the reliability risks associated with the various methodologies of managing vegetation. The
White Paper notes removal is superior to pruning in ensuring tree conflicts do not occur. The White
Paper includes elements of vegetation management risks, but the revised standard for the most part
excludes this issue. One could argue that the audits and fines will manage reliability risks, but we are
not convinced that this will do so in a consistent and adequate manner. There are numerous clearance
risk factors associated with managing vegetation on rights of way. Some of these are: accurate
measurement of conductor sag, accurate measurement of vegetation, vegetation growth rate,
conductor sway, tree movement. If one looks at Table 1, the Clearance Distances are to the nearest
cm or 1/100 of a foot. This makes one wonder, how realistic are the expectations laid out in the
standard? To manage the risks around the Critical Clearance Zone the Standard requires each
Transmission Owner to work with these precise numbers and build in a margin of safety to manage
the situation. Will each Transmission Owner use identical criteria to trigger work? This doubtful, so
this leads one to believe that the standard has not been designed to produce consistent results, which
in our opinion is the case. So one has varied field conditions that are difficult to nail down, precise
clearance requirements to the nearest 1/100’ and the likelihood of inconsistent margins of safety.
We realize that the audit process will help to assess these situations, but it may not be enough to
achieve a somewhat uniform risk profile across the transmission systems. Other standards that we
are familiar with include a margin of safety such as added clearance above the absolute minimum
recognizing that it may not be practical to work to such precise measures. Examples of standards that
use this approach to ensure consistent and reliable results include OHSA and the Canadian Standards
Association. We are not advocating that this standard follows an identical approach, but do want to
highlight that the standard may fall short in the area of managing vegetation management risks
which in turn have a direct impact on reliability. Considering the above, it is suggested that the aspect
of managing vegetation reliability risks be added to the White Paper to allow Transmisison Owners to
develop somewhat consitent criteria. Further on the topic of managing risk. We believe that reliability
risks are directly related to the amount of incompatible vegetation on a right of way that is
approaching the Critical Clearance Zone. Incompatible vegetation would be vegetation that has the
potential to grow into the Critical Clearance Zone at full growth. We suggest that risks could be
reduced significantly by including direction in the standard concerning the management of
incompatible vegetation. This would drive a greater degree of consistency among Transmission
Owners and would reduce the amount of vegetation on rights of way that have the potential to cause
flashover. In addition, this would reinforce the reliability risks associated with vegetation, not just
from a clearance perspective but also from a volume perspective, and would provide a more
comprehensive view for the public and interest groups. In order to respond to what we consider a
shortcoming of the proposed standard, our suggestion would be to expand R1.1 similar to the
following: Specify the methodologies that the Transmission Owner uses to control vegetation and
demonstrate that the removal of non-compatible vegetation is a focus within the plan. It is recognized
that reliability risks increase appreciably with an increase in incompatible vegetation on an active right
of way, and the Transmission Owner is required to remove incompatible vegetation at a point no later
in time when it poses a threat to the reliability of the transmission line. Exceptions include vegetation
used for designated visual screens, trees of a historic significance, vegetation to control erosion,
agreements made at the time of environmental approval for construction, ………etc.
Agree
Disagree
Clarification is required on the requirements. The frequency and need for inspection is based on a
number of factors that include: type of vegetation on a right of way, change in growing conditions and
the Transmission Owner’s clearance standards (i.e., if the clearance standards are well above the
Critical Clearance then the risk to reliability may be very low, so why inspect for vegetation clearances
on an annual basis?) This being the case, clarification is needed on inspection requirements relative to
the overall approach used to manage vegetation clearances. For example, Hydro One conducts
routine line inspections on an annual basis and identifies clearance issues. Would this meet the
requirements of the standard?
Agree
Agree
Agree
Disagree
We would agree only if the standard is revised to include the removal of incompatible vegetation as
outlined in our response to question 3 above. If not, then added direction or requirements are needed
to introduce the elements that combine (to a greater degree than exists under the revised standard)
reliability and vegetation management. Clearance 1 accomplished this to some degree.
Agree
Agree
Agree
Agree
Agree
Disagree
A statement is needed that this requirement applies to the active right of way. Outside of the active
right of way there is no guarantee that this can be achieved. As noted in the question above, it may
be very difficult with the first alternative to provide adequate evidence that no encroachment had
occurred over the compliance period, as the situation is very difficult to assess along each span to the
accuracies (1/100 of a foot) spelled out for the CCZ. It may be more meaningful that the
Transmission Owners be able to demonstrate processes, methodologies and actions that can support
that vegetation has not entered the CCZ. Another alternative for R4 could then be: Each Transmission
Owner shall demonstrate that adequate actions and processes are in place to prevent vegetation from
entering the CCZ. The effectiveness of the process can then be evaluated based on methods used for
field assessment and performance, i.e., outages and imminent threat reporting. It appears that the
second alternative noted above can be combined with R2. It is not clear why there needs to be a
separate requirement. Hydro One is not in favour of alternative 3, as this would create added
administration with a situation that will be difficult to prove to the accuracy required. LIDAR may be
the only means available to provide evidence of a quality needed to produce meaningful statistics,
and in many cases this may not be the most efficient use of the limited funding that is available.
Disagree
A further exception would be a sustained outage where the conductor has moved outside of the
critical clearance zone. This could occur under conditions of heavy icing, operating outside the line
rating or excessive wind. These would not necessarily be the result of a natural disaster. Also, it is
recommended that the requirement for R7 be revised to “Each Transmission Owner shall minimize
(“minimize†replacing “preventâ€) Sustained Outages of applicable lines due to
vegetation falling into a conductor….. A fall in is a random occurrence and the likelihood that this
would be the cause or contribute to a cascading event is very remote. These types of outages are rare
and can be considered similar in nature to an insulator flashover or a hardware failure, which have
not been given any association with cascading events. The purpose of the standard is to prevent
cascading events and it is suggested that this remain the focus and not introduce other types of
outages on a selective basis.
Agree
Please see our comments on question 3.
Individual
David Dworzak
Edison Electric Institute
Disagree
The purpose of the standard should be revised to state 'To maintain minimum clearances sufficient to
avoid any vegetation-related Sustained Outages for all applicable conditions.' This is the identical
wording taken from Order No. 693, Paragraph 731.
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Disagree
Consistent with previous comments, NERC should respond to FERC Order No. 693 Paragraph 721
regarding compliance audit procedures to identify appropriate inspection cycles.
Disagree
Encroachment without a Sustained Outage should not be construed as a violation. The proposed R4
requirement should be removed. EEI strongly believes that this requirement, if approved, is
unenforceable. The alternative, to require implementation of the imminent threat procedure, should
be considered as a practical approach. In particular, this concern applies to a requirement to prove
that no encroachments have existed. This will require extensive work by field personnel, who will be
required to make subjective judgments. In addition, determining actual clearance zones in the field
would require a span-by-span analysis to be conducted with the rigor of survey level measurements.
Calculations made to determine the clearance zones are based on undefined terms and subject to
wide variation. Enforcement authorities will be required to make interpretations. EEI believes that the
costs of conducting such work will not deliver sufficient benefit to warrant the requirement.
Ultimately, there is no basis for determining whether the theoretical clearance zones included in the
proposed standard will increase, or even maintain, an adequate level of reliability as provided by the
existing standard.
Agree
Agree
Overall Comments EEI strongly believes that companies are responding assertively to the
requirements in FAC-003-1 and that the existing standard is effective in supporting an adequate level
of reliability. The central issue with FAC-003-1 and the draft version 2 centers on circumstances
where vegetation encroachments into clearance zones take place and do not result in interruptions.
EEI understands that a potentially broad range of interpretations are being applied to the existing
standard, resulting in potential violations due to clearance encroachments of any possible design
position of the conductor being violations, as well as Sustained Outages. Version 2 should clarify this
issue in the context of focusing the industry in the direction that is most effective in establishing an
adequate level of reliability. The technical comments provided by EEI seek to address this critical
issue. Quantitative analysis on vegetation-related line outages or violations made publicly available do
not support the need for a substantive revision of the standard. Analysis needs to recognize a broader
range of facts in a consistent manner. Analysis needs to consider whether violations resulted in a
Sustained Outage, whether all outages and vegetation encroachment were voluntarily reported prior
to enactment of Section 215, or the facts and circumstances surrounding violations. For example,
while some entities may perceive a decline in industry performance, it may be that companies are
reporting much more completely than in the past. Much more rigorous analysis is needed before
concluding that the existing standard must be made tougher. Rather than focusing on whether the
standard should be more stringent, EEI believes that the emphasis in the standard development
process should focus on practicality, both for field personnel in terms of implementing the standard,
and enforceability. Revisions to the existing standard should therefore seek to a) respond to issues
raised by FERC in Order No. 693 b) where possible, clarify ambiguities in the requirements, and c)
improve industry understanding, practicality, and enforceability. For example, it is impractical to seek
development of a ‘bright line’ set of performance requirements. The standard needs to
recognize both the diversity of the continent in terms of geography, topography, and climate, and the
critical need to provide field personnel with workable performance requirements. Bottom line; it is
very important to recognize that the ultimate goal of the standard is to ensure that vegetation
management is conducted in order to maintain an adequate level of reliability, and the industry is
achieving this goal. The standard should aim for increasing clarity in the requirements without
sacrificing flexibility, since companies expect high monetary penalties associated with Sustained
Outages caused by vegetation. In addition, a continued ‘zero tolerance’ approach to vegetation
management will emphasize operational excellence. Seeking ‘zero tolerance’ on momentary
outages is equivalent to pursuit of operational perfection, which is achievable only at extraordinary
expense to customers. Therefore, the Standard will be most effective if its elements encourage
proactive behavior and provide incentives for Transmission Owners to identify and address vegetation
clearance issues before they result in momentary interruptions or Sustained Outages. Vegetation
Outage Data In Order No. 693, Pargraph 732, FERC ordered NERC to collect and analyze transmission
outage data to inform development of the revised standard. EEI encourages the drafting team and
NERC Standards Committee to request that NERC collect and analyze this critically important
information. Such analysis provides an important foundation for determining whether the standard
can ensure an adequate level of reliability as required by Section 215. Applicability Order No. 693,
Paragraph 708, directs NERC to 'develop an acceptable definition that covers facilities that impact
reliability but balances extending the applicability of this standard against unreasonably increasing the
burden on transmission owners.' In the order, FERC appears to accept the 200-kv threshold,
however, continues to ask about these other critical facilities. EEI recommends that the drafting team
develop a definition of 'sub- 200kv critical facilities' for use in the standard. Reliance on Reliability
Coordinators for developing their own definition raises the likelihood of inconsistent approaches and
applications of the term. In addition, the drafting team should consider whether such critical facilities
might require expanding applicability to entities other than Transmission Owners. Annual Plan as a
Defined Term In order to aid in compliance enforcement and industry compliance, the term 'annual
plan' should be a defined term.
Group
Santee Cooper
Terry L. Blackwell
South Carolina Public Service Authority
Agree
Disagree
The RC should not define applicable lines that are operated below 200 kV. PRC023 requires the
Planning Coordinator to define transmission lines operated at 100 kV to 200 kV that are considered
critical to the reliability of the Bulk Electric System. Multiple lists will lead to confusion among electric
utilities.
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Disagree
Recommend replacing the word "prevent" in R4 to "monitor". The first alternative that requires
immediate removal of vegetation or immediate implementation of the imminent threat procedure
would be a Requirement that could be measured. In addition, if an encroachment is found it needs to
be eliminated and the first alternative specifies immediate removal. If R4 is left as written, how can
you provide evidence that there has been no encroachments within the Critical Clearance Zone.
Disagree
Recommend removing R7 because current and proposed standards do not require the entire right-ofway or Active Transmission Line Right of Way to be clear of vegetation. In this case, a utility should
not be penalized if a tree falls from within the right-of-way or Active Transmission Right-of-Way as
long they are meeting all the other standards (e.g., minimum vegetation clearance distances). Since
fall-ins from just outside of the right-of-way is currently not a compliance issue, it makes sense that a
fall-in from within the right-of-way be treated the same. This is especially true for a utility who has
elected to acquire a wider right-of-way than another utility. That utility may have a tree(s) growing
just inside the right-of-way but still maintains a better clearance distance between trees and
conductors than a utility with a narrower right-of-way and no tree encroachment.
Agree
The SDT should clarify that Transmission lines operated at 200 kV and above is for lines that are
network facilities. Radial load transmission facilities operated at 200 kV and above should not be
subject to this standard as they would not lead to SOLs or IROLs. M2 requires evidence that a TO
implemented its imminent threat procedure upon knowledge of a Critical Clearance Zone breach. M4
requires evidence that there were NO encroachments into the Critical Clearance Zone. These two
measures are in conflict with one another. If a utility provides evidence for M2 then they are in
violation based upon M4. M4 and M5 requires a utility to provide "proof to the negative". These
measures should be removed from the standard. R9, R10, M9, and M10 should be removed from this
standard as critical facilities are identified through the PRC standards.
Individual
George Czerniewski
Consolidated Edison Company of New York (CECONY)
Disagree
The phrase "Bulk Electric System" (BES) is somewhat misleading. BES includes transmission voltages
greater than 100kV but this Standard addresses transmission lines with operating voltages at or
above 200kV and only those lines below 200kV designated by the Reliability Coordinator. Use of the
phrase "electric transmission circuits" or something similar rather than BES would reduce confusion.
Agree
CECONY agrees provided that R9 remains the same as is currently written. This states that the
Reliability Coordinator, in consultation with the Transmission Owner, shall jointly prepare and keep
current, a list of designated applicable lines.
Agree
Agree
Agree
Agree
Disagree
CECONY currently has procedures that mandate response to imminent threats. The Standard should
be made more general and not identify the specific actions that shall be taken in the procedure. The
second sentence of R1.4 should be deleted and the first sentence should read, 'Require a process or
procedure to respond to vegetation-related imminent threats." This adds the necessary flexibility that
utilities require and avoids additional redundant processes or procedures from being developed.
Agree
Agree
Agree
Disagree
CECONY is in favor of using the Gallet equations as they provide a more realistic clearance distance
for vegetation. We understand and agree that establishing a Critical Clearance Zone (CCZ) would
provide the specific area that a conductor could possibly travel through during various field and
weather conditions but we do not agree that this is the most practical approach. The main issue is
that the wording '...the Critical Clearance Zone is approached by vegetation.....' is very vague and left
open to wide interpretation which causes inconsistency and confusion throughout the industry. The
CCZ changes throughout the length of each conductor in each span so a field inspector's job and an
auditor's job become much more complicated when trying to confirm compliance when vegetation is
present in the Actiove ROW. We feel that the time spent trying to measure and calculate the CCZ and
then confirm compliance would be better spent initiating a response plan to safely remove the
vegetation. The imminent threat procedure would only be implemented if vegetation encroaches
beyond a specific distance from the conductor, not as it approaches the theoretical CCZ. Advanced
technology would be required if a vegetation approach distance to the CCZ was to be calculated in the
field. This is a very costly and time consuming requirement and does not efficiently meet the
Standard's goal of ensuring reliability.
Agree
Agree
Agree
Disagree
CECONY disagrees with R4 as currently written. As mentioned in the response to Question 15,
performing a field measurement of the CCZ and a field measurement of the vegetation encroaching
into the CCZ are complicated, time-consuming efforts. As the CCZ changes along the conductor, so
too may the Active ROW dimensions, the vegetation clearances at multiple points, and elevation
levels to name a few. Certifying compliance that no encroachments have occurred would be very
difficult for auditors and field inspectors. Modern laser technology would have to be deployed to take
these measurements and CECONY is concerned that, if an encroachment of the CCZ constitutes a
violation, utilities would not consider investing in this technology knowing that multiple violations
could potentially be found within a single span. Enhanced reliability is achieved when utilities invest in
the best available technology and perform proactive inspections on their systems but, as written, R4
would not effectively motivate a utility to follow through with these initiatives. We recommend that
the term 'momentary outage' or the phrase 'all outages' be used in R5, R6, and R7 instead of
'Sustained Outages' to avoid confusion throughout the industry. Momentary outages identify a
potential failure of the utility's vegetation management program and stating it directly in the Standard
clearly sends the message to utilities that all vegetation outages are unacceptable. In summary, we
do not agree that encroachments are violations but we do recommend that when a utility identifies
vegetation-related imminent threats and takes immediate action, they report this to their Reliability
Coordinator. The Reliability Coordinator (RC) could then identify the utilities that have had multiple
issues or have exceeded acceptable pre-established reporting limits which, in turn, would help the RC
prioritize auditing efforts. This, in our opinion, would enhance reliability more effectively.
Agree
CECONY agrees that outages caused by the factors mentioned are violations of R5, R6, and R7 but we
recommend that either the phrase 'momentary outage' be incuded in the wording or the phrase 'All
Outages' replace 'Sustained Outages' to make the requirements clearer.
Agree
CECONY does not feel that, as currently written, the Standard would effectively enhance reliability
throughout the industry. We recommend that stricter language be used in the Standard specifically
requiring the industry to remove incompatible species on Active ROWs. This should reduce the
number of outages resulting from vegetation grow-ins and vegetation fall-ins from inside the Active
ROW and help maintain a higher level of reliability. This is currently done at the state level (in NY)
and the revised wording in the Federal Standard may help promote consistency industry-wide and
avoid confusion. Also, the concept of the CCZ is theoretically strong but it needs to be made simpler
for the auditors and field inspectors.
Individual
Tom Mathews and Steve Rueckert
WECC
Agree
Disagree
WECC believes the Regional Entity should remain the proper entity to identify sub-200kV transmission
lines subject to this standard. The Regional Entity is in the best position to work with Transmission
Owners (TOs) and Reliability Coordinators across the interconnection to determine critical sub-200kV
transmission lines.
Agree
Agree
Agree
Agree
Agree
But for clarity, "Imminent Threat Procedure" should be replaced with "Vegetation Imminent Threat
Procedure".
Agree
Agree
Agree
Agree
Yes but the wording is ambiguous. Vegetation under a transmission line is always "approaching" or
growing towards the transmission line. Entities should define a specific distance greater than the
Critical Clearance Zone when they are required to implement their Imminent Threat Procedures.
Agree
Agree
Agree
Agree
Yes, R4 as written provides clear guidence to TOs on the minimum radial distance, dependant on line
voltage that vegetation is allowed to approach energized conductors. These industry standardized
distances will ensure a level of reliability equal to or better than FAC-003-1.
Agree
However reporting requirments are not identified in the standard. WECC believes that sustained
outages caused by vegetation should be reported to the Regional Entity using the existing reporting
requirments in FAC-003-1
Agree
Reporting requirments are not identified in the standard. WECC believes that sustained outages
caused by vegetation should be reported to the Regional Entity using the existing reporting
requirments in FAC-003-1 (Transmission Owners report outages to the Regional Entity). Reports of
sustained outages to the Reliability Coordinator should be made for reliability purposes and not
compliance purposes. The Reliability Coordinator should not be required to report vegetation outages
of individual Transmission Owners to the compliance department.
Individual
Sreenath Thota
Arizona Public Service Company
Disagree
APS suggest the following change; To improve the reliability of the Bulk Electric System by preventing
vegetation related outages. This is a reliability standard APS would suggest removing "that could lead
to widespread cascading failures" from the purpose statement.
Agree
Agree
Agree
Agree
Clarification is required on exactly what an inspection is, which should perhaps be outlined in the
white paper. There are areas where inspections are not necessary at all, such as lines over a parking
lot, or in a remote desert area. APS needs some assurance that this inspection will not constitute a
dedicated, comprehensive vegetation management inspection. Inspections are currently often part of
a routine line patrol, where the forester or lineman looks for vegetation concerns in addition to
undertaking maintenance work. Therefore, the Transmission Owner needs the ability within their
TVMP to define what an inspection is in the context of their utility operations.
Disagree
The document would benefit from keeping the two requirements together, since they relate to the
same topic. Under the new wording in R1, the TVMP no longer has a requirement to include
objectives. However, there is a phrase in R1.3 to “support the objectives…and
methodologies…outlined in the…program.†To be consistent with R1.3, APS recommends that
R1.1 be reworded to specify the methodologies and objectives that the Transmission Owner uses to
control vegetation.
Agree
APS agrees with 1.4, with the following qualification: Any standard that is developed should not
contain advisory-type language—it should be declarative in tone. For example, in R1.4, the ending
clause that begins “…and may include actions…†should be removed because it is advisory
in nature. The suggested actions are not even the responsibility of the vegetation management
program.
Agree
Disagree
APS disagrees with removal of clearance one. Clearance one should be achieved at time of
maintenance which is part of the vegetation program. This gives leverage with dealing with state and
federal agencies, tribal and private landowners. This isn't a fill in the blank requirement, however it
should be based on sound science in regards to vegetation management. A professional
arborist/forester can determine the appropriate amount of vegetation that needs to be obtained at the
time of maintenance. APS suggest the following language change for clearance 1. The Transmission
Owner shall maintain ROW on Federal, State, Tribal and Private lands in accordance with ANSIStandard A300 (Part 1)-2001 and (Part 7)-2006 in consultation with companion publication Best
Management Practices: Integrated Vegetation Management, 2007. If all utilities followed this standard
this would increase the reliability of the bulk electric system and reduce the risk of vegetation
outages.
Disagree
APS disagrees with the removal of personnel qualifications. The person responsible for vegetation
management program should have experience and training in vegetation management and system
operations. The International Society of Arboriculture has an ISA Certified Arborist and Utility
Specialist certification. This requires the credential holder to have minimal qualifications before sitting
for the certification and on going training to maintain the credential. The industry has already
responded by providing the information as part of the current standard FAC-003-1. It makes no sense
to remove personnel qualifications from the revision.
Agree
Agree
Agree
Agree
APS understands that it’s possible to have a schedule and not implement it. However, we feel that
the document itself would be easier to follow if it was re-organized so that the requirement to have
the schedule is kept together with the requirement to implement it.
Disagree
APS agrees with alternative one.The new requirement in R4 stipulates that the Transmission Owner is
in violation if an encroachment of the CCZ occurs at any time. However, the CCZ changes with each
foot of the transmission line from the insulator to the mid-span, depending on loading, actual
operating temperature, wind loading, ice loading, maximum design rating, maximum operating load,
and so on. Further, Measure M4 requires that the Transmission Owner has evidence demonstrating
there were no vegetation encroachments into the CCZ. These requirements may result in having to
LIDAR the lines annually, to prove that trees have not encroached upon the CCZ. This would be an
extremely onerous and expensive requirement for utilities. APS strongly supports the alternative to
R4 as recommended in the Comment Form (#15), which is to require immediate removal of the
vegetation or immediate implementation of the imminent threat procedure upon discovery of a
possible encroachment of the CCZ, thereby proactively preventing an outage. This means a violation
would occur only if the imminent threat process is not successfully implemented. This alternative is
essentially the same as R2. Therefore, APS recommends removing R4 from the standard entirely.
Disagree
APS strongly recommends that the requirement under R7 be changed from “shall prevent
sustained outages†to “shall minimize sustained outages due to vegetation falling into a
conductor.†We note that the word “minimize†was present in earlier drafts of the
document. We are concerned about the requirement for utilities to prevent sustained outages from
vegetation falling into the conductor from within the active transmission ROW. It is operationally
almost impossible to know precisely where the edge of the ROW is in all situations under all
conditions. This could lead to an incident where utilities are charged unreasonably – for example,
for an outage from a tree that was one foot within the active ROW line. We should not be held liable
when reasonable due diligence is practiced. Further, it is not economically feasible for utilities to
survey every ROW in the U.S. and Canada to determine precise clearance zones.
Disagree
APS understands that it’s possible to have an annual plan and not implement it. However, we feel
that the document itself would be easier to follow if it was re-organized so that the requirement to
have the plan is kept together with the requirement to implement it.
APS has a comment to NERC on picking the standard drafting team. FAC-003 is a vegetation
management standard not an engineering standard. The team members should have been chosen
based on managing the vegetation program not because they were engineers. Any standard that is
developed should not contain advisory-type language—it should be declarative in tone. For example,
in R1.4, the ending clause that begins “…and may include actions…†should be removed
because it is advisory in nature. The suggested actions are not even the responsibility of the
vegetation management program. APS supports the development of this white paper as a way to help
ensure consistent interpretation of the standard. Perhaps the lack of such a paper in the first version
of the standard contributed to the varying interpretations by the auditors. The utilities understand
however that this document is not a legal document and is not binding.
Group
Southern Company
Roman Carter
Southern Company Transmission
Disagree
The initial FAC-003-1 drafting team had a particular reason for not using Bulk Electric System for fear
of it being widely recognized to characterize the entire networked transmission system. This reason
was to limit possible confusion with the applicability of the Standard. The Bulk Electric System
definition includes all lines of the grid operated at 100 kV and above. This term also does not
necessarily include lines of any voltage class that are radial and directly serving load. Use of this term
in lieu of “electric transmission systems†has the potential to cause additional confusion to the
industry.
Disagree
The use of the Reliability Coordinator as the entity for identifying sub-200 kV lines is inconsistent with
the approach used in other NERC standards, such as PRC-023. Other NERC standards utilize the
Planning Coordinator or the RRO as the entity. We feel the Planning Coordinator would be the
appropriate entity for identifying sub-200 kV lines covered by FAC-003-2.
Agree
Agree
Agree
Agree
Disagree
The standard requirement, as written, requires the "immediate notification" of the operator. This
standard requirement could be interpreted to mandate that this notification take place prior to any
other action. There could be times that this communication would take up valuable time needed to
relieve the immediate threat. The requirement should be modified to list examples of appropriate
actions that could be taken. The Transmisison Owner should be allowed the flexibility of developing a
communication process that ensures timely notification of a threat and the proper channels of
communication that will be utilized in making the notifcation. The present wording in the standard
alone suggests the individual observing the threat in the field is directly responsible for
communicating with the Transmission Operator while the whitepaper tends to be more flexible. The
Transmission Owner may wish to have the vegetation contractor notify the Transmisison Owner's
forester who in turn will notify the Transmission Operator. While the whitepaper does an adequate job
describing acceptable responses, the standard does not. It is recommend the standard, VSL, and
RSAW better explain what is an acceptable response to the TOP. The requirement then goes on to
address specific actions the operator "may" take in response to the notification. The imminent threat
processs should be limited to the steps taken to notify the Transmission Operator in a timely manner.
FAC-003 is not the appropriate place to address Transmission Operator decisions resulting from
notification of a threat to the system.
Agree
Agree
Agree
Disagree
As written, R2 requires activation of the imminent threat process when the Critical Clearance Zone
(CCZ) is "approached" by vegetation. The term "approach" is vague and open to interpretation. Since
vegetation is dynamic in nature, it is constantly "approaching" any pre-defined zone. There could also
be many examples given of encroachments into the theoretical CCZ that would neither threaten the
transmission line conductor nor cause a reduction in the capacity of the transmission line. This
concept would be better suited to be a “trigger point†that, if found, would be incentive for the
Transmission Owner to take immeidate action or ensure future action occurs on schedule. This action
may be as urgent as implementation of the immediate threat procedure or as non-urgent as making
sure that the upcoming maintenance on that line is scheduled appropriately. We are concerned this
revision of FAC-003 continues to take a zero tolerance approach to compliance, which is contrary to
the philosophy utilized in other NERC standards. A state of non-compliance should not exist simply
because vegetation encroached within a pre-defined zone by a fractional inch, but only when an
event, such as a sustained outage, occurs due to the Transmssion Owner's failure to maintain
adequate clearance between conductors and vegetation.
Agree
Agree
Agree
Disagree
The Critical Clearance Zone is a concept that adequately describes the salient functionality a
Transmission Owner must consider when determining acceptable clearances. However, the practicality
of a requirement that forbids even one encroachment in the Critical Clearance Zone presents a
problem for not only the field personnel doing the vegetation work, but also the Regional Entity that
must enforce the requirement. This zone changes not only from one span to another, it also changes
at each location along each span. The reality is that the difference in encroaching into the zone and
not encroaching into the zone is a matter of a fractional inch. In order to prove non-compliance or to
defend compliance at a particular site, all vegetation work would have to be postponed for survey
accuracy equipment and appropriately trained personnel to be brought to the site, measurements and
calculation to be made and consequently a determination rendered. This hardly seems worthwhile
when the vegetation could simply be cut, the threat removed and the vegetation work could continue
on down the transmission line. As stated in a previous comment, there could be many examples given
of encroachments into this theoretical zone that would neither threaten the transmission line
conductor nor cause a reduction in the capacity of the transmission line. This concept would be better
suited to be a “trigger point†that, if found, would be incentive for the Transmission Owner to
either take immediate action or ensure future activities are appropriately scheduled and implemented.
This action may be as urgent as implementation of the immediate threat procedure or as non-urgent
as making sure that the upcoming maintenance on that line is scheduled appropriately. If a sustained
outage occurs due to an encroachment, the outage should be the compliance measure.
Agree
Disagree
While we agree in principle, we feel Requirement R8 as written is “open ended†and could be
interpreted to be in conflict with the “Active Rights of Way†concept. Clarifying the intent for
the annual plan to focus on the Active Rights of Way will prevent incorrect interpretations. We suggest
that the Requirement be reworded to read: Each Transmission Owner shall implement its annual work
plan for vegetation management within the Active Right of Way to accomplish the purpose of this
standard within the extent of its easements and or legal rights.
We would like to re-emphasize our concern over the zero tolerance philosophy of FAC-003-1 which is
continued in this proposed revision. FAC-003 has been singled out as the only zero tolerance NERC
standard. Compliance should not be based on the encroachment of vegetation into a theoretical, predefined zone, but on the occurrence of a sustained outage, as stated in the document's Purpose
Statement. We agree with the philosophy utilized in other NERC standards where a clearly discernible
compliaince event signals a review of the Transmission Owner's plans, policies, and procedures to
determine the effectiveness of the entity's programs and spirt toward complaince. Applicability
Section 4.2 describes the Facilities pertinent to this Standard. Recommendation is to restructure the
sentence by relocating the parenthetical phrase: Transmission lines operated at 200kV or higher, and
transmission lines operated below 200kV designated by the Reliability Coordinator as being subject to
this standard (“applicable linesâ€) including but not limited to those that cross lands owned by
federal, state, provincial, public, private, or tribal entities. Requirement R3 Recommend rephrasing to
say: Each Transmission Owner shall conduct vegetation inspections of all applicable lines in
accordance with the frequency specified in its transmission vegetation management program.
Requirement 10 The standard does not mention whether or not the results of this specific assessment
methodology are supposed to be compiled and maintained. The resulting information could be labeled
as sensitive and possibly critical since the loss would place the grid at an unacceptable risk of
instability, separation, or cascading failures. If the resulting information becomes auditable (subject
to discovery and posting) then precautions must be taken that are comparible to those designed to
preserve the integrity of critical assets or critical cyber assets. We would like to express our sincere
appreciation and thanks the drafting team for their efforts.
Individual
Patrick Brown
PJM Interconnection
Disagree
The RC or PC should not play a role in the vegetation management standard. All TOs need to ensure
they have a vegetation program to avoid unnecessary tripping of transmission lines, at any voltage
levels and regardless of their impacts on the BES. Identification of critical facilities is not a part of this
standard; it belongs to other standards that deal with SOL/IROL calculations, SPS, protection and
critical infrastructure protection. R9 and R10 should be removed from the standard.
the current version of this standard, FAC-003-1, kept the subject of vegetation outside of the Rights
of Way in the standard. Why are outside of Rights of Way vegetation issues not mentioned in FAC003-2, or some responsibility for looking for outside of Rights of Way imminent threats or issues
requiring corrective action plans not addressed?
Individual
William T. Rees
Baltimore Gas & Electric Company
Agree
Agree
The documented method to assess the reliability significance of sub-200 kV lines referenced in R10
should be put out for comment by the Reliability Coordinator to the regulated entities and FERC/NERC
before it is finalized.
Disagree
I agree with the simplification of the language, but I am uncomfortable with the definition of Active
Right-of-Way (R/W). The definition in FAC-003-2 and the examples used in the white paper continue
to leave room for interpretation, particularly with respect to the example where only one circuit is
installed on a double circuit tower. Moreover, there may be circumstances where the Active R/W is
relatively narrow and the utility has an Inactive R/W or otherwise owns land adjacent to the Active
R/W that can be maintained to protect the facilities from grow-ins. Consequently, consideration
should be given to require utilities to protect lines from grow-ins into the CCZ regardless of whether
or not the R/W is Active or Inactive as long as the utility has the legal ability to do the necessary
work.
Agree
Agree
Disagree
See response to question no. 17.
Agree
This requirement references Danger trees which according to ANSI A-300, Part 7 is any tree that
could fall on the conductor. Should this more appropriately be changed to Hazard tree which is a
structurally unsound tree? It might be helpful if an imminent threat were defined, e.g trees that are
presently encroaching in or near the CCZ, or trees that by virtue of their hazardous condition appear
to be likely to fall into or near the CCZ in the near future. (or just leave the explanation to the White
Paper)
Agree
Agree
While I may agree with the removal of this requirement strictly for reasons of simplification and selfdetermination, the current requirement forced utilities to structure their TVMP to develop safeguards
to keep trees from encroaching into the Clearance 2 envelope. The proposed change will leave the
clearance issue beyond the CCZ unaddressed. Responsible utilities will take the appropriate measures
and other utilities will not.
Agree
Similar to the response to no. 9, the end result is what counts and each utility will be responsible and
accountable for their actions. Qualifications unlike clearance requirements, are far-removed from
results and can easily be left unaddressed in the new std.
Agree
Again, each utility is responsible and accountable for it's actions. The Gallet clearances are a much
better approximation of a true spark gap than the present requirement. Without a clearance one
requirement, the closer tolerance produced by the Gallet equation will leave little room for error when
a line is at or approaching it's max. engineered sag. When vegetation gets in the new CCZ (if
adopted), it will be likely that an outage will be imminent. With the present clearance 1 and clearance
2 requirements, there is more of a buffer for encroaching vegetation.
Disagree
As noted in 11 above, the Gallet equation would appear to be a much closer approximation of the
actual spark gap/flashover distance. It seems as though the new std. is making the protective zone
around the conductors smaller by replacing the Clearance 2 requirement with the CCZ, while at the
same time eliminating any other type of consideration for how much clearance needs to be achieved
while trimming. All things being equal, if the only demarcation for when vegetation is a threat to the
lines is the clearance 2 or CCZ areas, it would make sense to have this area be larger rather than
smaller. Accordingly, I would recommend that the Clearance 2 value continue to be used instead of
the Gallet equation-created CCZ.
I have no expertise to respond to this question.
Disagree
If frequency of inspections are required to be specified, it is implied that the inspections will follow. I
suggest that R3 be eliminated and R1.2 be reworded to say: "Vegetation inspections shall occur at
least once per year, or more frequently as dictated by local and environmental factors. Specify the
frequency of when vegetation inspections will occur."
Disagree
One concern with the proposed wording is that the verbiage seems to provide a loophole that will
count any fallen tree, or tree with the potential to fall from inside or outside of the R/W (that doesn't
meet the criteria in footnotes 4 & 5) that passes or could pass through the CCZ, and that may or may
not cause an outage, would qualify as a violation in the std. There is no other language that I can
detect in the std. that counters this point. Determination of whether or not a fallen tree, or tree with
the potential to fall would qualify would be predicated upon height measurements of the fallen or
standing tree(s) relative to the CCZ at max. engineered sag. An alternative wording suggestion is:
"Each Transmission Owner shall prevent encroachment within the Critical Clearance Zone of it's
applicable lines associated with trees that meet the criteria for grow-ins from on or off the Active
right-of-way. Fall-ins from inside or outside of the active right-of-way are not applicable to this subrequirement." If the occurrence is a violation, reporting of the incident will be an ethical issue and rely
on the honesty of the inspector or whomever finds the problem. If it's not a violation, it will be more
likely that the incident will be reported and can be treated as "Near Miss' reports are with respect to
safety incidents - they provide valuable input to help forestall future more serious incidents.
Consequently, I recommend that no violation occur as long as the 'Imminent Threat Procedure' is
implemented. Further, if there is no violation associated with Imminent Threat Procedure
implementation, I would suggest that falling or standing trees orginating from within the active rightof-way that encroached or could encroach in the CCZ be added to the requirement to enhance the
'Near Miss' datapool.
Agree
Disagree
As in question no. 14 above for R1.2, it would seem to make more sense to combine R1.3 & R8 as
follows: "Require development and implementation of an annual plan that…."
The Applicability Section of the Reliability Standards (4.2 Facilities) defines the Transmission Lines
(Applicable Lines) that must comply to the reliability standard. This section should clearly state that
the scope is limited to the facilities that are Bulk Electric System facilities consistent with the Bulk
Electric System definition as defined by the Regional Entity. Regarding M5, M6, M7: The intention of
these paragraphs is unclear to me as written. At first glance, it appeared that the paragraphs were
asking for a negative to be proven, e.g. prove that you didn't have any tree-related outages. Anther
possible meaning is that utilities have to justify the cause of any outage that may occur. As such, the
burden of proof is on the TO to provide evidence that an outage was not caused by trees. If an outage
were to occur but the TO could not find any evidence of the cause, the wording in these paragraphs
suggests that by default, the outages will be classified as tree-related. If these paragraphs are
intended to assign an outage cause to an outage that has already occurred, then perhaps they could
be reworded to say something to the effect of: "TO shall provide results of investigation into all
transmission outages……" If these paragraphs are not intended to assign an outage cause to an
outage that already occurred, but to provide a mechanism to report outage performance that is
currently covered in M3 and M4 in FAC-003-1, then perhaps they could be reworded to say something
to the effect of: "TO shall provide documentation of tree-related outage performance on a quarterly
basis. Investigation results for unknown outages shall also be provided on a quarterly basis." Or as
one last suggestion, the wording could simply be: " The TO has evidence that there was a Sustained
Tree-related Outage…. Regarding the Tech. Reference, I thought that overall it was helpful and will
be valuable to help provide guidance for TVMP development and implementation. The area that
covers the Active/Inactive R/W should be more clearly explained and illustrated, particularly with
respect to the towers with space for another circuit on one side of the structures.
Individual
Greg Rowland
Duke Energy Corporation
Disagree
Duke disagrees with changing "electric transmission systems" to "Bulk Electric System" because this
creates the potential for confusion or indiscriminate expansion of the scope of applicability to 100kV
facilities which may not have an impact on network system reliability. Using "Bulk Electric System"
confuses the applicability of the standard. Duke believes that Section 4.2 has the specificity to clearly
designate any applicable lines. Thus, the term "electric transmission systems" is appropriate.
Disagree
Duke believes that the Planning Coordinator is the appropriate entity to identify any sub-200 kV
facilities that this standard should apply to. Of note is the time frame – once a sub-200kV line is
designated, then the TO has 12 months before the line is subject to the standard. This coincides with
the longer term view of the Planning Coordinator.
Agree
Agree
This is a good change from a compliance perspective; the documentation requirements can now be
assigned lower VRFs than the implementation requirements.
Agree
Agree
Disagree
Duke believes that Transmission Owners should have a Vegetation Imminent Threat Procedure, and
"Vegetation Imminent Threat" should be a defined term, defined as: "Vegetation observed in the field
encroaching upon a conductor within a distance that is twice the Gallet clearance distances referenced
in Table I of the draft standard FAC-003-2." In this case, the threat would require an immediate
response and would include communication to the Transmission Operator. From there, the actions
that the operator decides to take will be dependent on the incident and system conditions. We do not
need to be prescriptive with this requirement but rather allow the Transmission Operator and
appropriate field personnel the flexibility to make the right decisions to safely, promptly and
appropriately remove the vegetation threat. From a Transmission Owner's perspective, many
situations can constitute an imminent threat but this approach will clearly define a "Vegetation
Imminent Threat" as it relates to the Purpose of this standard. See our related comment on #11
below.
Agree
Agree
Agree
Disagree
No. Duke believes that the CCZ is a good theoretical concept to aid industy in understanding the
overall movement of conductors, but it is an impractical concept for field application. Due to the
variability in the size of the CCZ as you move along a conductor, as well as changes from span to
span or even line to line due to design parameters, loading or weather-related issues, the CCZ
concept should not be tied to an imminent threat procedure. Vegetation approaching the CCZ does
not constitute an imminent threat. It may be years before this vegetation ever gets to a proximity
distance from the conductor to be within a "spark-over" distance as defined by the Gallet equations.
Requirement R2 should support the purpose of this standard by requiring implementation of the
Vegetation Imminent Threat Procedure when the Transmission Owner has visual, field knowledge that
vegetation is encroaching upon a conductor within some specific distance that is a multiple of the
Gallet distances referenced in Table I of FAC-003-2 (to be conservative we suggest two times the
Gallet distances). Failure to implement the Vegetation Imminent Threat Procedure in such instances
would be a violation of R2. As R2 is currently stated, a Transmission Owner cannot comply with R2
unless the imminent threat procedure is continuously being implemented, because vegetation that is
growing is always approaching the CCZ. "Approaching the CCZ" cannot be the trigger for
implementation of the Vegetation Imminent threat Procedure. Instead, the trigger should be an
encroachment within an observed distance from vegetation to conductor that is twice the Gallet
distances in Table I. Requirement R2 could be reworded as follows: “Each Transmission Owner
shall implement its Vegetation Imminent Threat Procedure when the Transmission Owner has
knowledge, obtained through normal operating practices or notification from others, that vegetation is
encroaching upon a conductor within a distance that is twice the Gallet clearance distances referenced
in Table I." Using a multiple of the Gallet distances provides a safety factor. Assessing a violation for
failure to appropriately implement the Vegetation Imminent Threat Procedure or for a sustained
vegetation-related outage incents the proper behavior.
Agree
Agree
Agree
Disagree
The second bulleted alternative above is the best approach, but Duke believes it should be improved
by changing the imminent threat trigger from "encroachment of the CCZ" to "encroachment within
some observed, field distance that is a multiple of the Gallet distances referenced in Table I". We
have recommended changes to accomplish this in Requirement R2 (see our response to Question #11
above), and R4 should simply be deleted. While the CCZ is valuable to understanding the movement
of conductors, it cannot be readily applied in the field. This field application challenge is noted in the
Technical Reference Document (pages 29 & 30). The way R4 is currently stated, the Transmission
Owner would be in violation of R4 for any CCZ encroachment not due to natural disasters or human or
animal activity. This would include a tree falling from outside the right of way corridor that passes
through the theoretical CCZ. Furthermore, Transmission Owners would be required to self-certify
compliance with R4. The technological requirements for accurately certifying compliance would be
impossible to administer. Clearly the approach of assessing violations for CCZ encroachment is
unworkable. Likewise, the third alternative listed above is untenable. The tiered approach could have
a mitigating effect on violations, but it would require the same inspection effort and postponement of
vegetation management that makes the first alternative unworkable. Both the first and third
alternatives would require very significant additional expenditures for surveys and documentation in
an impossible attempt to certify compliance - money that would be better spent controlling
vegetation.
Agree
Agree
Duke agrees with the requirement to implement the annual work plan, but recommends striking the
words "within the extent of its easement and/or legal rights". The emphasis for this requirement is to
execute the annual work plan. The white paper already speaks to the point that it is a best practice
for utilities to exercise their legal rights. If we agree that the goal is to prevent outages, then we can
simply end this requirement with "accomplish the purpose of the standard". Each TO will be
accountable to manage compliance with this standard.
FAC-003-1 lacks clarity that is essential for understanding what is necessary for compliance. The
proposed FAC-003-2 needs to be simplified to aid with field implementation and compliance
interpretation. Currently, it does not provide the clarity and simplification needed by Transmission
Owners and regulatory bodies to enhance reliability.
Group
IRC Standards Review Committee
Charles Yeung
Southwest Power Pool
Disagree
We do not see the role of an RC or PC in a vegetation management standard. All TOs need to ensure
they have a vegetation program to avoid unnecessary tripping of transmission lines, at any voltage
levels and regardless of their impacts on the BES. Identification of critical facilities is not a part of this
standard; it belongs to other standards that deal with SOL/IROL calculations, SPS, protection and
critical infrastructure protection. R9 and R10 should be removed from the standard.
Group
E.ON U.S.
Brent Ingebrigtson
E.ON U.S.
Disagree
The definition of the Bulk Electric System generally does not include radial transmission lines directly
serving load and, in addition, includes all lines operated at 100 kV and above. Use of the term Bulk
Electric System will cause unnessesary confusion to the industry concerning applicability of this
standard. Therefore, we recommend the continued use of the undefined term "electric transmission
systems."
Agree
Agree
Agree
Agree
Disagree
The Requirement as written is too prescriptive and is open to interpretation, from an audit
perspective, with use of the term “immediate†communication and a partial list of activities.
Many conditions or threats, requiring immediate removal, would not require communcation with the
Transmission Operator, who is not an applicable entity for this standard. We suggest that R1.4 be
deleted. Since this is a "zero tolerance" standard any Transmission Owner will remove any discovered
threats to prevent outages. If R1.4 is not deleted, we believe that imminent threats should be a
defined term. The definition should be as follows: “Imminent Threat: A vegetation condition which,
if not addressed, will place a transmission line at a significant risk of a Sustained Outage.â€
Agree
Agree
Agree
Disagree
E.ON U.S. suggests that R2 be deleted. Since this is a "zero tolerance" standard any Transmission
Owner will remove any discovered threats to prevent outages. While we agree that the
implementation of an imminent threat procedure may be a valid concept, visualization of the Critical
Clearance Zone and determining an approaching encroachment is a practice in application of
theoretical conductor locations in real time.
Agree
Agree
Agree
Disagree
The concept of the Critical Clearance Zone is useful as a mental model to visualize required vegetation
management work. While this is a good conceptual tool to drive consistent terminology and proper
vegetation management practices, it remains theoretical in nature and impractical to measure on a
span by span basis. The complexity of determining an encroachment into the Critical Clearance Zone
is overly burdensome due to the need for survey accuracy measurements and engineering
evaluations. In addition, this complexity leads to questions about the ability to audit this requirement.
These complexities introduce reliability and audit issues when encroachments into this conceptual
area are defined as violations. We believe the Sustained Outage, as defined by other measures in this
standard, should be the non-compliance measure. We suggest that the Critical Clearance Zone
concept be kept in the technical white paper and that all references to the Critical Clearance Zone be
removed from the body of the standard.
Agree
Disagree
E.ON U.S. believes that the Requirement, as written, is “open ended†and could be interpreted
to be in conflict with the "Active Rights of Way" concept. Clarifying the intent for the annual plan to
focus on the Active Rights of Way will prevent incorrect interpretations. We suggest that the
Requirement be reworded to read: “Each Transmission Owner shall implement its annual work
plan for vegetation management within the Active Right of Way to accomplish the purpose of this
standard within the extent of its easements and or legal rights.â€
Individual
Michael Pakeltis
CenterPoint Energy
Agree
Agree
Disagree
The term "Active Transmission Line Right-of-way" is not defined in sufficient detail in the Definition of
Terms Used in the Standard section to know how to apply the Requirements. The term causes a
circular reference problem with the term "Critical Clearance Zone" that refers to the "limits of the
Active Transmission Line Right-of-way" which has no specific definition as to its limits within the
proposed revised Standard. There is an attempt to differentiate between the "Total R.O.W." and the
"Active R.O.W." portion by using the phrase "occupied by active transmission facilities", but no
specific limits of such occupation are included within the definition. Are "active transmission facilities"
only the physical energized conductors as-is, where-is? Does "occupied" include the conductor vertical
and horizontal movement envelope and any horizontal and vertical electrical clearance as well? Does
the term "Active Transmission Line Right-of-way" refer to the legal limits of the right-of-way? The
new R8 includes the phrase "within the extent of its easement and/or legal rights" which seems to
support that definition. The phrase "a strip of land" seems to refer to a metes and bounds description,
but how is that relevant when no specific land space is defined, such as with a railroad occupation or
Corp of Engineer's permit? On page 16 of the Technical Reference, there is a reference to the Bramble
and Byrnes wire-border zone technique. The wire zone is defined in the Technical Reference as "the
section of a utility transmission right-of-way directly under the wires and extending outward about 10
feet on each side". Are the limits of the "Active Transmission Line Right-of-way" intended to be
equivalent to the Bramble and Byrnes wire zone, or is the Transmission Owner to use its discretion to
define the limits? The examples in the Technical Reference document do not define the limits of the
"active transmission facilities" either. The "Active R.O.W." limit in Figure 1 and Figure 3 is arbitrary.
Figure 2 is supposed to display an edge zone for vegetation to exist, which implies an "Inactive
R.O.W" portion, but no such zone is defined. Figure 1 also has trees shown inside the "Total R.O.W."
and within the "Inactive R.O.W." that are tall enough and close enough to be within falling distance of
the active transmisssion line which seems averse to R7 for vegetation falling into a conductor when
the Transmission Owner likely has legal rights to remove them if they are within the "Total R.O.W."
and are within falling distance. The interpretation of M7 will be difficult in this case without a specific
method to define the "Active R.O.W." portion of the Total R.O.W. We recommend deleting the
confusing terms "Active Transmisssion Line Right-of-way and "Critical Clearance Zone" and returning
to the prior Clearance 2 Requirement with the newly specified minimum clearances from Table I of
Attachment 1 as an alternative approach should the definition of minimum vegetation clearance
distances remain integral to the Standard.
Disagree
Additional revisions are needed to clarify the requirements. For instance, R1.3 refers to "the
objectives" of the TVMP, which are no longer a required element and are not specified in M1.3.
Reference to "the objectives" should be deleted. The last sentence of R1.3 should read: "It shall use
the methodologies outlined in the transmission vegetation management program." R1.4 requires a
process for a response to an "imminent threat of a vegetation related Sustained Outage", but R2
refers to implementing an "imminent threat procedure" to "prevent an encroachment of the Critical
Clearance Zone". The requirement and the implementation should both refer to an "imminent threat
of a vegetation related Sustained Outage".
Disagree
The Standard and the Technical Reference provide no specific justification for defining a 1-year
inspection frequency and is abritrary. The requirement itself does not take into account "local and
environmental factors". Since the type of inspection is not specified within the Standard, a frequency
of at least once per calendar year is currently workable for CenterPoint Energy, but it may not
necessarily be appropriate for Transmission Owners with sparsely vegetated service territories. The
Technical Reference for R1.2 should state, "the Transmission Owner is given discretion as to the
inspection method", and "that while the inspection frequency is specified, it is not the intent of the
Standard that all vegetation be maintained on the same frequency". For example, CenterPoint Energy
currently utilizes a 5-year ground-based inspection cycle coupled with a 5-year cycle for vegetation
maintenance, and performs a supplemental annual aerial inspection.
Agree
See comments to Q4 above as well.
Agree
Disagree
Since there is no longer a reference to defined clearances in the Standard, it is unclear under what
specific "constrained" conditions R1.5 applies. R1.5 does not have a sister requirement for
implementation within the Standard which implies it has a diminished value. R1.5 and M1.5 should be
deleted as a requirement and measure, but should be footnoted as best practice as was ANSI A300 in
R1.1.
Agree
Designation of Clearance 1 is not required to meet the purpose of the Standard.
Agree
Designation of Personnel Qualifications are not required to meet the purpose of the Standard.
Agree
We agree with replacing IEEE 516 standard distances with the Gallet equation standard distances.
However, the term "Critical Clearance Zone" refers to the "limits of the Active Transmission Line
Right-of-way" which has no specific definition as to its limits within the proposed revised Standard.
(See comments to Q3 above.) R2 should be reworded to coordinate with R1.4. (See comments to Q4
above.)
Agree
Agree
Agree
Disagree
It is not reasonable to expect Transmission Owners to devote resources, both human and financial, to
prove that vegetation never encroached into the Critical Clearance Zone, anytime-anywhere. R4 and
M4 should be deleted. R2 and M2 are sufficient in ensuring a level of reliability equal to or better than
FAC-003-1 with some minor wording changes to adopt similar wording of the alternative to R4 that
was considered by the drafting team that includes "immediate implementation of the imminent threat
procedure" for imminent threats of a vegetation related Sustained Outage in lieu of a nebulous
"encroachment of the Critical Clearance Zone". According to the Technical Reference, it is "nearly
impossible to field correlate and accurately 'superimpose' the Critical Clearance Zone around the
conductor". It not likely that the Transmission Owner will know when the Critical Clearance Zone is
approached through field observation. The previous Clearance 2 provided for a specific radial
clearance from the conductor that was much easier to observe. (See comments to Q3 above.)
Agree
We agree with the exemptions; however, R6 and R7 refer to an "Active Transmission Line Right-ofway" which is not defined as to its limits, so M6 and M7 cannot be determined by definition. See
comments to Q3 above relating to the definitions and the examples in the Technical Reference.
Agree
R8 requires implementation of the annual work plan "within the extent of its [the Transmission
Owner's] easement and/or legal rights." All measures and compliance should be determined on this
basis as well. This concept should also be carried through the definitions for "Active Transmission Line
Right-of-way" and "Critical Clearance Zone", or for any definition of clearances should the Standard
continue to utilize such terms.
The proposed FAC-003-2 has gone FAR beyond what was contemplated by the Commission in FERC
Order 693 and equates to a total re-writing of the Standard for no apparent reason. The
Commission's determination dealt with the following areas: (1) applicability; (2) inspection cycles;
and (3) minimum clearances on National Forest Service lands. For instance in Paragraph 729, the
Commission states, “As proposed in the NOPR, the Commission approves Reliability Standard FAC003-1 with no proposed modification on the issue of clearances. The Commission reaffirms its
interpretation that FAC-003-1 requires sufficient clearances to prevent outages due to vegetation
management practices under all applicable conditions….†Rewriting the minimum clearances
introduced a new set of confusing definitions, and further burdens the Transmission Owners with new
documentation requirements with little if any benefit when compared to the Clearance 2 concept in
the existing Standard. A preferred approach would have been to incorporate the following few items
into the existing Standard: (1) the RC versus the RRO; (2) the designation of a specific inspection
frequency; (3) the Gallet equation; and (4) the applicability to National Forest Service lands. We
agree that the removal of requirements for quarterly reporting of outages, Clearance 1, and personnel
qualifications reduces the burden on the Transmission Owners and does not affect the purpose of the
standard to prevent vegetation outages. The Standard could meet its purpose and be streamlined by
considering the following changes: 1. Delete the new terms and definitions for "Active Transmission
Line Right-of-way" and "Critical Clearance Zone" and revert back to a Clearance 2 requirement while
replacing the IEEE 516 standard distances with the Gallet equation standard distances. 2. Delete R2,
M2, R4 and M4 which refer to the "Critical Clearance Zone" and rely on R5, M5, R6, M6, R7, and M7
which refer to the prevention of Sustained Outages. 3. Delete R1.5 and M1.5 as a requirement and
measure, but footnote the "interim corrective action process" as a best practice as was ANSI A300 in
R1.1.
Group
Bonneville Power Administration
Denise Koehn
Transmission Reliability Program
Agree
Agree
Disagree
R1: BPA understands that version 2 clearly states that the Critical Clearance Zone does not extend
beyond the Active Transmission Right of Way. The Technical reference provides examples of active
and inactive portions of corridors. BPA feels this list of examples is not exhaustive and therefore the
technical reference language should be changed to read, "Examples of active and inactive portions of
corridors include, BUT MAY NOT BE LIMITED TO:" Also, since it is clearly stated on page 2 of the
Standard, that the Critical Clearance Zone shall not extend beyond the limits of the Active
Transmission Line Right of Way, and that these limits are not specifically defined because they may
vary by circumstance, the definition of Active Transmission Line Right of Way on Page 2 of the
Standard should include a statement that the actual physical limits of each Active Right of Way will be
determined by the Transmission Owner. R1.1: BPA recommends retaining the version 1 language of
"objectives, practices, approved procedures, and work specifications" as it is more instructive in what
is expectied of a TMVP then the version 2 replacement language of "methodologies."
Agree
Agree
It would be helpful to clarify what is expected in regards to what constitutes an inspection. This could
be done in the technical reference. Some Transmission Operators inspect vegetation as part of line
patrol that focuses on more than just the condition of vegetation along the Right of Way. It should be
clear that the Transmission Owner, though required to complete a inspection frequency of at least
once per calendar year, has the ability to implement the type of inspection it deems necessary. Also
the frequency of once per calendar year may create some unintended reporting difficulties if
Transmission Owners currently track progress and completion of inspections using a differenct
convention than calendar year, e.g., fiscal year or other period. It may be helpful to change the
wording of R1.2 from "at least once per calendar year" to "once in a twelve month period."
Agree
Agree
BPA agrees with 1.4, with the following change. The ending phrase: "and may include actions such as
a temporary reduction in line Rating, switching lines out of service, or other actions" should be
eliminated. Not only does BPA feel it is inappropriate to use advisory-type rather than declarative
language in a Standard, BPA feels it is also questionable to give examples of imminent response
actions that are often not within the direct capability of a vegetation program to enact. Eliminating
the reference to these possible actions leaves it up to the Transmission Operator to decide what the
eminent threat response is.
Agree
Disagree
BPA opposes removal of Clearance 1. Clearance 1 provides a regulatory justification for a
Transmission Owner to apply and extend proactive vegetation threat prevention programs on its
rights of way easements across municipal, state, tribal, other federal and private properties. In many
cases, without the regulatory leverage of a Clearance 1 requirement, Transmission Owners would be
limited to maintaining less effective and higher risk vegetation management practices where it has
legal restrictions, then it presently can implement under the present version of FAC 003-01. BPA
recommends that Clearance 1 be placed back into the document , but as a Measure and not a
Requirement.
Agree
Agree
BPA agrees with R2, but refer to comments submitted regarding R4 (please see our response to
Question #15) for related recommendations to R2.
Agree
Agree
Agree
Disagree
R4 states that the Transmission Owner is in violation of the Standard if the Critical Clearance Zone is
encroached upon. The CCZ, as defined by the Standard, changes along the transmission line from the
insulator to mid-span, depending on loading, actual operating temperature, wind and ice loading,
maximum design rating and operating load, etc. Also, the tandem, Measure M4, requires that the
Tramsission Owner has evidence demonstrating that there has been no vegetation encoachments in
the CCZ along its transmission system. In order to meet the letter of the Standard, that is to provide
evidence that no encroachments in the CCZ have occurred under all manner of these fluid
environmental and operating conditions, the Transmission Owner would have to employ the highest
level of modeling technology available, which would seem to be LiDAR technology. The standard
should not be written in such a manner so that it requires, by all intent and purpose, a Transmission
Owner to acquire a particular technology. BPA recommends that the Alternative represented by "the
second bullet" above, be used rather than R4 in its present state, or that R.4. be simply dropped and
R1.4 modified to state that the imminent threat procedures include immediate removal of
encroachments into the Critical Clearance Zone. Also, the term "immediate" implies instantaneous
response. The use of another term is recommended, such as "as immediate as human health and
safety considerations allow, in order to prevent the possibility of flashover".
Agree
Agree
There is a typographical error / omission in the Technical Reference on Page 36, which states, "R6.
Each Transmission Owner shall prevent Sustained Outages of applicable lines due to the blowing
together of vegetation and a conductor with (sic) Active Transmission Line Right of Way) operatiing
within design blow-out conditions) with the following exception: . . . " I believe the intent is for the
statement to read "due to the blowing together of vegetation and a conductor WITHIN Active
Transmission Line Right of WAY". This change is needed to make the technical reference consistent
with R6. as it appears in the Standard, the definition of Active Transmission Line Right of Way on
Page 5 of the Technical Reference, as well as the terminology used on Page 37 in describing Fall-into
outages. This needs correction.
Group
Public Service Electric and Gas Company
Jeffrey C. Mueller
Public Service Electric and Gas Company
Disagree
An additional clarifying exception in the footnotes to R4 consisting of a tree that is located off of the
transmission owner's right of way falling into the CCZ should be added to the encroachment
exceptions. Transmission owners should not be found in violation of the standard for falling vegetation
located off of the TO's property.
These comments were prepared by Richard Wolowicz, Manager Vegetation Management, on behalf of
Public Service Electric and Gas Company ("PSE&G"). PSE&G also joins with and supports the
comments filed by the Edison Electric Institute (EEI) in this matter.
Individual
Ed Davis
Entergy Services
Disagree
Entergy disagrees with changing “electric transmission systems†to “Bulk Electric
System.†Historically, the definition of the Bulk Electric System has included all lines operated at
voltages 100 kV and greater. The above change in terminology will add ambiguity to which lines this
standard is applicable. Entergy is concerned about the potential for this ambiguity leading to the
expansion of the applicability of the standard to include lines below 200kv.
Agree
The applicability of this standard should state that it is not applicable to insulated transmission lines,
such as underground lines.
Agree
Agree
Agree
Agree
Disagree
1. The requirement should state that each Transmission Owner will be responsible for creating and
maintaining a Vegetation Imminent Threat Process. This process will clearly define how the
Transmission Owner defines a vegetation imminent threat. 2. The requirement needs to state that
only vegetation conditions identified, to the Transmission Owner, by regular field inspections,
including aerial inspections, and other internal and external verifiable reports of vegetation imminent
threats will be managed through this process. 3. If the standard requires a process to mitigate
potential immediate threats to the system, the term “vegetation imminent threat†must be
defined. This definition must not delineate the precise steps that are required to be taken to allow
experts as many options as necessary to address each vegetation condition specifically. 4. The list of
possible mitigating actions should be removed from the standard since it is not an all inclusive list.
Listing these actions in the standard may imply that the entity must do one or all of the actions to be
in compliance. The entity must have sufficient latitude to evaluate each possible vegetation condition
and apply the most appropriate mitigation steps, up to and including the removal of the identified
vegetation.
Agree
Agree
Agree
Disagree
: 1. Entergy suggests that the requirement for activation of the vegetation imminent threat process
should not be tied to the Critical Clearance Zone and that the each entity should define the activation
of their vegetation imminent threat process. Tying the activation of the imminent threat process to
the Critical Clearance Zone is limited in that this criterion does not address the possibilities of
vegetation falling into the line or Critical Clearance Zone. 2. In the sentence “Critical Clearance
Zone approached by vegetation†– the use of “approached†is subjective and not
specifically quantifiable. Effective, uniform activation of the imminent threat process will require
objective measurement criteria. 3. The standard needs to include a clear statement to the effect that
when the Transmission Operator is notified of a potential vegetation problem, obtained by normal
operations and inspections, the entity will activate the Vegetation Imminent Threat Process. 4) This
requirement, as stated, is redundant. The requirements for maintaining the Critical Clearance Zones
and / or avoiding vegetation outages, and the associated Violation Risk Factors and Violation Severity
Levels, already reinforce the desired behavior of the entity to identify and mitigate any potential
issues before the possibility of vegetation causing an outage.
Agree
Agree
Agree
Disagree
1. Entergy believes that outages caused by vegetation are the most reasonable and objective
measures for a violation which is not consistent with the proposed R4. See additional comments in
section 16 related to R5, 6, and 7. 2. If R4 remains, Entergy proposes that the most reasonable
approach to this requirement is a variation of the second bulleted option. This variation would include
wording clarifying that only known encroachments of the Critical Clearance Zone would be considered
violations. Entergy is willing to include failures to enact the imminent threat process (which is really a
violation of R2) and also known vegetation inside the Critical Clearance Zone. This variation should
continue to include the exceptions for natural disaster and human activities. 3. Determining objective,
quantifiable encroachments into the Critical Clearance Zone is very challenging in field operations
because such determination may require a degree of accuracy only obtainable using survey
equipment or other sophisticated, costly measuring devices. 4. Entergy is concerned about the
challenges of uniform auditability due to noted uncertainties and the statement of absolute criteria
that have to be shown in the negative. If the first bullet option is approved for R4, Entergy suggests
the sentence “Evidence will be required to prove that no encroachments of the Critical Clearance
Zone have occurred anywhere at the any time during the annual compliance period†be deleted. It
is very difficult in regulatory terms to attest that no vegetation has ever crossed the Critical Clearance
Zone during the time period being reviewed given the wide range of potential conditions that may not
have been detected or even been detectable unless the conditions afforded direct observation. Too
many assumptions would have to be made for an entity to self certify to this requirement. If R4 is
implemented as stated, those assumptions need to be stated and clarified. 5. If any version of R4 is
approved, Entergy suggests that the standard include an exception for trees falling from off the right
of way and encroaching the Critical Clearance Zone. For example, a tree that falls from off the right of
way. During the fall towards the conductor, the tree could possibly break the Critical Clearance Zone
without causing an outage or even a threat of an outage yet still be a violation of the proposed
standard. 6. If the second bulleted item is approved, it should be altered to read “a violation would
have occurred only if no vegetation imminent threat process was initiated.†7. Entergy does not
feel the third bulleted item is adequately defined to use as a requirement in the standard at this time.
8. Conditions for blow-out, in the development of the Critical Clearance Zone, need to be defined in
the standard. Their inclusions, in the white paper only, are not appropriate, as well.
Disagree
1. If a version of R4 that states an encroachment to the Critical Clearance Zone is a violation, Entergy
disagrees with the need for R5, R6, and R7 because it is redundant to R4. An outage cause by
vegetation: a) growing into the line b) blowing into the line and c) falling into the conductor would
require the vegetation to break the Critical Clearance Zone. If these requirements stay in the
standard, an outage of the above nature would mean the entity violated two requirements, R4 and
R5, R6, or R7. 2. Entergy is amenable to keeping R5, 6, and 7 if R4 is removed from the standard. 3.
If approved, we suggest that R5, 6, and 7 not apply to trees from off the right of way.
Agree
Entergy would like to note that requirements R1.3 and R8 are administrative requirements that add
marginal value to the reliability of the Transmission System. Since entities are required to have
flexible annual plans, deviations from the annual plan only need to be documented and these
requirements will be met. Entergy utilizes annual plans as a good practice but sees limited value with
the inclusion in this standard.
Entergy requests that the proposed FAC-003-2 revision continue work on clarifying the above
mentioned “Disagree†items and appreciates the consideration of the above comments in the
development of the standard. A clear understanding of all standard requirements by the industry is
needed to make certain field implementation is achieved and that ultimately we improve system
reliability.
Individual
Anita Lee
Alberta Electric System Operator
Disagree
The AESO believes that the inspection schedule should consider local and environmental factors that
may impact the anticipated growth rate of vegetation. In many of the areas in Alberta, due to cold
climate and arid conditions, we have slow vegetation growth rates. The requirement for minimum
annual inspection is not necessary. We recommend the inspection schedule be determined by the
Tranmisssion Owner and documented in its vegetation management plan.
The AESO is also a signatory to the joint ISO/RTO Council Standards Review Committee comments
which reflect our comments to the other questions in the Comment Form.
Group
FirstEnergy
Sam Ciccone
FirstEnergy Corp.
Agree
Agree
Agree
The Inactive Right of Way, by definition, should include a strip of trees on each side of the of the right
of way that was purchased, but not cleared at the time of construction. This could be a narrow strip
ten feet on each side that is intended for future hazard tree removal.
Agree
Agree
Agree
Although we agree with R1.3, we suggest it be broken up into subrequirements to allow for better
clarity to the reader as well as aid in the development of violation severity levels when developed. We
suggest the following: R1.3. Require an annual plan that includes the following as a minimum: (Note:
Adjustments to the plan within the year are permissible) R1.3.1. It shall identify the applicable lines
to be maintained and associated work to be performed during the year. R1.3.2. Is shall be flexible to
adjust to changing conditions and to findings from vegetation inspections. R1.3.3. It shall take into
consideration permitting and scheduling requirements from landowners or regulatory authorities.
R1.3.4. It shall support the objectives of the transmission vegetation management program and use
the methodologies outlined in the transmission vegetation management program.
Agree
The safety of the personnel required to remove a tree or vegetation on or near an energized
conductor must be considered when implementing the imminent threat procedure. Although this is a
reliability standard, the safety of the personnel may be one "trigger" to implement the imminent
threat procedure. That being said, the workers on site, in their judgement, are not able to remove the
vegetation safely then the imminent threat procedure would be implemented. See comments for CCZ.
Agree
We agree with the concept of a corrective action plan. However, it is not clear what flexibility the TO
is afforded in making adjustments to the work plan that may carry over from one calender year to the
next. Legal issues with property owners or other factors may prevent the utility from carrying out the
work plan as scheduled. Also, we question the use of the term "constrained". It should be clear as to
what constitutes appropriate or valid constraints.
Agree
Agree
Disagree
The CCZ is not equal to Clearance 2 in FAC-003-1. Per requirement R4, any encroachment into the
CCZ is a violation of the standard even if an outage does not occur. This is too strict because it refers
to a "0" tolerance even for encroachments that do not affect reliability. This can be an extremely
costly standard to comply with that may or may not improve reliability. The CCZ distance is a difficult
to determine from one moment to the next based upon the description and calculations outlined. The
conditions on the right of way are dynamic and ever changing. It would be more proactive for the TO
to focus on implementing the TVMP rather than expending time and money trying to determine if the
CCZ has been violated. A better approach would be to establish a minimum clearance at all times
rather than to monitor encroachment to a theoretical CCZ.
Agree
Agree
Agree
Disagree
Providing evidence to prove that there were no encroachments of the CCZ is difficult at best. An
occurrence of an encroachment does not necessarily translate to an outage. The CCZ is dynamic and
difficult to measure exactly from span to span and day to day and is dependent on environmental and
line conditions. The costs to comply with this requirement as written are difficult to justify considering
that reliability may not be improved at all. FirstEnergy believes that the first alternative above should
be used and is a more logical approach from both a reliability and compliance standpoint.
Furthermore, since the first alternative is already covered by the currently proposed wording of R2,
the only changes needed to the standard are to remove the proposed R4 and M4 and re-number the
requirements.
Agree
Agree
FirstEnergy agrees with the intent of R8, but the standard should be clarified by removal of the word
"easement". As written the standard is open to interpretation between "easement" and active right of
way. It is important to have the term "legal rights" remain in the standard. The TO should be held
accountable to fully enforce the legal rights outlined in maintaining the active right of way. This will
lead to a more reliable transmission system.
FE provides these additional comments for consideration: 1. Regarding the Applicable Facilities Section 4.2.2 would be more appropriately placed under Sec. 5 "Effective Dates" since it deals with
the timeframe the TO has to implement its TVMP on sub-200 kV lines. - Section 4.2.3 - We suggest
removing this section. First energy does not agree that this standard should dictate the amount of
time a TO has to obtain compliance with this standard for newly acquired transmission lines. It should
be the responsibility of every organization to "self-report" its compliance issues and planned
mitigation plans for all standards when they acquire new lines or facilities. If the SDT believes this
should be explicitly stated, then it should recommend to NERC that explicit language be placed in the
NERC Rules of Procedure. No other standards set timetables for newly acquired facilities and this
standard should be no exception. 2. Regarding R1.1, this subrequirement requires the TO to specify
the methodologies it uses to control vegetation. It should be clear that not all of these methodologies
are required to be deployed in every situation (as explained in the white paper pg.12). We suggest
rewording the requirement as follows: "R1.1. Specify the methodologies that the Transmission Owner
may use to control vegetation." 3. R1.5 requires a process for "interim corrective action" be specified
in the TVMP. However, the standard does not explicitly specify that this corrective action be
implemented when the TO is constrained from performing vegetation maintenance as planned. 4. As
written, in addition to the responsible RC, R9 may imply that this requirement is also the
responsibility of the TO(s) and neighboring RC(s) due to the use of the term "jointly". Also, R9 should
require the RC submit the list of designated lines below 200 kV to the TO(s) and neighboring RC(s)
within a reasonable time-frame after its completion. We suggest rewording and addition of
subrequirements to R9 as follows: R9. Each Reliability Coordinator, in consultation with its
Transmission Owner(s) and neighboring Reliability Coordinator(s), shall prepare and keep current a
list of designated applicable lines that are operated below 200kV, if any, which are subject to this
standard. R9.1. The RC shall submit the list to the impacted TO(s) within 30 calendar days of
completion and/or revision. R9.2. The RC shall submit the list to its neighboring RC(s) within 30
calendar days of completion and/or revision. Lastly, measure M9 will need to add sub-measures for
the proposed additions above. 5. Requirement R10 should require that the RC ONLY uses the
assumptions detailed in R10.1 and R10.2 to designate a line as significant. Also, R10.1. should
reference the IROL methodology standard FAC-011 since it directly ties into this requirement. Also, in
R10.2, "grid" should be replaced with "BES" and the term "failures" is not necessary. We suggest rewording R10, R10.1 and R10.2 as follows: R10. Each Reliability Coordinator shall document its
method for assessing the reliability significance of sub-200kV lines and shall be based only on the
following: R10.1 Transmission lines whose loss would result in the exceedance of an Interconnection
Reliability Operating Limit (IROL) as determined by standard FAC-011. R10.2 Transmission lines
whose loss would place the BES at an unacceptable risk of instability, separation, or cascading.
Individual
Richard Kafka
Pepco Holdings, Inc
Agree
Agree
FERC Order 693 essentially has the RC replacing the RRO.
Agree
Agree
Disagree
While an annual inspection is reasonable and appropriate for all but very low precipitation areas, In
Order 693, the Commission directs the ERO to develop compliance audit procedures, using relevant
industry experts, which would identify appropriate inspection cycles based on local factors. The SDT
does not seem to have thaken the local factors into account. FERC also does not want to leave this up
to the Transmission Owners. While the standards being developed are moving many things to the RC,
PHI sees that as the only way to have someone other than the TO determine an inspection cycle that
would consider local factors.
Agree
Disagree
While an imminent threat procedure is prudent and reasonable, it does not need to consider a Critical
Clearance Zone as addressed in our comments on other questions. In fact, one can quickly provide
examples of imminent threats when the threat is not even on the right of way. The TO should simply
have an imminent threat procedure to address identified imminent or potential imminent threats.
Agree
Agree
Agree
Disagree
R5, R6 and R7 make this requirement redundant and unnecessary - it should be deleted. It is largely
unenforceable and does not make the standard clear, specific and regulatorily enforceable. Further,
PHI believes the concept of enforcing no encroachment into the Critical Clearance Zone is a flawed
approach.
Agree
Agree
Agree
Disagree
As discussed in our response to Q11, the concept of encroachment into the Critical Clearance Zone is
flawed. It is enforceable almost exclusively through self reports. R5, R6 and R7 provide all incentives
for the TO to follow its inspection and maintenance plans, and R2, if properly written to remove
references to the Critical Clearance Zone provides additional incentives. R4 is not needed and should
be deleted. PHI is puzzled where this concept came from. Nowhere in Order 693 is this concept
discussed.
Agree
There is no need for three separate requirements if the incident is a Sustained Outage, but there is
nothing inherently wrong with the three requirements.
Disagree
THE SDT has introduced the term Active Transmission Line Right of Way. R8 should use this term to
avoid any misinterpretation.
Individual
Virginia Cook and Kim Wheeler
JEA
Disagree
We disagree with this change as it may cause confusion on the applicability of the standard as the
BES is generally 100kV and above, but this standard generally applies to 200kV and above.
Agree
Disagree
The standard should EITHER require an entity to have and follow a program OR hold an entity to
performance standards, but not both. Requiring a procedure in conjunction with performance
requirements incents the entity to write procedures that meet only the minimum requirements of the
standard, as they will be audited and held accountable for what is documented and performance
against that. If performance requirements are in place without the concurrent requirement for a
procedure, then the entity is incented to develop procedures that meet best practices in order to
assure that they will meet or beat the performance standards, because in this scenario, such
procedures do not expose the entity to additional compliance risk while enhancing reliability.
Disagree
See comment from #3.
Agree
Although there are probably few areas where this is appropriate, the entity should be able to reduce
the required number of inspections with RC approval if they are able to demonstrate that vegetation
conditions surrounding transmission lines does not warrant inspections at that frequency.
Disagree
See comment from #3.
Agree
It is appropriate to require procedures to respond to "emergency" condidtions, however Imminent
Vegetation Threat should be a defined term.
Agree
Agree
Agree
Disagree
The use of Gallet equations is not practical either for field use or for demonstrating compliance.
Agree
Agree
Disagree
See comment from #3.
Disagree
As written, demonstration of compliance may not be feasible and would certainly be prohibitively
expensive, consuming resources better spent managing vegetation. In general, putting entities in the
position of proving something didn't occur is exptremely difficult and burdensome, without really
aiding reliability. If the incident was significant, the region would know about it, and investigations
can be pursued, if warranted. The first alternative requiring implementation of the imminent threat
procedure is a better choice.
Agree
Disagree
See comment from #3.
M5, 6 and 7 ask the entity to prove the negative. This type of evidence is problematic, and may result
in nothing better than the entity making an attestation that the event did not occur, thus this
measure is not useful. With well over 100,000 miles of transmission covered by this standard, even
six-sigma performance would result in vegetation related issues. It is unreasonable to expect zerotolerance for vegetation events and unneccessary for the industry (and customers) to expend
resources to attempt to meet this level of compliance when the transmission system is planned and
operated to handle any single contingency, which means that a vegetation contact should not, in
isolation, cause a major problem to the bulk power system. This standard needs work to make it
clear, unambiguous, feasible and enforceable.
Individual
Dan Rochester
Independent Electricity System Operator
Agree
Disagree
The IESO does not see a role for an RC or PC in a vegetation management standard. All TOs need to
ensure they have a vegetation program to avoid unnecessary tripping of transmission lines,
particularly those that impact the BES. We are of the view that identification of critical facilities is not
a part of this standard; it belongs to other standards that deal with SOL/IROL calculations, SPS,
protection and critical infrastructure protection. R9 and R10 should therefore be removed from the
standard.
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
We recommend removing the Transmission Owner as the one to define a major storm, this task
should be left to an applicable regulatory body only, for consistency in assessing such an event. Also,
we recommend footnote #5 specify that planned removal of vegetation by the utility is not part of the
exceptions, because in our view this activity is a component of the vegetation management program
and that outages should be preventable. There is a typo in R6. The numeral "4" should be
superscripted.
Individual
Karen Powell
Salt River Project
Agree
Agree
Disagree
R1.1 states "Specify the methodologies that the Transmission Owner uses to control vegtation". The
word "methodologies" does not adequately replace "objectives, practices, approved procedures, and
work specifications". Recommend to keep the original wording.
Disagree
Although we agree that it is important to identify both aspects of the program for
"prepare/documentation" and "implementation", we do not agree that this needs to be documented in
separate requirements. It makes the standard longer than necessary and creates redundancy. The
document would be easier to follow if the two elements were kept together in the same requirement.
In addition, it is not defined what is "VRFs". We understand that this was detailed in a previous draft
document as "Violation Risk Factor". This needs to be defined and clarified in order to provide
comment back.
Agree
The Transmission owner needs the ability to define what an inspection is in the context of their utility
operation. Inspections may not constitute a dedicated, comprehensive vegetation management
inspection, but could often be part of a routine line patrol, where linemen or engineers look for
vegetation concerns in addition to undertaking maintenance work. Clarification of that would be
helpful, suggest that could be documented in the Technical Reference document.
Disagree
The document would be easier to follow if the two elements were kept together in the same
requirement (similar to comments stated in Comment #4 above). It makes the standard longer than
necessary and creates redundancy. Also, under the new wording in R1, the TVMP no longer has a
requirement to include objectives. However, there is a phrase in R1.3 to "support the
objectives…and methodologies…outlined in the...program". To be consistent with R1.3, it is
recommended that R1.1 be reworded to specify the methodologies and objectives that the
Transmission Owner uses to control vegetation.
Disagree
Agree with R1.4, however with the suggested change: Remove the language "…and may include
actions such as a temporary reduction in line Rating, switching lines out of service, or other actions.".
Any stardard should not contain advisory-type language, it should be declarative in tone. The
suggested actions are not the responsibility of the vegetation management program.
Agree
Disagree
Recommend adding it back to the document, however, only if it is changed to become a measurement
(M) rather than a requirement (R). Leaving it in as a measurement provides justification and leverage
for operational clearances when dealing with landowners. Without Clearance 1 landowners may only
allow vegetation clearance just at the Critical Clearance Zone at all times, which is not a feasible,
cost-effective, or responsible way for utilities to manage vegetation clearance.
Agree
Agree
Although we agree that using the Gallet equation is more definitive than using IEEE 516, we still
question from an engineering prespective as to how and why this method was chosen. It is stated in
the Technical Reference paper that the Gallet Equation is a well known method of computing the
required strike distance for proper insulation coordination. It is our understanding it's purpose is for
designing towers, to define the "tower window" or opening inside of a tower under normal conditions.
Because this is not a method designed specifically for vegetation management, was there any
physical testing involved in choosing this approach, such as testing in both wet and dry conditions?
We would recommend additional information to clarify this method to use for vegetation
management. See additional comments in Comment #18 below. In addition, we feel this clause
makes R4 redundant, as per our comments under Comment #15 below.
Agree
As commented in Comment #11 above, although we agree that using the Gallet equation is more
definitive than using IEEE 516, we still question from an engineering prespective as to how and why
this method was chosen. It is stated in the Technical Reference paper that the Gallet Equation is a
well known method of computing the required strike distance for proper insulation coordination. It is
our understanding it's purpose is for designing towers, to define the "tower window" or opening inside
of a tower under normal conditions. Because this is not a method design specifically for vegetation
management, was there any physical testing involved in choosing this approach, such as testing in
both wet and dry conditions? We would recommend additional information to clarify this method to
use for vegetation management. See additional comments in Comment #18 below.
Agree
As commented in Comments #11 & #12 above, although we agree that using the Gallet equation is
more definitive than using IEEE 516, we still question from an engineering prespective as to how and
why this method was chosen. It is stated in the Technical Reference paper that the Gallet Equation is
a well known method of computing the required strike distance for proper insulation coordination. It is
our understanding it's purpose is for designing towers, to define the "tower window" or opening inside
of a tower under normal conditions. Because this is not a method design specifically for vegetation
management, was there any physical testing involved in choosing this approach, such as testing in
both wet and dry conditions? We would recommend additional information to clarify this method to
use for vegetation management. See additional comments in Comment #18 below.
Disagree
The document would be easier to follow if the two elements would be kept together in the same
requirement (similar to comments stated in Comments #4 & #6 above). It makes the standard longer
than necessary and creates redundancy.
Disagree
Disagree with R4 as it is written. The new requirement in R4 stipulates that the Transmission Owner
is in violation if an encroachment of the Critical Clearance Zone occurs at any time. However, the
Critical Clearance Zone changes with each foot of the transmission line from the insulator to the midspan, depending on loading, actual operating temperature, wind loading, ice loading, maximum
design rating, maximum operating load, and so on. See additional comments in Comment #18 below.
Furthermore, Measure M4 requires that the Transmission Owner has evidence demonstrating there
were no vegetation encroachments into the Critical Clearance Zone. To provide evidence
demonstrating there were no vegetation encroachments into the Critical Clearance Zone would be an
extremely onerous task and an expensive requirement for the utilities. We strongly support changing
this to the 1st alternative written in Comment #15 "One alternative to R4 required immediate
removal of the vegetation or immediate implementation of the immenent threat procedure upon
discovery of a possible encroachment of the Critical Clearance Zone, thereby proactively preventing
an outage. A violation would have occurred only if the immenent threat process was not successfully
implemented." This alternative is essentially the same as R2, therefore, we recommend removing R4
from the standard entirely.
Disagree
Recommend that the requirement under R7 be changed from "shall prevent sustained outages" to
"shall minimize sustained outages due to vegetation falling into a conductor". We understand that the
word "minimize" was present in earlier drafts of the document. We are concerned about the
requirement to prevent sustained outages from vegetation falling into the conductor from within the
active transmission ROW. It is operationally almost impossible to know precisely where the edge of
the ROW is in all situations under all conditions. This could lead to an incident where a utility is
charged unreasonably - for example, for an outage from a tree that was one foot within the active
ROW line. We should not be held liable when reasonable due diligence is practiced. Furthermore, it is
not economically feasible for utilities to survey every ROW to determine precise clearance zones.
Disagree
The document would be easier to follow if the two elements would be kept together in the same
requirement (similar to comments in #4, #6, & #14 above). It makes the standard longer than
necessary and creates redundancy.
We question the method used in determining the clearance distances for Vegetation near
Transmission Lines. First is the use of the Gallet Equation. Although the Gallet Equation is more
definitive than using IEEE 516 as identified in the current standard, we have questions from an
engineering prespective as to how and why this method was chosen for vegetation management. It is
stated in the Technical Reference paper that the Gallet Equation is a well known method of computing
the required strike distance for proper insulation coordination. It is our understanding it's purpose is
for designing towers, to define the "tower window" or opening inside of a tower under normal
conditions. Because this is not a method designed specifically for vegetation management, what is the
basis for applying this to vegetation management? Was there, or could there be testing done? We
would find it definitive to substantiate the calculated equation assertions with test data from actual
energized flashover distances to vegetation. The testing ought to include dry and misting conditions
at 200+ kilovolt levels on a sampling of fresh cut common vegetation types. Reputable EHV testing
facilities where such tests can be performed exist within the United States and Canada. Is there
additional information to clarify why this method was used to help establish clearance distances for
vegetation near transmission lines? Second, it is expected that each utility needs to define their
"Critical Clearance Zone". It is outlined in the Technical Reference document how complicated it is to
define this clearance area. As the conductor moves throughout its "flight path", the minimum
clearance shell surrounding the conductor moves along with it. The shape and size of the Critical
Clearance Zone around the conductors is irregular and will change depending on where a conductor
segment is located within the span. At mid-span, where the potential for conductor movement is the
greatest due to sag and wind deflection, the corresponding Critical Clearance Zone is also the largest
and most irregular. With the size, shape, and area of the Critical Clearance Zone dramatically
changing as one progresses along a span, identifying the precise location and boundary of the Critical
Clearance Zone around the conductor in the field becomes very problematic. There are many
variables that are involved at any point along a line and at any given time (loading, operating
temperature, wind, maximum design rating, maximum operating loading and so on). Therefore, even
if the exact size and shape of the Critical Clearance Zone is known, it becomes nearly impossible to
field correlate and accurately "superimpose" the Critical Clearance Zone" around the conductor.
Therefore, it seems unreasonable to expect each utility to develop and implement a defensible and
auditable clearance zone. We strongly support the development of the Technical Reference document.
This would have been helpful if it was available for the first version, as it will help both utilities and
auditors. We recommend that this be included in the revised version and subsequent future revisions.
Please note that as FAC-003-2 goes through additionals revisions prior to finalization, the Technical
Reference document needs to be revised to reflect the final revisions prior to implementation.
Individual
Rick White
Northeast Utilities
Agree
Agree with the term "bulk electric system." Disagree with the wording of the Purpose Statement; The
Purpose statement reads "To improve the reliability of the bulk electric system by preventing
vegetation related outages that could lead to Cascading." One vegetation-caused outage does not in
and of itself cause Cascading. Cascading will only result due to a combination of events - either
multiple vegetation outages during the same time or an outage coupled with equipment malfunction
or operational errors. The document seems to be internally inconsistent in this regard. The Techincal
Reference for FAC-003-2 notes that outages due to trees falling from outside the right-of-way or
other outage causes on a critical facility would not constitute a possible cascading effect. If one
occurance of these types of outages would not constitute a cascading potential then one must wonder
why an outage from a tree contact within the right-of-way is considered a possible cascading event?
Suggest rewording the statement to exclude the comment about Cascading and use "by preventing
vegetation related outages on critical transmission facilities."
Agree
One question: Will the Reliability Coordinators use consistent criteria for listing sub 200-kV facilities to
be included under FAC-003-2? The purpose of FAC-003 is to ensure inter-regional reliability and to
focus on the reliable operation of these lines. By leaving the decision up to the individual Reliability
Coordinators - there is the potential for local differences in determining which sub-200-kV facilities
may be critical. This could result in some transmission owners having to include certain facilities
under the requirements of FAC-003-2 where in other regions of the country - similar facilities may not
be included by the Reliability Coordinator. Although there have been criteria established to guide the
Reliability Coordinators in the detemination of sub-200-KV facilities for inclusion under FAC-003-2 - is
this sufficient to ensure uniformity throughout the US? Perhaps some involvement at the Regional
Entity level at least, is warranted.
Agree
With respect to "active transmisison line ROW" the examples provided in the Technical Reference
document for FAC-003-2 show that any areas of the easement or fee-owned right-of-way not cleared
in accordance with company approved design standards will not be considered "active transmission
line ROW". Any vegetation contacts resulting from trees that fail in these non-cleared sections
("corridor edge zones") would not constitute a violation of FAC-003-2. The definition of the "active
transmission line right-of-way" states that this does not include areas of the easement or fee-owned
property that is unused or inactive and intended for other facilities. Does this imply that areas not
cleared and not intended for other facilities are part of the active right-of-way? If a company had
constructed new lines and allowed for a buffer strip of the easement that was not cleared, but is also
not intended for new facilities, and trees are allowed to remain in this strip - that an outage from
contact with a tree falling into the lines from this buffer would constitute a violation of R7 as a tree
falling from within the active right-of-way? Does this imply that trees in these buffer strips must be
removed? This will constitute a very costly and problematic position that will result in extreme
adverse public opposition to the required clearing. It is suggested that the clearing limits of any rightway comply with some established standards or codes. A utility should not be allowed to eliminate a
large number of vegetation violations by simply decreasing the size or width of the active right-ofway. However, this may also need to be flexible when new lines are constructed when easement
widths are limited due to local or state requirements.
Agree
Agree
Agree
Disagree
Agree with the need to have and implement when necessary an imminent threat procedure. Disagree
with the need to implement the imminent threat procedure merely because a CCZ is being
approached, as required by R2. Is there a desired distance from the CCZ where this procedure must
be implemented, since all vegetation within a right-of-way will "approach" the CCZ as it grows? How
will time of year and operating conditions be factored in, which may change the requirements to
perform control during periods of low temperature or low load? It would not be necessary to perform
all the requirements of an imminent threat procedure when there is adequate clearance to schedule
the work without jeopardizing the reliability of the system. For example, in mid winter a line is 8 feet
from a tree - there is little chance of the line reacing maximum sag at that time of year and the
present condition does not constitute an imminent threat at that time. Also, disagree with the
requirement for the imminent threat procedure to include actions that could be taken by the TOP
(reduction in line rating, switching). The requirement should be limited to notifications to the TOP,
since decisions on what specific system operating actions to take are beyond the responsibility of the
TO. The decision on what actions to take needs to be performed either by the TOP, or by the TOP in
conjunction with the TO.
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Disagree
First - the determination of the CCZ is highly problematic in the field. Second - it is impossible for any
utility to certify that no encroachments have occurred at any time unless a utility has completely
removed all potentially interferring vegetation on all areas of their transmission system. If the
standard is to clearcut and maintain a tree free right of way, the standard should say so. To
determine if vegetation may have violated the CCZ the inspector must know at the time of the
inspection the ambient temperature, the wind speed, the loading of the line and the actual distances
between the vegetation and conductors. Then, the information must be compared to possible extreme
operating levels of the line under all conditions to know if the vegetation may violate the CCZ. As
stated - it is improbable that this could accurately be performed in the field as the data changes
within each segment of a span's length. The first alternative provides the most effective means of
addressing encroachment of the CCZ - having an encroachment is not a violation - knowing there is
an encroachment and not correcting the problem would be a violation. Implementing the imminent
threat procedure and correcting the problem is a more effective approach. Having a zero tolerance for
encroachments of the CCZ under all situations and operating conditions would sub-optimize the use of
resources. No actual event may have occurred on the system, yet the utilities will be in violation just
for a possible or potential problem that even under extreme operating conditions may not actually
occur. It would be best if the violations were limited to "known encroachments" (not "possible
encroachments") such as would occur if a line were to trip due to vegetation contact, or if there is
evidence of any burns. If no action was taken on known encroachments to correct the problem (such
as implementation of the imminent threat procedure) then a violation will have occurred. It is
doubtful that any utility will be able to certify that at no time has vegetation encroached into the CCZ.
Utilities will have to spend an untold amount of resources to verify that there have not been any
encroachments during a compliance period - instead of using these resources more effectively in
taking proactive measures to manage and control encroaching vegetation. As written, any
encroachment into the CCZ is considered a violation of FAC-003-2 (R4). There are exceptions
provided for encroachments due to natural disasters and human or animal activity. There is no
exception for encroachments due to the failure of a tree(s) outside of the active transmission line
ROW. Based on R4, a trip and reclose of a transmission line (no outage) is a violation even if the tree
is outside of the active right-of-way; whereas per R6 and R7, a line outage would not be a violation if
the tree was outside of the active right-of-way. As written - this is not clear - there should be
exceptions to allow for trees falling into the CCZ (and into the active transmission line right-of-way)
from outside the limits of the active transmission line right-of-way. Also - how are violations of the
CCZ requirement to be reported - there is no provision for the reporting process and requirements
(specifics on the type of violation). Will this be addressed in the Compliance Section yet to be added?
Agree
Agree that contacts resulting in sustained outages due to vegetation from within the active
transmission line right-of-way should constitute a violation of the Standard. However, this Standard is
written for a zero tolerance of any vegetation caused outages or encroachment into the CCZ. One
vegetation-caused outage or one CCZ encroachment may not result in a potential Cascading effect.
Agree with the use of different violation risk factors (VRF's) and violation severity levels (VSL's) for
each of the three outage classes. Also - how are outage violations to be reported - there is no
provision in the revision for the reporting process and requirements (specifics on the type of
violation). Will this be addressed in the Compliance Section yet to be added? Suggest in both R6 and
R7, move the phrase "within an Active Transmission Line Right of Way" to immediately follow
"vegetation".
Agree
In section 4.2.2. the time period for bringing sub 200-kV lines into compliance with the standard
states a 12 month period following the designation of the lower voltage lines by the Reliability
Coordinator. This can present problems if the RC designates the lines during the course of a plan
year, because budgets may not have been established or funded for the additional work. It is
suggested that the time period be revised to state, "by the end of the following calendar or budget
year after the designation of lower voltage lines", allowing for a full calendar/budget year that can be
planned and budgeted to bring lines into compliance. There is concern over the use of the CCZ and
making this the "bright line" where encroachment at any time under any conditions is a violation of
the standard. The CCZ is a very detailed and calculated zone. It is improbable that an accurate
determination of the CCZ could be made in the field. Mere encroachment should not constitute a
violation. If the encorachment can be determined and corrected once found - this should be an
acceptable practice. It is reasonable for utilities to spend the time, money and manpower to actively
manage rights-of-way, and dealing with encroachment issues which can be identified. Many potential
encroachments will not be identifiable unless one can accurately identify the CCZ in all cases in all
areas at all times. Also, there is some concern over how the requirements are set up for violations of
the CCZ and for sustained outages. A sustained outage due to vegetation within the active
transmission right-of-way is a violation under R.5, R.6 and R.7. It is also possible that the outage is a
violation of the CCZ under R.4. The standard implies that a utility could be assessed multiple
violations of the standard for one outage with multiple penalties. Is this the desired intent? Finally,
version 1 had clear requirements on what was to be reported, when the reports were required, and
who was to submit reports. Is it intended that the standard rely soley on self-reports? Version 2
makes no mention of what is to be reported when a violation occurs, or of any other reports. Is
reporting going to be left up to the Regional Entity to establish?
Individual
Roger Champagne
Hydro-Québec TransÉnergie (HQT)
Agree
Disagree
HQT believe that the Planning Coordinator (PC) should be the entity responsible to determine the
elements part of the BPS submitted to this Standard, and in fact for all other Standards. Those
elements should be determined by an impact based methodology, as used in NPCC, with no voltage
limitation and no fixed voltage treshold level as imposed in Applicability 4.2.
Disagree
While we agree with the suggested changes for the terms proposed , we believe that the TVMP should
be focused on removal of incompatible vegetation from the Active Right of Way. R1.1 could
read:Specify the methodologies that the Transmission Owner uses to control vegetation and
demonstrate that the removal of non-compatible vegetation is a focus within the plan. Incompatible
vegetation should be defined as any vegetation which has the potential to grow tall enough to
jeopardize the integrity of an applicable transmission line by growing into the CCZ or falling into the
CCZ. This would provide clear guidance to all stakeholders, support long term vegetation
management philosophies, and complement methods such as IVM where incompatible vegetation is
completely removed, and compatible vegetation is encouraged to proliferate, thereby helping to
control incompatible vegetation in an environmentally positive manner.
Agree
Disagree
The frequency and need for inspection is based on a number of factors that include: type of
vegetation on a right of way, rainfall during any given year, climate (very slow growth in nordic area),
when the last removal of vegetation was done, etc. HQT believes R1.2 is overly prescriptive when a
«at least once a year» becomes mandatory; these terms should be removed from the Standard.
Disagree
R1.2 and R1.3 specify calendar year. The individual entities should define the 12 month period for
their programs.
Disagree
While we strongly agree that an imminent threat procedure should be required in the TVMP, we
disagree with some specific wording in R1.4. R1.4 requires immediate communication of an imminent
threat to the Transmission Operator, which we would normally agree with. R2 however requires that
the imminent threat procedure be implemented when the Critical Clearance Zone (CCZ) is approached
by vegetation. "Approached" is not defined as a specific distance, so this part of the requirement is
left up to the individual's interpretation. In cases where the CCZ is approached by vegetation no
threat to the system is possible if the vegetation is removed before it actually grows into the CCZ. In
many cases the vegetation can be removed without taking clearance outages because the CCZ is
large, and the conductor and vegetation are still relatively far apart. In such cases there is no need to
notify the Transmission Operator, although there is a need to remove the vegetation immediately. We
recognize that the opposite is also true, and that in some cases it will be necessary to notify the
Transmission Operator because a clearance outage or line de-rating may be required to remove the
vegetation. We therefore suggest a simple change to the wording of the second sentence of R1.4.
Change "…. specify actions which shall include immediate communication of the threat to the
Transmission Operator, and may include actions such as a temporary reduction in line Rating,
switching lines out of service, or other actions" to "... specify actions which may include immediate
communication of the threat to the Transmission Operator, a temporary reduction in line Rating,
switching lines out of service, or other actions". This change will address the issue which is described
above and will allow each Transmission Operator to develop an imminent threat procedure that best
fits their system. It should also be noted that many Transmission Operators have imminent threat
procedures in place to address all imminent threats to their transmission system, not just threats due
to vegetation. It makes sense for Transmission Owners to have only one imminent threat process,
therefore the flexibility that can be achieved in the context of this standard would be helpful.
Agree
Agree
We agree but believe that the TVMP should target removal of all incompatible vegetation on the
Active Right of Way as described in the response to question 3.
Agree
Agree
Agree
Agree
Agree
Disagree
The purpose of the standard is "To improve the reliability of the Bulk Electric System by preventing
vegetation related outages that could lead to Cascading". We believe that R4 is not the most effective
way to achieve this purpose because it does not provide incentive for Transmission Owners to take
advantage of modern technology, such as aerial laser survey (ALS) using Light Detection and Ranging
technology (LIDAR), that is capable of accurately identifying vegetation which is approaching the CCZ
or has encroached into it. In fact R4 provides an incentive not to utilize this technology because
Transmission Owners who identify encroachments would be in violation of R4 for each identified
encroachment. On the other hand, Transmission Owners who choose to be less proactive often would
not identify such encroachments because the CCZ and encroachments of it are generally not easy to
determine without taking precise measurements. Unless the line is heavily loaded or the vegetation is
significantly overgrown, encroachments of the CCZ would not be readily noticed. In most cases these
Transmission Owners would simply remove or cut back incompatible vegetation without taking
measurements. The threat to the line would have been eliminated with no encroachment having been
identified. R4 presents a dilemma for Transmission Owners that are considering making the significant
investment in ALS technology. While the technology would allow them to identify any potential growin or fall-in conditions, it would also expose them to the risk of identifying violations of R4, that would
otherwise not have been identified. Violation Risk Factors (VRFs), Violation Severity Levels (VSLs),
and Time Horizons are not included in this Draft, but after making a significant investment in ALS,
Transmission Owners could be faced with significant additional cost in terms of NERC penalties. In
addition, even if the penalties were relatively low they would be exposing themselves to violations
that less proactive Transmission Owners would not be exposed to. In our view R4 as written would, in
some cases, have the opposite effect of what is intended because the business case for using ALS is
more difficult to make. This will result in less use of ALS and other emerging technology that is likely
to be developed. This would result in fewer problems being identified, a small percentage of which will
not be discovered until they result in a line trip. Still we believe that the concept of the CCZ is a good
one and recommend that R4 be changed so that Transmission Owners are provided with an incentive
to invest in the best technology available in order to ensure the highest level of reliability. The
opportunity exists to develop the standard in a manner that encourages the industry to take
advantage of new technology and manage vegetation in a very proactive way. We recommend that
R4 be changed as follows: Modify R4 to require Transmission Owners to immediately implement the
imminent threat process defined in R1.4 when they identify instances where the CCZ is approached or
encroached upon. Failure to do so would be a violation of R4. Eliminate encroachment of the CCZ as a
violation of R4. This would eliminate R2 and incorporate implementation of the imminent threat
process into R4. Require Transmission Owners to report to the Regional Entity on a quartely basis any
instances where the imminent threat process was implemented due to an encroachment of the CCZ.
This would add a reporting requirement for Transmission Operators. Require Transmission Owners to
report to the Regional Entity on a quarterly basis any instances where either a momentary or
sustained outage was caused by grow-ins, Active Transmission Line Right of Way blow-ins, or Active
Transmission Line Right-of-Way fall-ins. This would add three additional reporting requirements for
Transmission Operators. Require Regional Entities to perform additional audits of Transmission
Owners that exceed metrics for violations of the CCZ . The metrics would be established in this
Standard based upon 100 circuit miles of applicable lines. This would add an additional requirement
for Regional Entites. This concept would result in a more rigorous standard than FAC-003-01 because
of the additional reporting and auditing requirements. It would drive proactive behavior throughout
the industry and provide a significant incentive for Transmisison Owners to invest in new technology
such as ALS that is capable of accurately identifying vegetation that has approached or encroached
upon the CCZ. We believe that this change would result in the identification of more incipient
vegetation-related problems and fewer vegetation-related outages as soon as it was implemented and
would best support the purpose of the Standard.
Disagree
HQT request clarification if violations of R5, R6, and R7 result in outages that must be reported. A
further exception would be a sustained outage where the conductor has moved outside the critical
clearance zone. This could occur under conditions of heavy icing, operating outside the line rating or
excessive wind.
Agree
HQT recommends that the Standard Drafting Team review the compliance and reporting requirements
for consistency and adequacy. Aplicability 4.2.3 contradict first part of Applicability 4.2.1 and that of
former Applicability 4.3
Individual
Kevin Koloini
Buckeye Power, Inc.
Agree
Agree
Agreed on this question.
Agree
OK with R1. However, the active transmission line right of way seems to be a reduction in ROW width
which would likely decrease reliability during the one moment when we need it most.
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
I agree with R2. I like the language changes, but decreasing the clearances will not improve
reliability.
Agree
I understand the reasoning for the change, but I do not see how decreasing clearances will increase
reliability.
Agree
Agree
Disagree
Proving vegetation is not in a clearance zone will be difficult without having third-party verification.
Agree
Agree
Group
MRO NERC Standards Review Subcommittee
Joseph Knight
GRE
Disagree
The standard specifically calls out that 200kV and higher are applicable to FAC-003. Changing to BES
would imply all lines 100kV and above would be applicable.
Disagree
The MRO disagrees that the RC is appropriately positioned to identify and designate any sub-200kV
lines that should be subject to this standard. The MRO believes that the lines below 200kV should
include only those that are currently classified as Interconnection Reliability Operating Limit (IROL)
lines which are already defined and listed for registered entities. As such R9 and R10 should be
eliminated from these standards along with the RC in the applicability section.
Agree
The MRO agrees but requests further clarification on the definition of the term "Active" in Active
Transmission Line R.O.W. For example: A utility has a 150 foot easement for a 230kV line and
currently manages 80 feet. First; is it the intent of the standard that the utility manage the entire 150
foot easement? Second; is the entire easement considered the Active Transmission Line R.O.W?
Agree
The MRO believes that clarity was improved by separating documentation and implementation. The
MRO suggests that moving the requirement for implementationt so that it immediately follows the
requirement for documentation will further enhance clarity.
Agree
The MRO suggests rewording the requirement to remove ".. and environmental" . The MRO believes
that local factors includes environmental.
Agree
The MRO suggests removing the words "during the year" from sentence 1 and removing the words
"within the year" in sentence 3. The MRO believes that having it only within the plan year is too
restrictive.
Agree
The MRO agrees and believes that it is very important for the applicable entities to posses a Imminent
Threat Procedure. The MRO also believes that the term "Imminent Threat" is subjective an should be
defined.
Agree
The MRO believes that the term "interim" should be removed from R1.5. The term Interim is
subjective.
Agree
The MRO agrees and fully supports the removal of Clearance 1. The MRO believes that the Gallet
equation is a more effective way of determining the required clearances.
Agree
Agree
The MRO agrees and believes that the Gallet equation yeilds a less subjective measurement. The MRO
believes R2 should be modified to be more definitive. The imminent threat procedure should be
implemented when vegetation “enters†the critical clear zone. Fines and violations for
approaching the zone is not measurable or enforceable. The MRO believes that "approached" is
subjective and not enforceable and should be removed from the requirement.
Agree
Agree
Agree
Disagree
The MRO believes R4 should be eliminated as vegetation contacts are covered in R5 and R6. A
violation should only occur with a vegetation contact. Assessing a violation and fine for a potential
reduction in system reliability is not correct. Actual contacts that trip a transmission element have
some measurable impact on system reliability even if it is slight.
Agree
Agree
The MRO both Agrees and Disagrees. The MRO agrees with the separation between having an annual
plan and implementing it. However, the MRO suggests removing all the words after vegetation
manangement.
Individual
Joe Knight
Great River Energy
Disagree
The standard specifically calls out that 200kV and higher are applicable to FAC-003. Changing to BES
would imply all lines 100kV and above would be applicable
Disagree
GRE disagrees that the RC is appropriately positioned to identify and designate any sub-200kV lines
that should be subject to this standard. GRE believes that the lines below 200kV should include only
those that are currently classified as Interconnection Reliability Operating Limit (IROL) lines which are
already defined and listed for registered entities. As such R9 and R10 should be eleiminated from this
standards along with the RC in the applicability section.
Agree
GRE agrees but requests further clarification on the definition of the term "Active" in Active
Transmission Line R.O.W. For example: A utility has a 150 foot easement for a 230kV line and
currently manages 80 feet. First; is it the intent of the standard that the utility manage the entire 150
foot easement? Second; is the entire easement considered the Active Transmission Line R.O.W?
Agree
GRE believes that clarity was improved by separating documentation and implementation. GRE
suggests that moving the requirement for implementationt so that it immediately follows the
requirement for documentation will further enhance clarity
Agree
GRE suggests rewording the requirement to remove ".. and environmental" . GRE believes that local
factors takes into account environmental.
Agree
GRE suggests removing the words "during the year" from sentence 1 and removing the words "within
the year" in sentence 3. GRE believes that having it only within the plan year is too restrictive.
Agree
GRE agrees and believes that it is very important for the applicable entities to posses an Imminent
Threat Procedure. GRE recomends that the Imminent Threat procedure be renamed "Vegetation
Imminent Threat Procedure" so as to clearly identify the procedure in the event that a company has
imminent threat procedures for more than one situation.
Agree
GRE believes that the term "interim" should be removed from R1.5. The term Interim is subjective.
Agree
GRE agrees and fully supports the removal of Clearance 1. GRE believes that the Gallet equation is a
more effective way of determining the required clearances.
Agree
Agree
GRE agrees and believes that the Gallet equation yeilds a less subjective measurement. GRE believes
R2 should be modified to be more definitive. The imminent threat procedure should be implemented
when vegetation “enters†the Critical Clearance Zone (CCZ). It is GRE's opinion that
approaching the CCZ is subjective and as such very difficult to enforce.
Agree
Agree
Agree
Disagree
GRE supports the elimination of R4, as vegetation contacts are covered in R5 and R6. A violation
should only occur with a vegetation contact. Assessing a violation and fine for a potential reduction in
system reliability is not correct. Actual contacts that trip a transmission element have some
measurable impact on system reliability even if it is slight. In the event that the SDT chooses not to
eliminate R4, GRE would also support the alternative language that is shown under the second bullet.
Agree
Disagree
GRE both Agrees and Disagrees. GRE agrees with the separation between having an annual plan and
implementing it. However, GRE suggests removing all the words after vegetation manangement.
Group
Midwest ISO Stakeholders Standards Collaborators
Jason L. Marshall
Midwest ISO
Disagree
By definition Bulk Electric System includes most facilities 100 to 200 kV. The previous version of this
standard appropriately restricted the applicability of the standard to these facilities by requiring the
Regional Reliability Organization to identify only those facilities that are critical in this voltage class.
This new version of the standards attempts to limit the 100-200 kV class applicability by having the
RC identify the critical facilities. We believe to have one requirement of the standard say that it
applies to all the BES and then another requirement to limit the application only confuses the
applicability and recommend leaving the term "electric transmission systems" in the definition.
Disagree
We do not believe that the RC is the appropriate entity to identify those facilities sub-200 kV facilities
that this standard should apply to. Vegetation management is not performed in the operating horizon.
Rather it is performed in the planning and operations planning horizons. The RC should not be
distracted from focusing on the operating horizon by this task. We believe what the standard is
essentially requiring is identifying critical facilities. There are other similar requirements such as PRC023-1 R3 that appear to require the determination of critical facilities even though the term critical
facilities is not defined. We believe this represents broader issue that requires NERC to define critical
facilities. Failure to do so could result in the inefficient identification of multiple lists of critical facilities
for specific requirements that may ultimately be challenged in due process.
Agree
Agree
This is a good change from a compliance perspective; the documentation requirements can now be
assigned lower VRFs than the implementation requirements.
Agree
Agree
Disagree
Transmission Owners should have a Vegetation Imminent Threat Procedure, and "Vegetation
Imminent Threat" should be a defined term, defined as: "Vegetation observed in the field encroaching
upon a conductor within a distance that is twice the Gallet clearance distances referenced in Table I of
the draft standard FAC-003-2." In this case, the threat would require an immediate response and
would include communication to the Transmission Operator. From there, the actions that the operator
decides to take will be dependent on the incident and system conditions. We do not need to be
prescriptive with this requirement but rather allow the Transmission Operator and appropriate field
personnel the flexibility to make the right decisions to safely, promptly and appropriately remove the
vegetation threat. From a Transmission Owner's perspective, many situations can constitute an
imminent threat but this approach will clearly define a "Vegetation Imminent Threat" as it relates to
the Purpose of this standard. See our related comment on #11 below.
Agree
Agree
Agree
Disagree
he CCZ is a good theoretical concept to aid industy in understanding the overall movement of
conductors, but it is an impractical concept for field application. Due to the variability in the size of
the CCZ as you move along a conductor, as well as changes from span to span or even line to line
due to design parameters, loading or weather-related issues, the CCZ concept should not be tied to
an imminent threat procedure. Vegetation approaching the CCZ does not constitute an imminent
threat. It may be months to years before this vegetation ever gets to a proximity distance from the
conductor to be within a "spark-over" distance as defined by the Gallet equations. Requirement R2
should support the purpose of this standard by requiring implementation of the Vegetation Imminent
Threat Procedure when the Transmission Owner has visual, field knowledge that vegetation is
encroaching upon a conductor within some specific distance that is a multiple of the Gallet distances
referenced in Table I of FAC-003-2 (to be conservative we suggest two to three times the Gallet
distances). Failure to implement the Vegetation Imminent Threat Procedure in such instances would
be a violation of R2. As R2 is currently stated, a Transmission Owner cannot comply with R2 unless
the imminent threat procedure is continuously being implemented, because vegetation that is growing
is always approaching the CCZ. "Approaching the CCZ" cannot be the trigger for implementation of
the Vegetation Imminent threat Procedure. Instead, the trigger should be an encroachment within
some observed field distance. Requirement R2 could be reworded as follows: “Each Transmission
Owner shall implement its Vegetation Imminent Threat Procedure when the Transmission Owner has
knowledge, obtained through normal operating practices or notification from others, that vegetation is
encroaching upon a conductor within a distance that is twice the Gallet clearance distances referenced
in Table I." Using a multiple of the Gallet distances provides a safety factor. Assessing a violation for
failure to appropriately implement the Vegetation Imminent Threat Procedure or for a sustained
vegetation-related outage incents the proper behavior.
Agree
Agree
Agree
Disagree
The second bulleted alternative above is the best approach, but it should be improved by changing
the imminent threat trigger from "encroachment of the CCZ" to "encroachment within some observed,
field distance that is a multiple of the Gallet distances referenced in Table I". We have recommended
changes to accomplish this in Requirement R2 (see our response to Question #11 above), and R4
should simply be deleted. While the CCZ is valuable to understanding the movement of conductors, it
cannot be readily applied in the field. This field application challenge is noted in the Technical
Reference Document (pages 29 & 30). The way R4 is currently stated, the Transmission Owner would
be in violation of R4 for any CCZ encroachment not due to natural disasters or human or animal
activity. This would include a tree falling from outside the right of way corridor that passes through
the theoretical CCZ. Furthermore, Transmission Owners would be required to self-certify compliance
with R4, and we don't think there's any way to do that. Clearly the approach of assessing violations
for CCZ encroachment is unworkable. Likewise, the third alternative listed above is untenable. The
tiered approach could have a mitigating effect on violations, but it would require the same inspection
effort and postponement of vegetation management that makes the first alternative unworkable. Both
the first and third alternatives would require very significant additional expenditures for surveys and
documentation in an impossible attempt to certify compliance - money that would be better spent
controlling vegetation.
Agree
Agree
We recommend striking the words "within the extent of its easement and/or legal rights". The
emphasis for this requirement is to execute the annual work plan. The white paper already speaks to
the point that it is a best practice for utilities to exercise their legal rights. By tagging the words on to
the requirement, we are adding unnecessary compliance validation to this requirement for both
industry and the regulators. By the way this is written, it could be interpreted different ways. If we
agree that the goal is to prevent outages, then we can simply end this requirement with "accomplish
the purpose of the standard". Each TO would be accountable to manage compliance with this standard
and public relations in their service area.
FAC-003-1 lacks clarity that is essential for understanding what is necessary for compliance. The
proposed FAC-003-2 needs to be simplified to aid with field implementation and compliance
interpretation. Currently, it does not provide the clarity and simplification needed by Transmission
Owners and regulatory bodies to enhance reliability.
Group
SERC Compliance Staff
John Wolfmeyer
SERC Reliability Corp
Disagree
The definition of the Bulk Electric System generally includes all lines operated at 100 kV and above
and may exclude radial lines to load only. The standard is applicable to lines operated at greater than
200 kV regardless of their function. SERC staff does not believe that it is the intent of the standard to
address lines operated at less than 200 kV unless they are deemed to be critical to the operation of
the BES nor do we believe it is the intent to exclude radials to load only from the applicability. Use of
the term Bulk Electric System will cause unnecessary confusion to the industry concerning
applicability of this standard. Therefore, we recommend the continued use of the undefined term
"electric transmission systems."
Agree
Agree
Agree
Agree
Agree
Disagree
SERC staff agrees with the concept of an imminent threat procedure, but disagrees with this
requirement in its current form. The use of the word "immediate" is ambiguous. There are many
conditions or threats that may require immediate removal, but would not require communication with
the Transmission Operator and may require communication with another entity. SERC staff suggests
that the proper communication paths be outlined by the Transmission Owner. Imminent threats
should be a defined term, however SERC staff has not developed an objective, unambiguous
definition.
Agree
Agree
Agree
Disagree
SERC staff agrees that the implementation of an imminent threat procedure may be a valid concept;
however visualization of the Critical Clearance Zone and determining an approaching encroachment
will be difficult from a practical matter. There also needs to be definition of what is meant by
"approaching" if this is used. While it may be a technically sound approach to designate the clearance
zone to be tied to the conductor movement envelope as found in the NESC, this results in a bananashaped zone that is difficult to substantiate in the field by entity and compliance personnel. It may be
better, and more reasonable to define a constant zone around a conductor that would be the same
throughout the span. The clearance zone should not include the limitation that the zone cannot
extend outside the active right of way.
Disagree
While the actual sparkover distance may be more correctly calculated using the Gallet equations,
SERC staff believes it is a less conservative approach to the goal of preventing vegetation related
outages. If the concept of the CCZ will remain in the standard, we suggest that the tables based on
the Gallet equations be removed from the standard and be kept in the technical white paper solely to
assist in developing a common understanding of the theory behind the establishment of a CCZ.
However, the CCZ will continue to be a very difficult, if not impossible, aspect of the standard to
implement from the perspective of practical application and compliance enforcement.
Agree
Agree
Disagree
The concept of the Critical Clearance Zone is useful as a mental model to visualize required vegetation
management work. While this is a good conceptual tool to drive consistent terminology and proper
vegetation management practices, it is impractical to measure on a span by span basis. The
complexity of determining an encroachment into the Critical Clearance Zone is overly burdensome
due to the need for survey accuracy measurements and engineering evaluations. While it may be a
technically sound approach to designate the clearance zone to be tied to the conductor movement
envelope as found in the NESC, this results in a banana-shaped zone that is difficult to substantiate in
the field by entity and compliance personnel. We suggest that the Critical Clearance Zone concept be
kept in the technical white paper and that all references to the Critical Clearance Zone be removed
from the body of the standard.
Agree
Agree
Vegetation management practices should be extended areas outside of the active rights-of-way
(ROW) to the extent necessary to prevent vegetation-related outages. This should include the
identification and removal of trees that could impact transmission line operation similar to the practice
of identifying danger trees off of the ROW. The requirement as written could serve to reward those
entities that, for whatever reason, have insufficient right-of-way widths. From a practical perspective,
it should not be necessary to perform clear cutting of non-active ROW, but Entities should be held
responsible for any outages that occur due to contact with vegetation within their legal rights to
control.
SERC staff continues to find the Applicability section of the standard to be confusing and contentious.
While we recognize it is the intent this section to make the standard applicable t all entities that own
transmission lines that operate at greater than 200 kV, this section should not be written to be
applicable to transmission lines. Only registered entities can be held accountable for compliance with
the standards. SERC staff believes the applicability should be rewritten to include Transmission
Owners, Distribution Providers, and Generation Owners that own transmission lines with the
characteristics defined in Section 4.2. This would eliminate the need to make register, for example, a
Distribution Provider that own a 230 kV line that serves load as a Transmission Owner and make
them subject to the requirements of FAC-001 and FAC-002. SERC Staff also suggest the applicability
could be handled as it is in PRC-005-1 where the applicability is qualified as 'distribution provider that
owns...' and 'generator owner that owns...' or in a similar manner that captures the appropriate
subgroup but does not include unintended entities. SERC Staff believes a flashover between
vegetation and overhead ungrounded supply conductors that occurs, whether or not the flashover
results in a Sustained Outage, is clear evidence of an unallowable encroachment of vegetation into
the space that should be avoided and thus should be identified as evidence of a violation of the
standard. SERC staff has also found that excluding outages resulting from "earthquakes, fires,
tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the
Transmission Owner…" results in inconsistencies in reporting because of the inconsistency of the
Transmission Owners' definitions of same. If such exceptions are to be allowed, a consistent method
of determining the acceptability of those exemptions should be pursued.
Consideration of Comments on 1st Draft FAC-003-2 Vegetation
Management SDT — Project 2007-07
The Vegetation Management Standard Drafting Team (VM SDT) thanks all commenters who
submitted comments on the 1st draft of FAC-003-2 — Transmission Vegetation Management
Program standard. This standard was posted for a 30-day public comment period from
October 27, 2008 through November 25, 2008. Stakeholders were asked to provide
feedback on the standard through a special Standard Comment Form. There were more
than 60 sets of comments, including comments from more than 100 different people from
over 60 companies representing each of the 10 Industry Segments as shown in the table on
the following pages.
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
Key differences between first posting and second posting of proposed FAC-003 -2 include:
Replaced the CCZ concept found in R4 with a practical field measurement to
address commenter’s concerns.
Eliminated the CCZ as the trigger of imminent threat in R2 to address
commenter’s concerns.
Added a sub part to the TVMP (1.6) in order to address commenter’s concerns
regarding the elimination of Clearance 1. This change requires that the TO
account for anticipated conductor movement.
Developed VRF’s and VSL’s consistent with the NERC Drafting Team Guidelines.
Created a second grow-in outage requirement to allow for different VRF levels
based on the actual criticality of the line.
There were 3 strong minority views not resolved:
Some commenters disagreed with the “zero tolerance” nature of the existing inforce standard.
Some commenters disagreed with a minimum Vegetation Inspection frequency of
one year.
Some commenters want to retain Clearance 1 that is in the existing in-force
standard.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Gerry Adamski, at 609-452-8060 or at [email protected]. In addition, there is a
NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
September 8, 2009
1
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management
Program — Project 2007-07
Index to Questions, Comments, and Responses
1.
In the Purpose Statement the term “electric transmission systems” was changed to
Bulk Electric System, and the Purpose statement was shortened by moving the
various explanatory objectives to other locations in the revised Standard. Do you
agree with the purpose statement? If not, please explain. ......................................13
2.
The Reliability Coordinator was chosen as the proper entity to identify sub-200kV
transmission lines to be subject to this standard (see applicability, R9, and R10). Do
you agree with this choice? If not, please explain. ................................................24
3.
In R1 the proposed standard replaces “prepare, and keep current” with “have”,
replaces the list of terms, “objectives, practices, approved procedures, and work
specifications,” with “designed to control vegetation”, defines the “active
transmission line ROW”, and specifies that the transmission vegetation management
program applies to that area. Do you agree with R1? If not, please explain.............36
4.
Documentation and implementation of the transmission vegetation management
program which were previously combined in Requirement R1 are now separated in
order to apply appropriate VRFs and time horizons. The implementation of some
elements has been moved into standalone requirements such as inspection cycles
(R3) and annual plan implementation (R9). Do you agree with these revisions and
separation? If not, please explain. .....................................................................51
5.
In R1.2 the Transmission Owner is required to have an inspection frequency of at
least once per calendar year. Do you agree with R1.2? If not, please explain. .........59
6.
In R1.3 the Standard requires that transmission vegetation management program
specify an Annual Plan and specifies parameters for the plan. Implementation of the
Annual Plan is separated and placed in R9. Do you agree with R1.3 and the
separation of the implementation from the specification of the Annual Plan? If not,
please explain. .................................................................................................70
7.
In R1.4 the Standard requires the Transmission Owner to have an Imminent Threat
Procedure and specifies elements to be in that procedure. Do you agree with R1.4?
If not, please explain. .......................................................................................79
8.
Requirement 1 section R1.5 replaces Version 1 sub-requirement R1.4. This section
is now referred to as interim corrective action process. This process addresses
situations where vegetation maintenance activities cannot be performed as planned.
The term corrective action plan is used in lieu of mitigation plan to avoid confusion
with other uses in NERC of “mitigation plan”. Do you agree with R1.5? If not, please
explain.......................................................................................................... 102
9.
Clearance 1 in Version 1 was a “fill-in-the-blank” requirement and was removed
from the standard. Do you agree? If not, please explain..................................... 110
10. Personnel Qualifications in R1.3 in Version 1 was a “fill-in-the-blank” requirement
and was removed from Version 2 of the standard. Do you agree? If not please
explain.......................................................................................................... 121
11. The IEEE 516 standard distances were replaced with the Gallet equation distances.
Clearance 2 was replaced by the Critical Clearance Zone. The Critical Clearance
Zone is defined as the zone of all possible positions of the conductor at the line’s
designed operating ratings including wind factors. (Please refer to pages 22-32 in
the Technical Reference Document on the Critical Clearance Zone for further
background for this question.) The imminent threat procedure, R2, requires action
to be taken to prevent an outage when the Critical Clearance Zone is approached.
Do you agree with R2? If not please explain. ..................................................... 129
September 8, 2009
2
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management
Program — Project 2007-07
12. The Standard Drafting Team revised the spark-over (also referred to as “flashover”)
distance thresholds utilizing technically-equivalent Gallet equations in lieu of IEEE
516 minimum air insulation distance (MAID) calculations that were used in FAC-0031. The rationale is that the minimum air insulation distances in IEEE 516 were
safety clearances developed under laboratory conditions and thus there exists
concern these distances may be too conservative to apply to lines operating in
actual field conditions. Do you agree with this? If not, please explain. .................. 151
13. The Standard Drafting Team applied a transient overvoltage factor (T) of 1.4 and 2.0
for ac voltage classes of 345kV and above and sub-345kV facilities, respectively.
Version 1, using the IEEE 516 method, assumes a maximum transient overvoltage
value. The Standard Drafting Team asserts that in this application of steady-state
flashovers and due to the design attributes of higher voltage systems, a lower T
factor is applicable. Do you agree with this? If not, please explain. ...................... 159
14. R3 has been added to clarify that conduction of inspections is a separate
requirement from specifying the frequency that inspections will occur. Do you agree
with R3? If not please explain.......................................................................... 165
15. Several alternatives to R4 were considered by the drafting team. The drafting team
explored these significantly different alternatives at length. They are outlined below
to provide background to industry during this comment period. (Please refer to
pages 22-32 in the Technical Reference Document on the Critical Clearance Zone for
further background for this question.) Do you agree that R4 is written in the most
effective way to achieve the purpose of the standard? If not, what do you propose
as an alternative to R4 that would ensure a level of reliability equal to or better than
FAC-003-1? ................................................................................................... 172
16. Requirements R5, R6, and R7 define that Sustained Outages due to vegetation
growing into, blowing together with, and falling into transmission lines are violations
(subject to certain exemptions). Therefore, all such outages must be reported as
violations of the standard. Do you agree with this change? If not, please explain. .. 205
17. R8 is a new requirement which separates the implementation of the annual plan
from the requirement to have an annual plan. Do you agree with R8? If not please
explain.......................................................................................................... 218
18. If you have further suggestions for improving this standard or the technical
reference document, please offer them.............................................................. 229
September 8, 2009
3
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
The Industry Segments are:
1 — Transmission Owners
2 — Transmission Owners, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 – Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
1.
John Neagle
Associated Electric Cooperative Inc.
2
3
4
5
6
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. Chris Bolick
SERC
1, 5, 6
2. John Bussman
SERC
1, 5, 6
3. Ralph Schulte
SERC
1, 5, 6
4. Ted Hilmes
SERC
1, 5, 6
5. John Settle
SERC
1, 5, 6
6. Kevin White
SERC
1, 5, 6
7. John Stickley
SERC
1, 5, 6
8. Gary Highfill
SERC
1, 5, 6
9. Jeff Neas
SERC
1, 5, 6
10. Craig Thomas
SERC
1, 5, 6
2.
Guy Zito
Additional Member
September 8, 2009
NPCC
Additional Organization
Region Segment Selection
4
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Commenter
Organization
Industry Segment
1
1. Ralph Rufrano
New York Powerm Authority
NPCC
5
2. Roger Champagne
Hydro-Quebec TransEnergie
NPCC
2
3. Rick White
Northeast Utilities
NPCC
1
4. Greg Campoli
New York Independent System Operator NPCC
2
5. Mike Garton
Dominion Resources Services, Inc.
NPCC
5
6. Chris De Graffenried
Consolidate Edison Co. of New York, Inc. NPCC
1
7. Don Nelson
Massachusetts Dept. of Public Utilities
NPCC
9
8. Kurtis Chong
Independent Electricity System Operator NPCC
2
9. Brian Gooder
Ontario Power Generation Incorporated
NPCC
5
10. David Kiguel
Hydro One Networks Inc.
NPCC
1
11. Kathleen Goodman
ISO - New England
NPCC
2
12. Brian Evans-Mongeon Utility Services, LLC
NPCC
6
13. Mike Gildea
Constellation Energy
NPCC
6
14. Lee Pedowicz
NPCC
NPCC
10
3.
Linda Perez
WECC Reliability Coordination
4.
Jerry Paulson
Western Area Power Administration, Upper Great
Plains Region
5.
Jack Gardner (Chairman)
Joe Spencer (SERC staff)
SERC Vegetation Management Subcommittee (VMS)
Additional Member
Additional Organization
3
4
5
6
7
8
9
10
Region Segment Selection
1. Jack Gardner
Progress Energy Carolinas
SERC
2. Randy Gann
Alabama Power Co.
SERC
3. John Neagle
Associated Electric Cooperative, Inc.
SERC
4. Robby Trimble
E.ON U.S. Services Inc. for LG&E & KU
Companies
SERC
5. Ralph Hale
Entergy
SERC
6. Marc Tunstall
Fayetteville Public Works Commission
SERC
7. Reggie Wallace
Fayetteville Public Works Commission
SERC
September 8, 2009
2
5
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Commenter
Organization
Industry Segment
1
8. Jerry Lindler
South Carolina Electric and Gas Company
SERC
9. Richard Dearman
Tennessee Valley Authority
SERC
10. Billy George
Duke Energy Carolinas
SERC
6.
John Pinney
Progress Energy Florida
2
3
4
5
6
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. David Crews
7.
FRCC
Michael Gammon
1, 3, 5
Kansas City Power & Light
Additional Member Additional Organization Region Segment Selection
1. Todd Fridley
SPP
1, 3, 5
2. Paul Beaulieu
SPP
1, 3, 5
3. Duane Anstaett
SPP
1, 3, 5
4. Gary O'Neil
SPP
1, 3, 5
8.
Ron Turley
Western Area Power Administration, Rocky Mountain
Region
9.
Jack Gardner
Progress Energy Carolinas
10.
Samuel Stonerock
Southern California Edison Company
11.
Jim Griffith
SERC OC Standards Review Group
Additional Member
Additional Organization
Region Segment Selection
1. Jim Case
Entergy
SERC
1, 3, 5
2. John Neagle
Assoc. Electric Coop., Inc.
SERC
1, 3, 5
3. Greg Rowland
Duke Energy-Carolinas
SERC
1, 3, 5
4. Bill Thompson
Dominion Virginia Power
SERC
1, 3, 5
5. John Rembold
Southern Illinois Power Coop.
SERC
1, 3, 5
6. Jason Marshall
Midwest ISO
SERC
2
September 8, 2009
6
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Commenter
Organization
Industry Segment
1
7. Randy Castello
Mississippi Power Co.
SERC
8. Jimmy Etheridge
Georgia Transmission Corp.
SERC
1
9. Danny Dees
Municipal electric Authority of Ga.
SERC
1, 3, 5
10. Glenn Stephens
South Carolina Public Service Auth. SERC
1, 3, 5
11. Glen Thweatt
Big Rivers Electric Coop.
SERC
1, 3, 5
12. Gerald Beckerle
Ameren
SERC
1, 3, 5
13. Sam Holeman
Duke Energy - Carolinas
RFC
1, 3, 5
14. Melinda Montgomery Entergy
SERC
1, 3, 5
15. Roman Carter
SERC
1, 3, 5
Southern Company
2
3
4
5
6
7
8
9
10
1, 3, 5
12.
Mike Neal
Western Utility Arborists
13.
John Tamsberg
Florida Power & Light
Additional Member Additional Organization Region Segment Selection
1. Eduardo Devarona
Florida Power & Light
FRCC
1
2. Silvia Parada-Fortum Florida Power & Light
FRCC
1
3. Brian J. Murphy
FRCC
1
14.
Florida Power & Light
Terry L. Blackwell
Santee Cooper
Additional Member Additional Organization Region Segment Selection
1. S. T. Abrams
Santee Cooper
SERC
1
2. Ben Fleming
Santee Cooper
SERC
1
3. Kenny Sott
Santee Cooper
SERC
1
4. Jim Peterson
Santee Cooper
SERC
1
5. Glenn Stephens
Santee Cooper
SERC
1
6. Kristi Boland
Santee Cooper
SERC
1
7. Rene' Free
Santee Cooper
SERC
1
15.
Roman Carter
September 8, 2009
Southern Company
7
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Commenter
Organization
Industry Segment
1
Additional Member
Additional Organization
1. Steve Burns
Gulf Power Co.
SERC
3
2. Nancy Huddleston
Georgia Power Co.
SERC
3
3. Ronald Reinike
Mississippi Power Co.
SERC
3
4. Randall Gann
Alabama Power Co.
SERC
3
5. Marc Butts
Southern Co. Transmission
SERC
1
6. Raymond Vice
Southern Co. Transmission
SERC
1
7. JT Wood
Southern Company Transmission SERC
1
8. Jim Busbin
Southern Co. Transmission
SERC
1
9. Chris Wilson
Southern Co. Transmission
SERC
1
16.
Charles Yeung
3
4
5
6
PJM
RFC
2
2. Jim Castle
NYISO
NPCC
2
3. Dan Rochester
IESO
NPCC
2
4. Matt Goldberg
IEONE
NPCC
2
5. Lourdes Estrada-Salinero CAISO
WECC
2
6. Anita Lee
AESO
WECC
2
7. Steve Myers
ERCOT
ERCOT
2
8. Bill Phillips
MISO
RFC
2
17.
Brent Ingebrigtson
E.ON U.S.
18.
Denise Koehn
Bonneville Power Administration
Additional Organization
9
10
Region Segment Selection
1.
John Jamrog
Vegetation/Access Road Mgmt
WECC
1
2.
Jerry Reding
Transmission Engineering
WECC
1
3. Don Swanson
Transmission Line Maintenance Technical Svcs WECC
1
4. Michael Staats
Transmission Engineering
1
September 8, 2009
8
Additional Organization Region Segment Selection
1. Patrick Brown
Additional Member
7
IRC Standards Review Committee
Additional Member
2
Region Segment Selection
WECC
8
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Commenter
Organization
Industry Segment
1
5. Steven Bottemiller
Real Property Support Svcs
WECC
1
6. Marian Wolcott
Real Property Svcs
WECC
1
7. Jennifer Bailey
Transmission Line Maintenance Technical Svcs WECC
1
8. Stephen Larson
Legal
WECC
1
9. Allen Chan
Legal
WECC
1
Transmission Field Services
WECC
1
2
3
4
5
6
7
8
9
10
10
Robin Furrer
19.
Jeffrey C. Mueller
Public Service Electric and Gas Company
20.
Sam Ciccone
FirstEnergy
Additional Member Additional Organization Region Segment Selection
1. Charles Olenik
FE
RFC
1
2. Shawn Standish
FE
RFC
1
3. Rebecca Spach
FE
RFC
1
4. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
21.
Joseph Knight
MRO NERC Standards Review Subcommittee
Additional Member Additional Organization Region Segment Selection
1. Neal Balu
WPS
MRO
2. Terry Bilke
MISO
MRO
2
3. Carol Gerou
MP
MRO
1, 3, 5, 6
4. Jim Haigh
WAPA
MRO
1, 6
5. Charles Lawrence
ATC
MRO
1
6. Ken Goldsmith
ALTW
MRO
4
7. Terry Harbour
MEC
MRO
1, 3, 5, 6
8. Pam Sordet
XCEL
MRO
1, 3, 5, 6
9. Dave Rudolph
BEPC
MRO
1, 3, 5, 6
10. Eric Ruskamp
LES
MRO
1, 3, 5, 6
September 8, 2009
3, 4, 5, 6
9
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Commenter
Organization
Industry Segment
1
11. Joe DePoorter
MGE
MRO
3, 4, 5, 6
12. Larry Brusseau
MRO
MRO
10
13. Michael Brytowski
MRO
MRO
10
22.
Jason L. Marshall
2
3
4
5
6
7
8
9
10
Midwest ISO Stakeholders Standards Collaborators
Additional Member Additional Organization Region Segment Selection
1. Jim Cyrulewski
JDRJC Associates
RFC
2. Greg Rowland
Duke Energy
SERC
1, 3, 5, 6
8
3. Kirit Shah
Ameren
SERC
1
23.
John Wolfmeyer
SERC Compliance Staff
24.
JAMES W. SMITH
ITC HOLDINGS
25.
Richard Dearman
Tennessee Valley Authority
26.
Chris Scanlon
Exelon
27.
Weston Davis
Central Maine Power Company
28.
Thad Ness
American Electric Power (AEP)
29.
Deborah Schaneman
30.
Platte River Power Authority
Alan Gale
City of Tallahassee
31.
Fred Young
Northern California Power Agency (NCPA)
32.
Jason Lietz
Northern Indiana Public Service Company
33.
Chip Turner
Tampa Electric Company
34.
Edward Bedder
Orange and Rockland Utilities Inc.
September 8, 2009
10
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
35.
Jason Shaver
American Transmission Company
36.
Alice Druffel
Xcel Energy
37.
Jeff Hackman
Ameren
38.
John Humphrey
Nebraska Public Power District
39.
Jonathan Appelbaum
Long Island power Authority
40.
Robert (Bob) B.
Suedkamp
USDA Forest Service, Southwestern Region, Regional
Office for AZ and NM
41.
Kris Manchur
Manitoba Hydro
42.
Jianmei Chai
Consumers Energy Company
43.
Dawn Travalini
National Grid
44.
Stephen Tankersley
Pacific Gas & Electric Co.
45.
Rich Salgo
NV Energy (fka Sierra Pacific / Nevada Power Co.)
46.
Patricia vanMidde
San Diego Gas & Electric
47.
David Kiguel
Hydro One Networks Inc.
48.
David Dworzak
Edison Electric Institute
49.
George Czerniewski
Consolidated Edison Company of New York (CECONY)
50.
Tom Mathews and Steve
Rueckert
WECC
September 8, 2009
7
8
9
10
11
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
51.
Sreenath Thota
Arizona Public Service Company
52.
Patrick Brown
PJM Interconnection
53.
William T. Rees
Baltimore Gas & Electric Company
54.
Greg Rowland
Duke Energy Corporation
55.
Michael Pakeltis
CenterPoint Energy
56.
Ed Davis
Entergy Services
57.
Anita Lee
Alberta Electric System Operator
58.
Richard Kafka
Pepco Holdings, Inc
59.
Virginia Cook and Kim
Wheeler
JEA
60.
Dan Rochester
Independent Electricity System Operator
61.
Karen Powell
Salt River Project
62.
Rick White
Northeast Utilities
63.
Roger Champagne
Hydro-Québec TransEnergie (HQT)
64.
Kevin Koloini
Buckeye Power, Inc.
65.
Joe Knight
Great River Energy
September 8, 2009
9
10
12
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
1. In the Purpose Statement the term “electric transmission systems” was changed to Bulk Electric System, and the
Purpose statement was shortened by moving the various explanatory objectives to other locations in the revised
Standard. Do you agree with the purpose statement? If not, please explain.
Summary Consideration: The SDT revised the purpose statement based on industry comments. The SDT returned to “electric
transmission system” based on the comments that indicated confusion with the use of “BES”. The SDT also inserted the word
“those” in front of the phrase “vegetation-related outages” to clarify that not all vegetation-related outages lead to cascading.
The revised purpose statement now reads:
Purpose: To improve the reliability of the electric transmission system by preventing those vegetation related outages that could lead to
Cascading.
Organization
Associated Electric
Cooperative Inc.
Agree?
Disagree
Question 1 Comment
The definition of Bulk Electric System includes most transmission lines operated at 100 kv and above. While
Section A.4.2.1 limits the applicability of FAC-003-2 to 200 kv and higher transmission lines, the use of the term
Bulk Electric System could cause unnecessary confusion. Associated Electric Cooperative Inc recommends the
continued use of the term "electric transmission systems."
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
SERC Vegetation
Management Subcommittee
(VMS)
Disagree
The definition of the Bulk Electric System generally does not include radial transmission lines directly serving load
and, in addition, includes all lines operated at 100 kV and above. Use of the term Bulk Electric System will cause
unnecessary confusion to the industry concerning applicability of this standard. Therefore, we recommend the
continued use of the undefined term "electric transmission systems."
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Progress Energy Florida
Disagree
The intent of the revision of the standard was to bring clarity to the standard. Referring to the BES in the purpose
creates confusion as to the applicability of the standard. Therefore, Progress Energy recommends the continued
use of the term "electric transmission systems."
Response: The SDT thanks you for your comment Based on the comments received, the SDT understands there may be confusion caused by “BES”
September 8, 2009
13
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 1 Comment
and has revised the purpose statement to delete BES and return to electric transmission system.
Kansas City Power & Light
Disagree
The definition of the bulk electric system does not match the scope of the systems covered by the vegetation
management standard. If the term bulk electric system is used , it should exclude the areas not covered by the
standard.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Western Area Power
Administration, Rocky
Mountain Region
Disagree
Use of the general term Bulk Electrical System creates unintentional confusion regarding the applicability of this
standard to lines operated at 200 kV or higher and designated lines operated below 200 kV.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Progress Energy Carolinas
Disagree
The intent of the revision of the standard was to bring clarity to the standard. Referring to the BES in the purpose
creates confusion as to the applicability of the standard. Therefore, Progress Energy recommends the continued
use of the term "electric transmission systems."
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
SERC OC Standards Review
Group
Disagree
The following comments are supplied by the SERC OC Standards Review Group (OCSRG): The definition of the
Bulk Electric System generally does not include radial transmission lines directly serving load. The current standard
covers all 200 kV and above transmission lines along with those lower voltage lines designated by the RRO while
the BES includes all lines 100 kV and above. Use of the term Bulk Electric System will cause unnecessary
confusion to the industry concerning applicability of this standard. Therefore, the SERC OCSRG recommends the
continued use of the undefined term "electric transmission systems."
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Florida Power & Light
September 8, 2009
Disagree
The Purpose Statement of any regulation or standard should be completely consistent with the body of regulation or
standard. Here the use of Bulk Electric System (which is defined as 100 kV and above) is inconsistent with the
language of the Standard that states this Standard applies to 200 kV and above. One of the primary purposes of re-
14
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 1 Comment
drafting a Reliability Standard is to clear up any previous confusion -- here the Purpose Statement instead of adding
to clarity, adds an unnecessary element of confusion. Thus, the Purpose Statement should be re-written to state
200 Kv and above.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”.
Rather than create a new class of BES (>200kv), the SDT revised the purpose statement to delete BES and return to electric transmission system.
Southern Company
Disagree
The initial FAC-003-1 drafting team had a particular reason for not using Bulk Electric System for fear of it being
widely recognized to characterize the entire networked transmission system. This reason was to limit possible
confusion with the applicability of the Standard. The Bulk Electric System definition includes all lines of the grid
operated at 100 kV and above. This term also does not necessarily include lines of any voltage class that are radial
and directly serving load. Use of this term in lieu of “electric transmission systems” has the potential to cause
additional confusion to the industry.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
E.ON U.S.
Disagree
The definition of the Bulk Electric System generally does not include radial transmission lines directly serving load
and, in addition, includes all lines operated at 100 kV and above. Use of the term Bulk Electric System will cause
unnecessary confusion to the industry concerning applicability of this standard. Therefore, we recommend the
continued use of the undefined term "electric transmission systems."
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
MRO NERC Standards
Review Subcommittee
Disagree
The standard specifically calls out that 200kV and higher are applicable to FAC-003. Changing to BES would imply
all lines 100kV and above would be applicable.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Midwest ISO Stakeholders
Standards Collaborators
September 8, 2009
Disagree
By definition Bulk Electric System includes most facilities 100 to 200 kV. The previous version of this standard
appropriately restricted the applicability of the standard to these facilities by requiring the Regional Reliability
Organization to identify only those facilities that are critical in this voltage class. This new version of the standards
attempts to limit the 100-200 kV class applicability by having the RC identify the critical facilities. We believe to
have one requirement of the standard say that it applies to all the BES and then another requirement to limit the
15
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 1 Comment
application only confuses the applicability and recommend leaving the term "electric transmission systems" in the
definition.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
SERC Compliance Staff
Disagree
The definition of the Bulk Electric System generally includes all lines operated at 100 kV and above and may
exclude radial lines to load only. The standard is applicable to lines operated at greater than 200 kV regardless of
their function. SERC staff does not believe that it is the intent of the standard to address lines operated at less than
200 kV unless they are deemed to be critical to the operation of the BES nor do we believe it is the intent to exclude
radials to load only from the applicability. Use of the term Bulk Electric System will cause unnecessary confusion to
the industry concerning applicability of this standard. Therefore, we recommend the continued use of the undefined
term "electric transmission systems."
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
ITC HOLDINGS
Disagree
ITC does not agree with the new purpose statement. The NERC Glossary of terms states that the BES ?.generally
operated at voltages of 100kV or higher and the Applicability in Section 4 clearly states the standard is intended to
apply to all line voltages of 200kV and above and those lines designated by the Reliability Coordinator (4.2.1) as
being subjected to this standard. Using the term Bulk Electric System (BES) clearly sends a confusing message and
should be eliminated. Thus the term of "electric transmission system" is appropriate for the standard
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Tennessee Valley Authority
Disagree
TVA feels the use of the term Bulk Electric System will cause unnecessary confusion to the industry concerning
applicability of this standard. TVA recommends the continued use of the undefined term "electric transmission
systems. TVA recommends changing the phrase "by preventing vegetation-related outages that could lead to
Cascading" to "by preventing those vegetation-related outages that could lead to Cascading", this removes the
improper inference that each vegetation-related outage leads to Cascading
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system. Additionally, at your suggestion and that of others,
the SDT has added the qualifying word “those” to define that the standard should address interconnection reliability and security.
September 8, 2009
16
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Central Maine Power
Company
Disagree
Question 1 Comment
Central Maine Power suggests that a definition be provided for Bulk Power.
Response: The SDT is uncertain of the need to define Bulk Power.
American Electric Power
(AEP)
Disagree
American Electric Power ("AEP") does not agree with this purpose statement. First, it is clear from the Applicability
(in Section 4) that the standard applies only to certain lines, not to the entire Bulk Electric System (BES). Reference
to the BES in the Purpose statement tends to muddy the water, potentially leading to an assumption that the
Standard indeed applies to the entire BES. AEP suggests that the term BES used herein be replaced with "electric
transmission system" or "transmission grid". Second, the phrase "by preventing vegetation-related outages that
could lead to Cascading" should be changed to "by preventing those vegetation-related outages that could lead to
Cascading", to remove any suggestion that all vegetation-related outages could lead to Cascading.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system. Additionally, at your suggestion and that of others,
the SDT has added the qualifying word “those” to define that the standard should address interconnection reliability and security.
Tampa Electric Company
Disagree
NERC glossary of terms defines the Bulk Electric System as "the electrical generation resources, transmission lines,
interconnections with neighboring systems, and associated equipment, generally operated at voltages of 100 kV or
higher." This, at a minimum, could lead to confusion over what impacts the reliability of the Grid by potentially
including facilities less than 200 kV.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Orange and Rockland Utilities
Inc.
Disagree
The use of the term "Bulk Electric System" (BES) could lead to confusion. In most regions BES includes lines with
operating voltages equal to or greater than 100kV. The Standard is intended to apply to all lines with operating
voltages equal to or greater than 200kV, and only those sub-200kV lines which are designated by the Reliability
Coordinator (paragraph 4.2.1). Use of the words "electric transmission systems" rather than BES would eliminate
this potential source of confusion.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
American Transmission
September 8, 2009
Disagree
ATC disagrees with changing the term "electric transmission systems" to "Bulk Electric System". This standard
applies to 200 kV and higher transmission lines not all BES facilities. Suggested Purpose statement: To maintain
17
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Company
Question 1 Comment
the reliability of the electric transmission system by requiring entities to have and implement a transmission
vegetation management plan.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system. We also appreciate your suggested purpose
statement but based on others’ comments to be more specific about the reliability need for this standard we modified the purpose statement as seen
in the Summary Consideration above.
Ameren
Disagree
By definition, the capitalized term, Bulk Electric System, is defined to include most facilities 100 kV and above. The
previous version of this standard appropriately restricted the applicability of the standard to those facilities operating
above 200kV and any additional facilities identified by the Regional Reliability Organization as critical. This new
version of the standards attempts to limit the 100-200 kV class applicability by having the RC identify the critical
facilities. We believe the change creates unnecessary and undesirable confusion in that one requirement of the
standard says that it applies to all the BES and then another requirement limits the application. Leaving the term
"electric transmission systems" in the definition is preferable to that proposed.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Nebraska Public Power
District
Disagree
NPPD disagrees with the change to bulk electric system, because it creates confusion on the applicability. This
standard only applies to certain lines and not the entire (bulk) system.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Manitoba Hydro
Disagree
Manitoba Hydro disagrees with changing "electric transmission systems" to "Bulk Electric System" because BES
applies to facilities 100kV and above which may not have an impact on system reliability.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Consumers Energy Company
Disagree
Consumers Energy disagrees with changing the current "electric transmission systems" to "bulk electric system".
This change will create confusion and can lead to a discrepancy concerning lines operating below 200kV that may
be included in the "bulk electric system" but are otherwise excluded from this standard.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
September 8, 2009
18
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 1 Comment
and has revised the purpose statement to delete BES and return to electric transmission system.
National Grid
Disagree
Use of the term Bulk Electric System will cause unnecessary confusion to the industry concerning applicability of
this Standard.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Edison Electric Institute
Disagree
The purpose of the standard should be revised to state 'To maintain minimum clearances sufficient to avoid any
vegetation-related Sustained Outages for all applicable conditions.' This is the identical wording taken from Order
No. 693, Paragraph 731.
Response: The SDT appreciates your comments to use the exact wording in the FERC Order for the purpose statement. However, the SDT believes
strongly that the interconnected system reliability which FERC should be protecting is better defined by the second posting statement. For instance,
there are 200 kV circuits which serve only local load. Outages to these circuits from vegetation are no different than from other causes. The issue for
this standard should be the prevention of vegetation outages that will threaten the interconnection.
Consolidated Edison
Company of New York
(CECONY)
Disagree
The phrase "Bulk Electric System" (BES) is somewhat misleading. BES includes transmission voltages greater than
100kV but this Standard addresses transmission lines with operating voltages at or above 200kV and only those
lines below 200kV designated by the Reliability Coordinator. Use of the phrase "electric transmission circuits" or
something similar rather than BES would reduce confusion.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Arizona Public Service
Company
Disagree
APS suggest the following change; To improve the reliability of the Bulk Electric System by preventing vegetation
related outages. This is a reliability standard APS would suggest removing "that could lead to widespread
cascading failures" from the purpose statement.
Response: The SDT thanks you for your comment. However, the SDT believes strongly that the interconnected system reliability which FERC should
be protecting is better defined by the second posting statement. For instance, there are 200 kV circuits which serve only local load. Outages to these
circuits from vegetation are no different than from other causes. The issue for this standard should be the prevention of vegetation outages that will
threaten the interconnection.
Duke Energy Corporation
September 8, 2009
Disagree
Duke disagrees with changing "electric transmission systems" to "Bulk Electric System" because this creates the
potential for confusion or indiscriminate expansion of the scope of applicability to 100kV facilities which may not
19
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 1 Comment
have an impact on network system reliability. Using "Bulk Electric System" confuses the applicability of the
standard. Duke believes that Section 4.2 has the specificity to clearly designate any applicable lines. Thus, the term
"electric transmission systems" is appropriate.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Entergy Services
Disagree
Entergy disagrees with changing “electric transmission systems” to “Bulk Electric System.” Historically, the
definition of the Bulk Electric System has included all lines operated at voltages 100 kV and greater. The above
change in terminology will add ambiguity to which lines this standard is applicable. Entergy is concerned about the
potential for this ambiguity leading to the expansion of the applicability of the standard to include lines below 200kv.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
JEA
Disagree
We disagree with this change as it may cause confusion on the applicability of the standard as the BES is generally
100kV and above, but this standard generally applies to 200kV and above.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Great River Energy
Disagree
The standard specifically calls out that 200kV and higher are applicable to FAC-003. Changing to BES would imply
all lines 100kV and above would be applicable
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system.
Western Area Power
Administration, Upper Great
Plains Region
Agree
Western (UGPR) agrees with the objective of using the FERC/NERC defined term "Bulk Electric System", but
believe that the FERC/NERC definition includes lines above 100 kV. It needs to be clearly understood that use of
the generic term in the Purpose section does not supersede the specific definitions (greater than 200 kV, etc.)
contained in the Facilities section.
Response: The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system based on a overwhelming industry preference for the
latter.
September 8, 2009
20
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Platte River Power Authority
Agree?
Agree
Question 1 Comment
The use of the approved terminology, Bulk Electric System, from the NERC Glossary of Terms is better than the
undefined term electric transmission systems.
Response The SDT thanks you for your comment. Based on the comments received, the SDT understands there may be confusion caused by “BES”
and has revised the purpose statement to delete BES and return to electric transmission system based on a overwhelming industry preference for the
latter.
Northeast Utilities
Agree
Agree with the term "bulk electric system. "Disagree with the wording of the Purpose Statement; The Purpose
statement reads "To improve the reliability of the bulk electric system by preventing vegetation related outages that
could lead to Cascading." One vegetation-caused outage does not in and of itself cause Cascading. Cascading will
only result due to a combination of events - either multiple vegetation outages during the same time or an outage
coupled with equipment malfunction or operational errors. The document seems to be internally inconsistent in this
regard. The Technical Reference for FAC-003-2 notes that outages due to trees falling from outside the right-of-way
or other outage causes on a critical facility would not constitute a possible cascading effect. If one occurrence of
these types of outages would not constitute a cascading potential then one must wonder why an outage from a tree
contact within the right-of-way is considered a possible cascading event? Suggest rewording the statement to
exclude the comment about Cascading and use "by preventing vegetation related outages on critical transmission
facilities."
Response: The SDT thanks you for your comment. The SDT acknowledges that a single vegetation-related outage will not, in the absence of other
contributing factors cause a cascading collapse of the electric grid. The intent of the standard is to prevent those vegetation-related outages that could
contribute to a cascading event. Therefore based on your comment, and others’, the SDT added “those” to further refine the intent.
Southern California Edison
Company
Agree
Q1: SCE agrees in part with the proposed revisions to the purpose statement. However, we believe the phrase
"vegetation related outages" is unnecessarily vague. Based on the content of certain requirements in Version 2, the
intent of this standard is and should be to prevent sustained outages due to vegetation-to-line contacts. SCE
respectfully suggests the purpose statement (A3) be revised to read: "To improve the reliability of the Bulk Electric
System by preventing vegetation-to-line contacts that could lead to Cascading?
Response: The SDT thanks you for your comment. The SDT focuses this standard on preventing vegetation-related Sustained Outages rather than
vegetation to line contacts as you recommend because not all contacts result in Sustained Outages.
BCTC
Agree
Yes, we agree.
Western Utility Arborists
Agree
Yes, we agree.
September 8, 2009
21
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Bonneville Power
Administration
Agree
FirstEnergy
Agree
Santee Cooper
Agree
Exelon
Agree
City of Tallahassee
Agree
Northern California Power
Agency (NCPA)
Agree
Northern Indiana Public
Service Company
Agree
Xcel Energy
Agree
Long Island power Authority
Agree
USDA Forest Service,
Southwestern Region,
Regional Office for AZ and
NM
Agree
Pacific Gas & Electric Co.
Agree
NV Energy (fka Sierra Pacific
/ Nevada Power Co.)
Agree
San Diego Gas & Electric
Agree
Hydro One Networks Inc.
Agree
September 8, 2009
Question 1 Comment
22
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
NPCC
Agree
WECC Reliability
Coordination
Agree
WECC
Agree
Baltimore Gas & Electric
Company
Agree
CenterPoint Energy
Agree
Pepco Holdings, Inc
Agree
Independent Electricity
System Operator
Agree
Salt River Project
Agree
Hydro-Quebec Transenergie
(HQT)
Agree
Buckeye Power, Inc.
Agree
Question 1 Comment
Response: The SDT thank you for your participation. The SDT made revisions to the purpose statement in response to industry comment. In order to
avoid confusion the SDT replace “BES” with “electric transmission system” and inserted the word “those” in front of the phrase “vegetation-related
outages”.
September 8, 2009
23
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
2. The Reliability Coordinator was chosen as the proper entity to identify sub-200kV transmission lines to be subject to
this standard (see applicability, R9, and R10). Do you agree with this choice? If not, please explain.
Summary Consideration: A majority of the commenters agreed with the selection of Reliability Coordinator to designate sub200 kV transmission lines to which this standard applies. However several dissenters recommended the Planning Coordinator
(PC) as a more appropriate choice. The stakeholders’ main reason for preferring the PC is the longer time horizon that the PC
normally considers in the performance of its function. Typically an RC considers the real time to months ahead operating time
horizons. A PC typically takes into account a planning horizon extending out several years. An example cited by some
stakeholders is the assignment to the PC for identifying applicable lines in NERC Standard PRC-023 R3 – Transmission Relay
Loadability.
Upon consideration of the sound rationale for replacement of RC with PC, the SDT changed Requirement R10 and R11 as well
as the applicability section 4.2 to reflect this.
Some commenters suggested that facilities critical to the derivation of an IROL should be the only criterion for selection of lines
subject to this standard. The Independent System Operator - Regional Transmission Owner Council (ISO/RTO Council) and
individual ISOs offered that all transmission lines of the BES are applicable under this standard regardless of voltage class or
impact on the BES. However the ISO/RTO Council believes that there are other standards that determine critical facilities.
The SDT agreed that including facilities critical to the derivation of an IROL would be a technically acceptable threshold to
determine applicability of sub-200 kV lines, but concluded that there are other thresholds that define circuits important to the
reliability of the Bulk Electric System (e.g., the WECC region’s Major Transfer Paths). The SDT wishes to allow the application of
other criteria in addition to IROL to support to the greatest extent possible the reliability of the BES.
Several commenters recommended the inclusion of a dispute resolution process and coordination between Transmission
Owner/RC in this standard to ensure agreement and consistency across regions. The SDT believes that the language in
Requirement R10 which specifies “consultation” OR CONSENSUS between the Planning Coordinator and its member
Transmission Owners, would minimize the need for a dispute resolution process. Additionally, other Standards in which the PC
determines important circuits to the reliability of the BES include no such mechanism.
Deleted: Reliability
Requirements R9 and R10 (now R10 and R11) were changed as follows:
R9.
Each Planning Coordinator shall prepare and review annually, a list lines that are operated below 200kV, if any, which are
subject to this standard. . Each Planning Coordinator shall consult with its Transmission Owner(s) and neighboring Planning
Coordinators to obtain input to develop the list.
September 8, 2009
Formatted: Indent: Left: 0",
Pattern: Clear (Custom
Color(RGB(211,220,233)))
24
Deleted: in consultation with its
Transmission Owner(s) and neighboring
Reliability Coordinator(s) shall jointly
prepare and keep current
Deleted: of designated applicable
Formatted: Indent: Left: 0",
Pattern: Clear (Custom
Color(RGB(211,220,233)))
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
R10. Each Planning Coordinator shall develop and document its method for assessing the reliability significance of sub-200kV lines
whose loss would place the grid at an unacceptable risk of instability, separation, or cascading failures.
Organization
Agree?
SERC Vegetation Management
Subcommittee (VMS)
Question 2 Comment
Deleted: Reliability
Deleted: considering all of the
following:¶
R10.1 Transmission lines whose loss
would result in the exceedance of an
Interconnection Reliability Operating
Limit (IROL)¶
R10.2 Transmission lines
The SERC Vegetation Management Subcommittee (VMS) abstains on this question. However, we believe that this
comment form should provide an option to abstain in addition to the options to agree/disagree.
Response: Thank you for your comment. The SDT does not believe this issue can be addressed by this team. However it is appropriate to raise this
limitation with the NERC staff.
American Transmission
Company
Disagree
Requirements 9 and 10 should be deleted and replaced with the following language. Proposed Language The
Transmission Owner shall include those transmission lines below 200 kV that that are associated with an established
IROL. (This language could either be uses as a requirement or inserted into the Applicability section.) Our statement
provides a clear decision on which lower voltage lines have to be included in an entities transmission vegetation
management program.
Response: Thank you for your comments. The SDT replaced RC with PC in Requirements R9 and R10 (now R10 and R11)as well as the applicability
section 4.2. The SDT believes that further guidance is needed to ensure all regions have evaluated and developed a list of sub 200kV lines that are subject
to this standard. The FERC indicated that not all regions produced such lists and directed the ERO, using this stakeholder process, to develop a
mechanism to provide the list. The proposed R10 continues to require consultation between the PC and Transmission Owner as well as neighboring PCs.
In R10, the SDT believes that the PC has the requisite expertise and planning horizon perspective to designate sub 200kV lines to comply with this
standard. Limiting the choice of lines to solely IROL lines may not achieve the purpose of this standard. The SDT intends in R10 that the PC employ a
technically sound criterion when designating transmission lines to be subject to this standard which includes IROL calculations.
Associated Electric
Cooperative Inc.
Disagree
Associated Electric Cooperative Inc does not believe the Reliability Coordinator (RC) is the appropriate entity to
determine whether or not selected sub-200 kv transmission lines should be subject to this standard. The planning
horizon for the RC is typically much shorter than the time needed to incorporate a sub-200 kv transmission line into a
vegetation management program. Associated recommends Planning Coordinator be designated as the applicable
functional entity and be substituted wherever Reliability Coordinator appears in the Standard.
Response: Thank you for your comment. The SDT agrees and has replaced RC with PC in Requirements R9 and R10 (now R10 and R11) as well as the
applicability section 4.2.
Santee Cooper
September 8, 2009
Disagree
The RC should not define applicable lines that are operated below 200 kV. PRC023 requires the Planning
Coordinator to define transmission lines operated at 100 kV to 200 kV that are considered critical to the reliability of
25
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 2 Comment
the Bulk Electric System. Multiple lists will lead to confusion among electric utilities.
Response: Thank you for your comments. Several commenters offered sound rationale for replacement of RC with PC including a reference to NERC
Standard PRC-023 Relay Loadability. The SDT agreed with the rationale and changed Requirements R9 and R10 (now R10 and R11) as well as the
applicability section 4.2 to reflect this.
Southern Company
Disagree
The use of the Reliability Coordinator as the entity for identifying sub-200 kV lines is inconsistent with the approach
used in other NERC standards, such as PRC-023. Other NERC standards utilize the Planning Coordinator or the RRO
as the entity. We feel the Planning Coordinator would be the appropriate entity for identifying sub-200 kV lines
covered by FAC-003-2.
Response: Thank you for your comments. Several commenters offered sound rationale for replacement of RC with PC including a reference to NERC
Standard PRC-023 Relay Loadability. The SDT agreed with the rationale and changed Requirements R9 and R10 (now R10 and R11) as well as the
applicability section 4.2 to reflect this.
SERC OC Standards Review
Group
Disagree
The SERC OCSRG does not believe that the RC is the appropriate entity to identify sub-200 kV transmissions to be
subject to this standard. Vegetation Management programs are longer than the normal operating horizons of RCs.
We believe that the proper function to identify sub-200 kV transmission lines subject to this standard is the Planning
Coordinator. This must be consistent with PRC-023, Requirement 3. We also recommend that a process be
established for dispute resolution. NERC should develop a comprehensive approach to the determination of "critical"
facilities rather than pushing a piecemeal approach as evidenced by this standard and PRC-023, among others.
Response: Thank you for your comments. Several commenters offered sound rationale for replacement of RC with PC including a reference to NERC
Standard PRC-023 Relay Loadability. The SDT agreed with the rationale and changed Requirements R9 and R10 (now R10 and R11) as well as the
applicability section 4.2 to reflect this. In regard to dispute resolution process, the SDT believes that the requirement for consultation implies cooperation
and collaboration between entities and a dispute resolution process is not currently needed.
In regard to a comprehensive approach to identify/determine “critical” facilities, the SDT agrees in concept but has some reservations. The reservations
are based upon doubt that “one size can fit all” for every context of every standard. A critical facility for one situation may not be a critical facility for
another. For example, the PRC standard seeks to identify facilities that may need to carry very heavy contingent flows to stop a cascade. This FAC-003
standard seeks to identify facilities for which their OUTAGE (due to vegetation) would create reliability concerns for the BES.
IRC Standards Review
Committee
September 8, 2009
Disagree
We do not see the role of an RC or PC in a vegetation management standard. All Transmission Owners need to
ensure they have a vegetation program to avoid unnecessary tripping of transmission lines, at any voltage levels and
regardless of their impacts on the BES. Identification of critical facilities is not a part of this standard; it belongs to
other standards that deal with SOL/IROL calculations, SPS, protection and critical infrastructure protection. R10 and
26
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 2 Comment
R11 should be removed from the standard.
Response: Thank you for your comments. The SDT does not agree with removal of R10 and R11. The SDT does not believe the burden of compliance for
low voltage circuits with little or no impact on the BES is reasonable for electricity consumers to bear. FERC has acknowledged the same and given
guidance for this standard’s applicability which provides that a distinction exists in sub-200 kV facilities. The SDT sought to develop a reasonable
mechanism that balances these concerns when we drafted R9 and R10 (now R10 and R11). The SDT agrees with respect to use of the label “critical”. This
standard does not intend to classify facilities as critical, that is left to CIP-002.
Independent Electricity System
Operator
Disagree
The IESO does not see a role for an RC or PC in a vegetation management standard. All Transmission Owners need
to ensure they have a vegetation program to avoid unnecessary tripping of transmission lines, particularly those that
impact the BES. We are of the view that identification of critical facilities is not a part of this standard; it belongs to
other standards that deal with SOL/IROL calculations, SPS, protection and critical infrastructure protection. R10 and
R11 should therefore be removed from the standard.
Response: Thank you for your comments. The SDT does not agree with removal of R10 and R11. The SDT does not believe the burden of compliance for
low voltage circuits with little or no impact on the BES is reasonable for electricity consumers to bear. FERC has acknowledged the same and given
guidance for this standards’ applicability which provides that a distinction exists in sub-200 kV facilities. The SDT sought to develop a reasonable
mechanism that balances these concerns when we drafted R9 and R10 (now R10 and R11). The SDT agrees with respect to use of the label “critical”. This
standard does not intend to classify facilities as critical, that is left to CIP-002.
Hydro-Quebec Transenergie
(HQT)
Disagree
HQT believe that the Planning Coordinator (PC) should be the entity responsible to determine the elements part of the
BPS submitted to this Standard, and in fact for all other Standards. Those elements should be determined by an
impact based methodology, as used in NPCC, with no voltage limitation and no fixed voltage threshold level as
imposed in Applicability 4.2.
Response: Thank you for your comments. Several commenters offered sound rationale for replacement of RC with PC. The SDT agreed with the rationale
and changed Requirement R9 and R10 (now R10 and R11) as well as the applicability section 4.2 to reflect this. The SDT believes each PC can determine
the appropriate threshold to assure the reliability of the BES and does not believe it necessary to instruct PCs in this regard in this Standard.
MRO NERC Standards Review Disagree
Subcommittee
The MRO disagrees that the RC is appropriately positioned to identify and designate any sub-200kV lines that should
be subject to this standard. The MRO believes that the lines below 200kV should include only those that are currently
classified as Interconnection Reliability Operating Limit (IROL) lines which are already defined and listed for registered
entities. As such R10 and R11 should be eliminated from these standards along with the RC in the applicability
section.
Response: Thank you for your comments. The SDT agrees that the RC is not appropriately positioned and replaced the RC with the PC. The SDT believes
September 8, 2009
27
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 2 Comment
that further guidance is needed to ensure all regions have evaluated and developed a list of sub 200kV lines that are subject to this standard. FERC
indicated that not all regions produced such lists and directed the ERO, using this stakeholder process, to develop a mechanism to provide the list. The
proposed R10 continues to require consultation between the PC and Transmission Owner as well as neighboring PCs. In R10, the SDT believes that the
PC has the requisite expertise and planning horizon perspective to designate sub 200kV lines to comply with this standard. Limiting the choice of lines to
solely those included in the derivation of an IROL may not achieve the purpose of this standard. The SDT intends in R10 that the PC employ a technically
sound criterion when designating transmission lines to be subject to this standard, which could include those included in the derivation of IROL
calculations.
Midwest ISO Stakeholders
Standards Collaborators
Disagree
We do not believe that the RC is the appropriate entity to identify those facilities sub-200 kV facilities that this standard
should apply to. Vegetation management is not performed in the operating horizon. Rather it is performed in the
planning and operations planning horizons. The RC should not be distracted from focusing on the operating horizon
by this task. We believe what the standard is essentially requiring is identifying critical facilities. There are other
similar requirements such as PRC-023-1 R3 that appear to require the determination of critical facilities even though
the term critical facilities is not defined. We believe this represents broader issue that requires NERC to define critical
facilities. Failure to do so could result in the inefficient identification of multiple lists of critical facilities for specific
requirements that may ultimately be challenged in due process.
Response: Thank you for your comments. Several commenters offered sound rationale for replacement of RC with PC including a reference to NERC
Standard PRC-023 Relay Loadability. The SDT agreed with the rationale and changed Requirements R9 and R10 (now R10 and R11) as well as the
applicability section 4.2 to reflect this. Your comment on time horizon further supports this change.
In regard to a comprehensive approach to identify/determine circuits, the SDT agrees in concept but has some reservations. The reservations are based
upon doubt that “one size can fit all” for every context of every standard. A critical facility for one situation may not be a critical facility for another. For
example, the PRC standard seeks to identify facilities that may need to carry very heavy contingent flows to stop a cascade. This FAC-003 standard seeks
to identify facilities for which their OUTAGE (due to vegetation) would create reliability concerns for the BES.
Ameren
Disagree
While the RC would seemingly have the wide area view to make the assignment appropriate, the standard is really
trying to determine the entity who can assess the risk to the BES of a vegetation-related outage. The management of
that risk is in the venue of the Transmission Planner who, in the long term, designs the system and, in the Operating
Horizon, establishes the parameters of operation that will lead to reliability. Certainly, the RC is preferable to the RE
(RRO). However, the TP is preferable to the RC.
Response: Thank you for your comments. Several commenters offered sound rationale for replacement of RC with PC including a reference to NERC
Standard PRC-023 Relay Loadability. The SDT agreed with the rationale and changed Requirements R9 and R10 (now R10 and R11) as well as the
applicability section 4.2 to reflect this. The PC performs its function over a similarly long term time horizon as the Transmission Planner but would be
better positioned as a result of the PC’s wider area view.
September 8, 2009
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Organization
Manitoba Hydro
Agree?
Disagree
Question 2 Comment
Manitoba Hydro disagrees that the RC is appropriately positioned to identify and designate any sub-200kV lines that
should be subject to this standard. Lines below 200kV should include only those that are currently classified as
Interconnection Reliability Operating Limit (IROL) lines which are already defined and listed for registered entities. As
such R10 and R11 should be eliminated from this standards along with the RC in the applicability section.
Response: Thank you for your comments. The SDT agrees that the RC is not appropriately positioned and replaced the RC with the PC in the revised draft
proposed Standard.
The SDT agrees that lines included in the derivation of an IROL should be included in the PC’s list; there are other lines that have importance to the
reliability of the BES, e.g. the WECC Major Transfer Paths. The PC is well qualified for this differentiation task and may choose to develop thresholds
which match the needs of its region. Therefore, the SDT respectfully disagrees that the only sub-200 kV circuits for which this standard should apply are
those stated by MH.
WECC
Disagree
WECC believes the Regional Entity should remain the proper entity to identify sub-200kV transmission lines subject to
this standard. The Regional Entity is in the best position to work with Transmission Owners (Transmission Owners)
and Reliability Coordinators across the interconnection to determine critical sub-200kV transmission lines.
Response: Thank you for your comments. Several commenters offered sound rationale for replacement of RC with PC. The SDT agreed with the rationale
and changed Requirements R9 and R10 (now R10 and R11) as well as the applicability section 4.2 to reflect this.
PJM Interconnection
Disagree
The RC or PC should not play a role in the vegetation management standard. All Transmission Owners need to
ensure they have a vegetation program to avoid unnecessary tripping of transmission lines, at any voltage levels and
regardless of their impacts on the BES. Identification of critical facilities is not a part of this standard; it belongs to
other standards that deal with SOL/IROL calculations, SPS, protection and critical infrastructure protection. R10 and
R11 should be removed from the standard.
Response: Thank you for your comments. The SDT does not agree with removal of R10 and R11. The SDT does not believe the burden of compliance for
low voltage circuits with little or no impact on the BES is reasonable for electricity consumers to bear. FERC has acknowledged the same and given
guidance for this standards’ applicability which provides that a distinction exists in sub-200 kV facilities. The SDT sought to develop a reasonable
mechanism that balances these concerns when we drafted R10 and R11. The SDT agrees with respect to use of the label “critical”. This standard does not
intend to classify facilities as critical, that is left to CIP-002
National Grid
Disagree
No opinion.
Response: Thank you for your participation.
September 8, 2009
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Organization
Duke Energy Corporation
Agree?
Disagree
Question 2 Comment
Duke believes that the Planning Coordinator is the appropriate entity to identify any sub-200 kV facilities that this
standard should apply to. Of note is the time frame once a sub-200kV line is designated, then the Transmission
Owner has 12 months before the line is subject to the standard. This coincides with the longer term view of the
Planning Coordinator.
Response: Thank you for your comment. Several commenters offered sound rationale for replacement of RC with PC. The SDT agreed with the rationale
and changed Requirements R9 and R10 (now R10 and R11) as well as the applicability section 4.2 to reflect this.
Great River Energy
Disagree
GRE disagrees that the RC is appropriately positioned to identify and designate any sub-200kV lines that should be
subject to this standard. GRE believes that the lines below 200kV should include only those that are currently
classified as Interconnection Reliability Operating Limit (IROL) lines which are already defined and listed for registered
entities. As such R10 and R11 should be eliminated from this standards along with the RC in the applicability section.
Response: Thank you for your comments. The SDT agrees that the RC is not appropriately positioned and replaced the RC with the PC in the draft
proposed Standard.
The SDT agrees that lines included in the derivation of an IROL should be included in the PC’s list, there are other lines that have importance to the
reliability of the BES, e.g. the WECC Major Transfer Paths. The PC is well qualified for this differentiation task and may choose to develop thresholds
which match the needs of its region. Therefore, the SDT respectfully disagrees that the only sub-200 kV circuits for which this standard should apply are
those stated by GRE.
WECC Reliability Coordination
Agree
This would be a new function in WECC RC; we are not currently staffed to perform this function.
Response: Thank you for your comment. The SDT replaced RC with PC in Requirements R9 and R10 (now R10 and R11) as well as the applicability
section 4.2.
Western Area Power
Administration, Upper Great
Plains Region
Agree
Western's (UGPR) agreement is contingent upon maintaining the requirements for consulting with Transmission
Owners and neighboring Reliability Coordinator(s) and documenting the method for assessing the reliability
significance of each included line as contained in R10 and R11.
Response: Thank you for your comment. The SDT replaced RC with PC in Requirements R9 and R10 (now R10 and R11) as well as the applicability
section 4.2. The proposed R10 continues to require consultation between the PC and Transmission Owner as well as neighboring PCs.
Progress Energy Florida
September 8, 2009
Agree
While Progress Energy agrees that the RC is the appropriate entity, the drafting team should consider including a
dispute resolution requirement for those instances when the Transmission Owner and the Reliability Coordinator
disagree as to which lines below 200 kV should be included.
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Organization
Agree?
Question 2 Comment
Response: Thank you for your comment. Several commenters offered sound rationale for replacement of RC with PC. The SDT agreed with the rationale
and changed Requirements R9 and R10 (now R10 and R11) as well as the applicability section 4.2 to reflect this. In regard to dispute resolution process,
the SDT believes that the requirement for consultation implies cooperation and collaboration between entities and a dispute resolution process is not
currently needed.
Kansas City Power & Light
Agree
I agree with the qualification that the Reliability Coordinator identify sub-200kv facilities in consultation with its
Transmission Owner(s) and neighboring Reliability Coordinator(s).
Response: Thank you for your comment. The SDT replaced RC with PC in Requirements R9 and R10 (now R10 and R11) as well as the applicability
section 4.2. The proposed R10 continues to require consultation between the PC and Transmission Owner as well as neighboring PCs.
Progress Energy Carolinas
Agree
While Progress Energy agrees that the RC is the appropriate entity, the drafting team should consider including a
dispute resolution requirement for those instances when the Transmission Owner and the Reliability Coordinator
disagree as to which lines below 200 kV should be included.
Response: Thank you for your comment. Several commenters offered sound rationale for replacement of RC with PC. The SDT agreed with the rationale
and changed Requirements R9 and R10 (now R10 and R11) as well as the applicability section 4.2 to reflect this. In regard to dispute resolution process,
the SDT believes that the requirement for consultation implies cooperation and collaboration between entities and a dispute resolution process is not
currently needed.
Southern California Edison
Company
Agree
Q2: No comments.
Response: Thank you for your participation.
Western Utility Arborists
Agree
Yes, we agree.
Response: Thank you for your comment. Please see the summary consideration – based on stakeholder comments, the SDT changed the applicability in
Requirements R9 and R10 (now R10 and R11) from the Reliability Coordinator to the Planning Coordinator.
ITC HOLDINGS
Agree
ITC agrees that the Reliability Coordinator is the appropriate entity to identify and designate any sub - 200kV lines
deemed applicable to the standard with the concurrence of the Transmission Owner.
Response: Thank you for your comment. Based on other stakeholder comments, the SDT replaced RC with PC in Requirements R9 and R10 (now R10 and
R11) as well as the applicability section 4.2. The proposed R10 continues to require consultation between the PC and Transmission Owner as well as
September 8, 2009
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Organization
Agree?
Question 2 Comment
neighboring PCs.
Tennessee Valley Authority
Agree
TVA agrees with Comment question 2
Response: Thank you for your comment. Based on other stakeholder comments, the SDT replaced RC with PC in Requirements R9 and R10 (now R10
and R11) as well as the applicability section 4.2. The proposed R10 continues to require consultation between the PC and Transmission Owner as well as
neighboring PCs.
American Electric Power (AEP) Agree
AEP concurs with the drafting team that the Reliability Coordinator is the appropriate entity for identifying sub-200kV
lines (if any) that would be subject to the Standard.
Response: Thank you for your comment. Based on other stakeholder comments, the SDT replaced RC with PC in Requirements R9 and R10 (now R10 and
R11) as well as the applicability section 4.2.
Platte River Power Authority
Agree
The Reliability Coordinator is better able to identify lines under 200 kv that would exceed an Interconnection Reliability
Operating Limit (IROL), cause instability, uncontrolled separation, or cascading outages resulting from a vegetation
related outage than the Regional Entity.
Response: Thank you for your comment. Based on other stakeholder comments, the SDT replaced RC with PC in Requirements R9 and R10 (now R10 and
R11) as well as the applicability section 4.2.
Nebraska Public Power District
Agree
NPPD agrees that the Reliability Coordinator is the correct body for identification of any sub 200kV lines that would be
subject to this standard.
Response: Thank you for your comment. Based on other stakeholder comments, the SDT replaced RC with PC in Requirements R9 and R10 (now R10 and
R11) as well as the applicability section 4.2.
Consolidated Edison Company
of New York (CECONY)
Agree
CECONY agrees provided that R10 remains the same as is currently written. This states that the Reliability
Coordinator, in consultation with the Transmission Owner, shall jointly prepare and keep current, a list of designated
applicable lines.
Response: Thank you for your comment. Based on other stakeholder comments, the SDT replaced RC with PC in Requirements R9 and R10 (now R10 and
R11) as well as the applicability section 4.2. The proposed R10 continues to require consultation between the PC and Transmission Owner as well as
neighboring PCs.
September 8, 2009
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Organization
Northeast Utilities
Agree?
Agree
Question 2 Comment
One question: Will the Reliability Coordinators use consistent criteria for listing sub 200-kV facilities to be included
under FAC-003-2? The purpose of FAC-003 is to ensure inter-regional reliability and to focus on the reliable
operation of these lines. By leaving the decision up to the individual Reliability Coordinators - there is the potential for
local differences in determining which sub-200-kV facilities may be critical. This could result in some transmission
owners having to include certain facilities under the requirements of FAC-003-2 where in other regions of the country similar facilities may not be included by the Reliability Coordinator. Although there have been criteria established to
guide the Reliability Coordinators in the determination of sub-200-KV facilities for inclusion under FAC-003-2 - is this
sufficient to ensure uniformity throughout the US? Perhaps some involvement at the Regional Entity level at least, is
warranted.
Response: Thank you for your comments. The SDT agrees with the points you raise regarding inter-regional reliability. This is addressed in part by the
requirement R10 where consultation with neighboring entities is specified. We feel that the requirement R10 ensures that inter-regional coordination is
addressed.
In addition several commenters offered sound rationale for replacement of RC with PC. The SDT agreed with the rationale and changed Requirements R9
and R10 (now R10 and R11) as well as the applicability section 4.2 to reflect this.
Baltimore Gas & Electric
Company
Agree
The documented method to assess the reliability significance of sub-200 kV lines referenced in R10 should be put out
for comment by the Reliability Coordinator to the regulated entities and FERC/NERC before it is finalized.
Response: Thank you for your comment. Several commenters offered sound rationale for replacement of RC with PC. The SDT agreed with the rationale
and changed Requirements R9 and R10 (now R10 and R11) as well as the applicability section 4.2 to reflect this.
Entergy Services
Agree
The applicability of this standard should state that it is not applicable to insulated transmission lines, such as
underground lines.
Response: Thank you for your comment. The SDT believes that the general term “transmission line” along with the associated tables and terminology
sufficiently eliminates any misconception or misdirected thought that this standard applies to underground conductors or other conductors that are
insulated in a manner that would prevent their flashover to trees.
Pepco Holdings, Inc
Agree
FERC Order 693 essentially has the RC replacing the RRO.
Response: Thank you for your comment. Several commenters offered sound rationale for replacement of RC with PC. The SDT agreed with the rationale
and changed Requirements R9 and R10 (now R10 and R11) as well as the applicability section 4.2 to reflect this.
BCTC
Agree
September 8, 2009
Yes, we agree.
33
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 2 Comment
Response: Thank you for your participation.
Buckeye Power, Inc.
Agree
Agreed on this question.
Response: Thank you for your participation.
Western Area Power
Administration, Rocky
Mountain Region
Agree
Florida Power & Light
Agree
Bonneville Power
Administration
Agree
FirstEnergy
Agree
SERC Compliance Staff
Agree
Exelon
Agree
Central Maine Power Company Agree
City of Tallahassee
Agree
Northern California Power
Agency (NCPA)
Agree
Northern Indiana Public
Service Company
Agree
Tampa Electric Company
Agree
Orange and Rockland Utilities
Agree
September 8, 2009
34
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 2 Comment
Inc.
Long Island power Authority
Agree
USDA Forest Service,
Southwestern Region,
Regional Office for AZ and NM
Agree
Consumers Energy Company
Agree
Pacific Gas & Electric Co.
Agree
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Agree
San Diego Gas & Electric
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
Arizona Public Service Co.
Agree
JEA
Agree
CenterPoint Energy
Agree
Salt River Project
Agree
September 8, 2009
35
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
3. In R1 the proposed standard replaces “prepare, and keep current” with “have”, replaces the list of terms, “objectives,
practices, approved procedures, and work specifications,” with “designed to control vegetation”, defines the “active
transmission line ROW”, and specifies that the transmission vegetation management program applies to that area. Do
you agree with R1? If not, please explain.
Summary Consideration:
Regarding the use of “have”, some commenters requested that the original wording should remain. However, the SDT and
some other commenters note that proving whether something is “current” is an opportunity for compliance ambiguity and
unintended discrimination. Therefore, the SDT continues to use “have” in the second draft.
A few commenters raised the issue concerning Critical Clearance Zone in this question and that has been addressed with the
substantive changes which have been made to the second draft standard.
While some commenters prefer the list of terms, the SDT chose the term “methods” as a more global, all encompassing term
that allows transmission owners flexibility in developing their Transmission Vegetation Management Program. The SDT agrees
the list of terms is helpful. However, when listed in a Requirement there is an expectation that all such terms must be included
and evidence produced to show compliance. The list of terms can be included in the technical reference to assist Transmission
Owners.
Finally, many commenters wanted more specificity in the reference material to describe the “Active Transmission Line Right-ofWay”. The SDT has provided additional clarification in the technical reference document.
Formatted: Space After: 6 pt,
Pattern: Clear (Custom
Color(RGB(211,220,233)))
The revised R1 is shown below:
Deleted: designed to control vegetation
Deleted: s’
R1.
Each Transmission Owner shall have a documented transmission vegetation management program that describes how it
conducts work on its Active Transmission Line Rights of Way to prevent Sustained Outages due to vegetation, considering all
possible locations the conductor may occupy under the effects of sag and sway throughout its operating range under rated
conditions. The transmission vegetation management program shall:
1.1. Specify the methods that the Transmission Owner may use to control vegetation.
Deleted: R
Deleted: methodologies
Deleted: Owner
Deleted: s
Deleted: 2
Deleted: R
1.2. Specify a Vegetation Inspection frequency of at least once per calendar year that takes into account local3 and environmental
factors.
Deleted: vegetation
1.3. Require an annual plan. An annual work plan shall:
Formatted: Superscript
Deleted: i
Deleted: R
September 8, 2009
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Deleted: that i
1.3.1 Identify the applicable lines to be maintained
Deleted: ies
1.3.2 Identify the work to be performed
Formatted: Font: Bold
1.3.3 Be flexible to adjust to changing conditions and to findings from Vegetation Inspections. Adjustments to the plan within the
year are permissible.
Deleted: and associated
1.3.4 Take into consideration permitting and scheduling requirements from landowners or regulatory authorities.
Deleted: vegetation
Deleted: during the year. It shall b
Deleted: i
1.4. Require a process or procedure for response to an imminent threat of a vegetation related Sustained Outage. The process or
procedure shall specify actions which shall include immediate communication of the threat to the responsible control center.
Deleted: The plan shall t
Deleted:
1.5. Specify an interim corrective action process for use when the Transmission Owner is constrained from performing vegetation
maintenance as planned.
1.6 Specify the maintenance strategies used (such as minimum vegetation-to-conductor distance or maximum vegetation height) to
ensure that Table 1 clearances in Attachment 1 are never violated. The maintenance strategies shall consider the sag and sway of the
conductor throughout its operating range under rated conditions.
Deleted: It shall support the objectives
of the transmission vegetation
management program and use the
methodologies outlined in the
transmission vegetation management
program.¶
R
Deleted: s
Deleted: Transmission Operator
Organization
Bonneville Power
Administration
Agree?
Disagree
Deleted: , and may include actions such
as a temporary reduction in line Rating,
switching lines out of service, or other
actions.
Question 3 Comment
R1: BPA understands that version 2 clearly states that the Critical Clearance Zone does not extend beyond the Deleted: R
Active Transmission Right of Way. The Technical reference provides examples of active and inactive portions of
Indent: Left: 0", First
corridors. BPA feels this list of examples is not exhaustive and therefore the technical reference language shouldFormatted:
line: 0", Space After: 6 pt, Pattern:
be changed to read, "Examples of active and inactive portions of corridors include, BUT MAY NOT BE LIMITED Clear (Custom
Transmission Owner:"
Color(RGB(211,220,233)))
Also, since it is clearly stated on page 2 of the Standard, that the Critical Clearance Zone shall not extend beyond
the limits of the Active Transmission Line Right of Way, and that these limits are not specifically defined because
they may vary by circumstance, the definition of Active Transmission Line Right of Way on Page 2 of the Standard
should include a statement that the actual physical limits of each Active Right of Way will be determined by the
Transmission Owner.
R1.1: BPA recommends retaining the version 1 language of "objectives, practices, approved procedures, and
work specifications" as it is more instructive in what is expected of a TMVP then the version 2 replacement
language of "methodologies."
Response: Thank you for your comment. The issues concerning Critical Clearance Zone have been addressed by changes which have been made to
September 8, 2009
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Organization
Agree?
Question 3 Comment
the draft standard. The definition and use of the term “Critical Clearance Zone” have both been removed from the revised standard.
The SDT chose, for the revised standard, the term “methods” as a more global, all encompassing term that allows transmission owners flexibility in
developing their Transmission Vegetation Management Program. ANSI A300 has been referenced as a best management practice by reference as a
footnote to R1.1.
Associated Electric Cooperative Disagree
Inc.
Associated Electric Cooperative Inc agrees with the changes described in Question 3 except for the definition of
Active Transmission Line Right of Way. Associated suggests the term be revised to "Active Right-of-Way" for
consistency with the present Glossary term "Right-of-Way" and that the definition of Active Right-of-Way be
revised to explicitly permit the Transmission Owner to solely determine the appropriate width. A suggested
definition is "Active Right-of-Way: The portion of Right-of-Way utilized for active transmission facilities. The width
of the Active Right-of-Way, as determined by the Transmission Owner, shall be consistent with the Transmission
Owner’s normal standards and practices and shall be consistent with good utility practice for other transmission
lines of similar voltage and configuration. Inactive or unused portions of the Right-of-Way, intended for future
transmission lines or other facilities, may be excluded from the Active Right-of-Way."
Response: Thank you for your comment. While there is logic in your proposal to simply modify Rights-of-Way with “Active”, previous commenters
wanted to include “Transmission” to clearly eliminate the case of rights-of-way that include lower voltage facilities.
NPCC
Disagree
While we agree with the suggested changes, we believe that the Transmission Vegetation Management Program
should be focused on removal of incompatible vegetation from the Active Right of Way. We recommend using the
following phrase in R1: "designed to remove incompatible vegetation on its Active Transmission Lines' Rights 0f
Way" instead of "designed to control vegetation on its Active Transmission Lines' Rights of Way ".
Incompatible vegetation should be defined as any vegetation which has the potential to grow tall enough to
jeopardize the integrity of an applicable transmission line by growing into the Critical Clearance Zone or falling
into the Critical Clearance Zone. This would provide clear guidance to all stakeholders, support long term
vegetation management philosophies, and complement methods such as IVM where incompatible vegetation is
completely removed, and compatible vegetation is encouraged to proliferate, thereby helping to control
incompatible vegetation in an environmentally positive manner. Removal of incompatible vegetation is superior to
pruning, topping, and trimming in terms of short and long term reliability of the Bulk Electric System. This
language would also serve to align NERC and FERC with Transmission Owners who attempt achieve the highest
degree of reliability by exercising their full easement rights in cases where strong opposition from landowners and
public officials is encountered. If such language is adopted it should apply to R1 and the Transmission Vegetation
Management Program.
It should be made clear in the technical reference document that removal, rather than pruning of incompatible
vegetation is the philosophy that must be incorporated into the Transmission Vegetation Management Program. It
September 8, 2009
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Organization
Agree?
Question 3 Comment
must be clearly explained that Transmission Owners have the flexibility to perform removals gradually over
several treatment cycles in sensitive areas as long as pruning is performed as an interim measure to ensure that
Critical Clearance Zone encroachments and on-Right of Way fall overs do not occur. It must also be made clear
that the presence of incompatible vegetation on the Right of Way will always occur and does not in itself constitute
a violation of the Standard.
Response: Thank you for your comment. The SDT has addressed removal of incompatible vegetation as a best management practice by referencing
ANSI A300 as a footnote to Requirement R1. It is noted that A300 is not a requirement of the standard, only a best management practice. We will
address your other comments in the technical reference paper for industry guidance.
Baltimore Gas & Electric
Company
Disagree
I agree with the simplification of the language, but I am uncomfortable with the definition of Active Right-of-Way
(R/W). The definition in FAC-003-2 and the examples used in the white paper continue to leave room for
interpretation, particularly with respect to the example where only one circuit is installed on a double circuit tower.
Moreover, there may be circumstances where the Active R/W is relatively narrow and the utility has an Inactive
R/W or otherwise owns land adjacent to the Active R/W that can be maintained to protect the facilities from growins. Consequently, consideration should be given to require utilities to protect lines from grow-ins into the Critical
Clearance Zone regardless of whether or not the R/W is Active or Inactive as long as the utility has the legal
ability to do the necessary work.
Response: Thank you for your comment. The Standard clearly addresses that all grow-ins are considered to be within the active right-of-way,
regardless of whether or not the tree is rooted within the active right-of-way. The Standard requires that such vegetation be managed as described in
the Transmission Owner’s Transmission Vegetation Management Program. Additionally, the SDT has revised the drawings and guidance in the technical
reference paper to eliminate the confusion you and others detected.
Northern Indiana Public Service Disagree
Company
Use of the term "have" is a notable and unnecessary weakening versus the terms "prepare and keep current".
One of the key lessons learned from past vegetation related outages and subsequent investigations and reports is
that successful UVM programs must continually adapt to changing circumstances which means practices and
procedures must be kept current. Why weaken this expectation in the standard? Also, I disagree with the
elimination from the revised standard the present requirement R1 that all Transmission Vegetation Management
Programs include certain essential components (objectives, practices, approved procedures & work
specifications). Why make changes that imply Transmission Vegetation Management Program's without these
key components are acceptable?
Response: Thank you for your comment. The SDT believes that the term “have” is appropriate. While sympathetic to your perception about the terms, in
order to “have” a Transmission Vegetation Management Program it had to have been prepared. Latency of the plan, like all plans required by NERC
standards, can easily be addressed in compliance without creating the task of proving “current” if it is included in the Requirement. The SDT chose, for
the revised standard, the term “methods” as a more global, all encompassing term that allows transmission owners flexibility in developing their
September 8, 2009
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 3 Comment
Transmission Vegetation Management Program. ANSI A300 has been referenced as a best management practice by reference as a footnote to R1.1.
Xcel Energy
Disagree
We propose adding the following language to the end of the definition for "Active Transmission Line Right of
Way": OR OTHER PURPOSES, REGARDLESS OF THE PREMISES DIMENSIONS IN ANY EASEMENT,
LICENSE AGREEMENT OR OTHER LAND RIGHT DOCUMENT.
Response: Thank you for your comment. The SDT believes that the definition of “active transmission line right-of-way” is appropriate for meeting the
objectives of the Standard. This topic will be covered in the technical reference document which will be issued with the next draft of the Standard.
Hydro One Networks Inc.
September 8, 2009
Disagree
We agree in changing the text as proposed only if R1 is expanded as suggested below. The standard as written is
primarily, if not exclusively focused on outage prevention through one means, to keep vegetation out of the
Critical Clearance Zone. The burden to accomplish this is placed on the Transmission Owner/Operator as it
should be. The first section highlights that a program is required, but does not provide a requirement above this
simplistic view, and from our perspective the Measures do not introduce any further rigour. This simplistic
approach, in our opinion, does not adequately address the reliability risks associated with the various
methodologies of managing vegetation. The White Paper notes removal is superior to pruning in ensuring tree
conflicts do not occur. The White Paper includes elements of vegetation management risks, but the revised
standard for the most part excludes this issue. One could argue that the audits and fines will manage reliability
risks, but we are not convinced that this will do so in a consistent and adequate manner. There are numerous
clearance risk factors associated with managing vegetation on rights of way. Some of these are: accurate
measurement of conductor sag, accurate measurement of vegetation, vegetation growth rate, conductor sway,
tree movement. If one looks at Table 1, the Clearance Distances are to the nearest cm or 1/100 of a foot. This
makes one wonder, how realistic are the expectations laid out in the standard? To manage the risks around the
Critical Clearance Zone the Standard requires each Transmission Owner to work with these precise numbers and
build in a margin of safety to manage the situation. Will each Transmission Owner use identical criteria to trigger
work? This doubtful, so this leads one to believe that the standard has not been designed to produce consistent
results, which in our opinion is the case. So one has varied field conditions that are difficult to nail down, precise
clearance requirements to the nearest 1/100? and the likelihood of inconsistent margins of safety. We realize that
the audit process will help to assess these situations, but it may not be enough to achieve a somewhat uniform
risk profile across the transmission systems. Other standards that we are familiar with include a margin of safety
such as added clearance above the absolute minimum recognizing that it may not be practical to work to such
precise measures. Examples of standards that use this approach to ensure consistent and reliable results include
OHSA and the Canadian Standards Association. We are not advocating that this standard follows an identical
approach, but do want to highlight that the standard may fall short in the area of managing vegetation
management risks which in turn have a direct impact on reliability. Considering the above, it is suggested that the
aspect of managing vegetation reliability risks be added to the White Paper to allow Transmission Owners to
develop somewhat consistent criteria. Further on the topic of managing risk. We believe that reliability risks are
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Agree?
Question 3 Comment
directly related to the amount of incompatible vegetation on a right of way that is approaching the Critical
Clearance Zone. Incompatible vegetation would be vegetation that has the potential to grow into the Critical
Clearance Zone at full growth. We suggest that risks could be reduced significantly by including direction in the
standard concerning the management of incompatible vegetation. This would drive a greater degree of
consistency among Transmission Owners and would reduce the amount of vegetation on rights of way that have
the potential to cause flashover. In addition, this would reinforce the reliability risks associated with vegetation,
not just from a clearance perspective but also from a volume perspective, and would provide a more
comprehensive view for the public and interest groups. In order to respond to what we consider a shortcoming of
the proposed standard, our suggestion would be to expand R1.1 similar to the following:
Specify the methodologies that the Transmission Owner uses to control vegetation and demonstrate that the
removal of non-compatible vegetation is a focus within the plan. It is recognized that reliability risks increase
appreciably with an increase in incompatible vegetation on an active right of way, and the Transmission Owner is
required to remove incompatible vegetation at a point no later in time when it poses a threat to the reliability of the
transmission line. Exceptions include vegetation used for designated visual screens, trees of a historic
significance, vegetation to control erosion, agreements made at the time of environmental approval for
construction,???etc.
Response: Thank you for your comments. The SDT revised the standard so that it no longer references the “Critical Clearance Zone.” The SDT chose,
in the revised standard, to use the term “methods” as a more global, all encompassing term that allows transmission owners flexibility in developing
their Transmission Vegetation Management Program. ANSI A300 has been referenced as a best management practice by reference as a footnote to R1.1.
Moreover, we believe the Standard as subsequently revised provides flexibility for Transmission Owners to develop their own vegetation management
programs. But we are sensitive to the issues you raised and have tried to define through the subsections in R1 that specific elements are necessary.
CenterPoint Energy
September 8, 2009
Disagree
The term "Active Transmission Line Right-of-way" is not defined in sufficient detail in the Definition of Terms Used
in the Standard section to know how to apply the Requirements. The term causes a circular reference problem
with the term "Critical Clearance Zone" that refers to the "limits of the Active Transmission Line Right-of-way"
which has no specific definition as to its limits within the proposed revised Standard. There is an attempt to
differentiate between the "Total R.O.W." and the "Active R.O.W." portion by using the phrase "occupied by active
transmission facilities", but no specific limits of such occupation are included within the definition. Are "active
transmission facilities" only the physical energized conductors as-is, where-is? Does "occupied" include the
conductor vertical and horizontal movement envelope and any horizontal and vertical electrical clearance as well?
Does the term "Active Transmission Line Right-of-way" refer to the legal limits of the right-of-way? The new R9
includes the phrase "within the extent of its easement and/or legal rights" which seems to support that definition.
The phrase "a strip of land" seems to refer to a metes and bounds description, but how is that relevant when no
specific land space is defined, such as with a railroad occupation or Corp of Engineer's permit? On page 16 of the
Technical Reference, there is a reference to the Bramble and Byrnes wire-border zone technique. The wire zone
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Question 3 Comment
is defined in the Technical Reference as "the section of a utility transmission right-of-way directly under the wires
and extending outward about 10 feet on each side". Are the limits of the "Active Transmission Line Right-of-way"
intended to be equivalent to the Bramble and Byrnes wire zone, or is the Transmission Owner to use its discretion
to define the limits? The examples in the Technical Reference document do not define the limits of the "active
transmission facilities" either. The "Active R.O.W." limit in Figure 1 and Figure 3 is arbitrary. Figure 2 is supposed
to display an edge zone for vegetation to exist, which implies an "Inactive R.O.W" portion, but no such zone is
defined. Figure 1 also has trees shown inside the "Total R.O.W." and within the "Inactive R.O.W." that are tall
enough and close enough to be within falling distance of the active transmission line which seems averse to R7
for vegetation falling into a conductor when the Transmission Owner likely has legal rights to remove them if they
are within the "Total R.O.W." and are within falling distance. The interpretation of M7 will be difficult in this case
without a specific method to define the "Active R.O.W." portion of the Total R.O.W. We recommend deleting the
confusing terms "Active Transmission Line Right-of-way and "Critical Clearance Zone" and returning to the prior
Clearance 2 Requirement with the newly specified minimum clearances from Table I of Attachment 1 as an
alternative approach should the definition of minimum vegetation clearance distances remain integral to the
Standard.
Response: Thank you for your comments. The Critical Clearance Zone concept has been removed from the latest draft of the Standard. While the SDT
believes that the definition of “active transmission line right-of-way” in the Standard is appropriate, this concept will be further reviewed by the SDT in
the context of the technical reference and your comments. And we agree that a further explanation is required to eliminate questions like the ones you
raised. The new examples in the technical reference should eliminate that ambiguity.
JEA
Disagree
The standard should EITHER require an entity to have and follow a program OR hold an entity to performance
standards, but not both. Requiring a procedure in conjunction with performance requirements incents the entity to
write procedures that meet only the minimum requirements of the standard, as they will be audited and held
accountable for what is documented and performance against that. If performance requirements are in place
without the concurrent requirement for a procedure, then the entity is incented to develop procedures that meet
best practices in order to assure that they will meet or beat the performance standards, because in this scenario,
such procedures do not expose the entity to additional compliance risk while enhancing reliability.
Response: Thank you for your comment. The Standard provides the framework for Transmission Owners to develop and implement an effective
transmission vegetation management program in support of the main reliability objective: preventing sustained outages of transmission lines that could
lead to cascading. During the drafting process, many members of the drafting team asserted that several of the requirements are merely facilitative in
nature and would be unnecessary if sustained outages are successfully prevented. Because this standard is relatively new compared to standards that
were developed from operating policies that had been followed for decades, there is a sense that the benefits of "defense in depth" (keeping the
facilitating requirements) may be warranted until entities have more experience with mandatory vegetation management.
September 8, 2009
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Salt River Project
Agree?
Disagree
Question 3 Comment
R1.1 states "Specify the methodologies that the Transmission Owner uses to control vegetation". The word
"methodologies" does not adequately replace "objectives, practices, approved procedures, and work
specifications". Recommend to keep the original wording.
Response: Thank you for your comments. The SDT chose “methods” in R1 part 1.1 to provide flexibility for Transmission Owners to develop their own
vegetation management programs. ANSI A300 has been referenced as a best management practice in a footnote to 1.1. The Technical Reference
Document provides examples of the variations in methods that are necessary due to the wide diversity of vegetation across North America.
Hydro-Quebec Transenergie
(HQT)
Disagree
While we agree with the suggested changes for the terms proposed , we believe that the Transmission Vegetation
Management Program should be focused on removal of incompatible vegetation from the Active Right of
Way.R1.1 could read: Specify the methodologies that the Transmission Owner uses to control vegetation and
demonstrate that the removal of non-compatible vegetation is a focus within the plan. Incompatible vegetation
should be defined as any vegetation which has the potential to grow tall enough to jeopardize the integrity of an
applicable transmission line by growing into the Critical Clearance Zone or falling into the Critical Clearance
Zone . This would provide clear guidance to all stakeholders, support long term vegetation management
philosophies, and complement methods such as IVM where incompatible vegetation is completely removed, and
compatible vegetation is encouraged to proliferate, thereby helping to control incompatible vegetation in an
environmentally positive manner.
Response: Thank you for your comments. The SDT has re-written this Requirement to address your concerns in a manner that allows transmission
owners flexibility in developing their Transmission Vegetation Management Program. ANSI A300 has been referenced as a best management practice by
reference as a footnote to R1.1. Moreover, we believe the Standard as subsequently revised provides flexibility for Transmission Owners to develop
their own vegetation management programs.
Western Area Power
Administration, Upper Great
Plains Region
Agree
A question that has surfaced during discussions within the industry is "Can the Transmission Owner designate an
active R/W width that is less than the easement width even with a single-circuit line with no R/W set aside for
vegetation buffer or future development?" OR, does the easement width equate to "Active T-Line ROW" under
the situation described above.
Response: Thank you for your comment. The intent of the Standard is that such rights-of-way as identified in your response are considered as “active
transmission rights-of-way” in general for their full width. The definition of “active transmission line right-of-way” was developed to recognize that in
some cases additional ROW width was secured to allow for buffers and future expansion. This is further described in the technical reference document.
Western Utility Arborists
September 8, 2009
Agree
Yes, we agree, subject to the qualification about “active” rights-of-way under Comment #16. Under R1.1, it says
“Specify the methodologies that the Transmission Owner uses to control vegetation.” The single word
“methodologies” does not adequately replace “objectives, practices, approved procedures, and work
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Question 3 Comment
specifications.” The Western Utilities recommends keeping the original wording. We would also like to point out
that the original intent of the standard was to ensure that utilities had a complete vegetation management
program. The new standard is evolving towards an outage control program, and no longer encourages programs
or behaviors that would ensure the causes of outages are prevented long before they become a problem. The
standard now redirects efforts to avoiding outages instead of managing vegetation.
Response: Thank you for your comments. The SDT has re-written this Requirement to address your concerns in a manner that allows transmission
owners flexibility in developing their Transmission Vegetation Management Program. ANSI A300 has been referenced as a best management practice by
reference as a footnote to R1.1. Moreover, we believe the Standard as subsequently revised provides flexibility for Transmission Owners to develop
their own vegetation management programs. The SDT believes that the latest draft includes Requirements that dictate appropriate behavior in
controlling vegetation but also added a strong statement that outages, that could have been prevented, are inconsistent with interconnection reliability
and should be violations.
Southern California Edison
Company
Agree
Q3: No Comments.
Response: Thank you for your response.
FirstEnergy
Agree
The Inactive Right of Way, by definition, should include a strip of trees on each side of the of the right of way that
was purchased, but not cleared at the time of construction. This could be a narrow strip ten feet on each side that
is intended for future hazard tree removal.
Response: Thank you for your comment. The definition of “Active Transmission Line Right-of-Way” has been modified in the current draft of the
Standard. The SDT believes that the definition of “Active Transmission Line Right-of-Way” as currently defined is appropriate. The definition was
developed to recognize that in some cases additional ROW width was secured to allow for buffers and future expansion. This is further described in the
technical reference document. However, the SDT does not agree that a categorical “set aside” which is not active but can be is appropriate for all
Transmission Owners. Rather, some Transmission Owners may want to manage the entire rights-of-way. But flexibility is permitted within the current
draft.
MRO NERC Standards Review
Subcommittee
Agree
The MRO agrees but requests further clarification on the definition of the term "Active" in Active Transmission
Line R.O.W. For example: A utility has a 150 foot easement for a 230kV line and currently manages 80 feet. First;
is it the intent of the standard that the utility manage the entire 150 foot easement? Second; is the entire
easement considered the Active Transmission Line R.O.W?
Response: Thank you for your comment. The Transmission Owner is responsible for determining the Active ROW width based upon the definition of
“active transmission line right-of-way” included in the Standard. The scenario presented in your comment does not provide enough information for the
September 8, 2009
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Organization
Agree?
Question 3 Comment
SDT to provide a definitive answer. The definition of “Active Transmission Line Right-of-Way” has been changed in the most current draft. In addition a
technical reference document with a more detailed explanation of this topic will be issued with the next draft. These documents should provide clarity.
The definition was developed to recognize that in some cases additional ROW width was secured to allow for buffers and future expansion. This is
further described in the technical reference document. However, the SDT does not agree that a categorical “set aside” which is not active but can be is
appropriate for all Transmission Owners. Rather, some Transmission Owners may want to manage the entire rights-of-way. But flexibility is permitted
within the current draft.
ITC HOLDINGS
Agree
The standard doesn't actually explain or define the Active Transmission Line Right of Way.
Response: Thank you for your comment. A definition of “Active Transmission Line ROW” is included in the Standard. This definition has been modified
in the most current draft of the Standard. The technical reference will provide further clarity.
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 3
Response: Thank you for your comment.
American Electric Power (AEP)
Agree
While Requirement R1 does not actually define "Active Transmission Line Right of Way" (it is defined on page 2
of the Standard), AEP concurs with R1, except as noted below for R1.4.
Response: Thank you for your comment.
Platte River Power Authority
Agree
The list of terms, "objectives, practices, approved procedures and work specifications," from version 1 provides
more clarity that the one word "methodology" and should both be replaced. The newly defined term "active
transmission line ROW" provides clarity to the portion of the ROW requiring vegetation management and is a
valuable addition to the standard.
Response: Thank you for your comment. The SDT revised R1.1 to allow transmission owners the necessary flexibility in developing their Transmission
Vegetation Management Program. ANSI A300 has been referenced as a best management practice by reference as a footnote to R1.1.
American Transmission
Company
Agree
We agree with the idea but the term "active transmission facilities" needs additional clarity. This clarity could be
accomplished with a footnote. Proposed Footnote: A transmission facility that contains a transmission line to
which FAC-003 is applicable. The proposed footnote aids in the identification of applicable transmission facilities.
Response: Thank you for your comment. Applicable lines are defined in Section 4 of the Standard.
September 8, 2009
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
USDA Forest Service,
Agree
Southwestern Region, Regional
Office for AZ and NM
Question 3 Comment
My disagreement with R1
Response: Thank you for your comment; however the SDT does not understand your comment.
National Grid
Agree
Defining "Active Transmission Line Right-of-Way" solves the Right-of-Way definition problem within the SAR.
Response: Thank you for your comment.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Agree
Yes, we agree, subject to the qualification about “active” rights-of-way under Comment #16. We would also like to
point out that the original intent of the standard was to ensure that utilities had a complete vegetation
management program. The new standard is evolving towards an outage control program, and no longer
encourages programs or behaviors that would ensure the causes of outages are prevented long before they
become a problem. Instead, it redirects efforts to avoiding outages instead of managing vegetation. If this is now
the preferred approach, the term Transmission Vegetation Management Program is no longer valid and should
perhaps be changed to the Transmission Vegetation Outage Prevention Program. Under R1.1, it says “Specify
the methodologies that the Transmission Owner uses to control vegetation.” The single word “methodologies”
does not adequately replace “objectives, practices, approved procedures, and work specifications.” We
recommend that the SDT retain the original wording.
Response: Thank you for your comments. The SDT revised R1.1 to allow transmission owners the necessary flexibility in developing their Transmission
Vegetation Management Program. ANSI A300 has been referenced as a best management practice by reference as a footnote to R1.1. The SDT believes
that the latest draft includes Requirements that dictate appropriate behavior in controlling vegetation but also added a strong statement that outages,
that could have been prevented, are inconsistent with interconnection reliability and should be violations.
San Diego Gas & Electric
Agree
Yes, we agree, subject to the qualification about "active" rights of way under comment 16. Under R1.1 it says
"Specify the methodologies that the Transmission Owner uses to control vegetation." The single word
"methodologies" does not adequately replace "objectives, practices, approved procedures, and work
specifications." We recommend keeping the original wording.
Response: Thank you for your comment. The SDT revised R1.1 to allow transmission owners the necessary flexibility in developing their Transmission
Vegetation Management Program. ANSI A300 has been referenced as a best management practice by reference as a footnote to R1.1.
Northeast Utilities
September 8, 2009
Agree
With respect to "active transmission line ROW" the examples provided in the Technical Reference document for
FAC-003-2 show that any areas of the easement or fee-owned right-of-way not cleared in accordance with
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Agree?
Question 3 Comment
company approved design standards will not be considered "active transmission line ROW". Any vegetation
contacts resulting from trees that fail in these non-cleared sections ("corridor edge zones") would not constitute a
violation of FAC-003-2.The definition of the "active transmission line right-of-way" states that this does not include
areas of the easement or fee-owned property that is unused or inactive and intended for other facilities. Does this
imply that areas not cleared and not intended for other facilities are part of the active right-of-way? If a company
had constructed new lines and allowed for a buffer strip of the easement that was not cleared, but is also not
intended for new facilities, and trees are allowed to remain in this strip - that an outage from contact with a tree
falling into the lines from this buffer would constitute a violation of R7 as a tree falling from within the active rightof-way? Does this imply that trees in these buffer strips must be removed? This will constitute a very costly and
problematic position that will result in extreme adverse public opposition to the required clearing. It is suggested
that the clearing limits of any right-way comply with some established standards or codes. A utility should not be
allowed to eliminate a large number of vegetation violations by simply decreasing the size or width of the active
right-of-way. However, this may also need to be flexible when new lines are constructed when easement widths
are limited due to local or state requirements.
Response: Thank you for your comments. The definition of “Active Transmission Line Right-of-Way” has been modified in the current draft of the
Standard. The SDT believes that the definition of “Active Transmission Line Right-of-Way” as currently defined is appropriate. The definition was
developed to recognize that in some cases additional ROW width was secured to allow for buffers and future expansion. This is further described in the
technical reference document. The new section in the technical reference attempts to address these issues.
Buckeye Power, Inc.
Agree
OK with R1. However, the active transmission line right of way seems to be a reduction in ROW width which
would likely decrease reliability during the one moment when we need it most.
Response: Thank you for your comment. The “active transmission line right-of-way” definition has been developed to address rights-of-way obtained
for future facilities. It is not intended to diminish the Transmission Owners’ responsibility to manage vegetation on a right-of-way which was acquired
solely for the purpose of the subject line and is necessary for the reliable operation of the line.
Great River Energy
Agree
GRE agrees but requests further clarification on the definition of the term "Active" in Active Transmission Line
R.O.W. For example: A utility has a 150 foot easement for a 230kV line and currently manages 80 feet. First; is it
the intent of the standard that the utility manage the entire 150 foot easement? Second; is the entire easement
considered the Active Transmission Line R.O.W?
Response: Thank you for your comment. The Transmission Owner is responsible for determining the Active ROW width based upon the definition of
“active transmission line right-of-way” included in the Standard. The scenario presented in your comment does not provide enough information for the
SDT to provide a definitive answer. The definition of “Active Transmission Line Right-of-Way” has been changed in the most current draft. In addition a
technical reference document with a more detailed explanation of this topic will be issued with the next draft. These documents should provide clarity.
September 8, 2009
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Organization
BCTC
Agree?
Agree
Question 3 Comment
Yes, we agree, subject to the qualification about “active” rights-of-way under Comment #16.
We would also like to point out that the original intent of the standard was to ensure that utilities had a complete
vegetation management program. The new standard is evolving towards an outage control program, and no
longer encourages programs or behaviours that would ensure the causes of outages are prevented long before
they become a problem. Instead, it redirects efforts to avoiding outages instead of managing vegetation. If this is
now the preferred approach, the term Transmission Vegetation Management Program is no longer valid and
should perhaps be changed to the Transmission Vegetation Outage Prevention Program.
Under R1.1, it says “Specify the methodologies that the Transmission Owner uses to control vegetation.” The
single word “methodologies” does not adequately replace “objectives, practices, approved procedures, and work
specifications.” BCTC recommends keeping the original wording.
Thank you for your comments. The SDT revised R1.1 to allow transmission owners the necessary flexibility in developing their Transmission Vegetation
Management Program. ANSI A300 has been referenced as a best management practice by reference as a footnote to R1.1. The SDT believes that the
latest draft includes Requirements that dictate appropriate behavior in controlling vegetation but also added a strong statement that outages, that could
have been prevented, are inconsistent with interconnection reliability and should be violations.
WECC Reliability Coordination
Agree
SERC Vegetation Management
Subcommittee (VMS)
Agree
Progress Energy Florida
Agree
Kansas City Power & Light
Agree
Agree
Western Area Power
Administration, Rocky Mountain
Region
Progress Energy Carolinas
Agree
SERC OC Standards Review
Group
Agree
September 8, 2009
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Florida Power & Light
Agree
Santee Cooper
Agree
Southern Company
Agree
E.ON U.S.
Agree
Midwest ISO Stakeholders
Standards Collaborators
Agree
SERC Compliance Staff
Agree
Exelon
Agree
Central Maine Power Company
Agree
City of Tallahassee
Agree
Northern California Power
Agency (NCPA)
Agree
Tampa Electric Company
Agree
Orange and Rockland Utilities
Inc.
Agree
Ameren
Agree
Nebraska Public Power District
Agree
Long Island power Authority
Agree
Manitoba Hydro
Agree
September 8, 2009
Question 3 Comment
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Organization
Agree?
Consumers Energy Company
Agree
Pacific Gas & Electric Co.
Agree
Edison Electric Institute
Agree
Consolidated Edison Company
of New York (CECONY)
Agree
WECC
Agree
Arizona Public Service
Company
Agree
Duke Energy Corporation
Agree
Entergy Services
Agree
Pepco Holdings, Inc
Agree
September 8, 2009
Question 3 Comment
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
4. Documentation and implementation of the transmission vegetation management program which were previously
combined in Requirement R1 are now separated in order to apply appropriate VRFs and time horizons. The
implementation of some elements has been moved into standalone requirements such as inspection cycles (R3) and
annual plan implementation (R9). Do you agree with these revisions and separation? If not, please explain.
Summary Consideration: Most respondents were in favor of separating the documentation from the implementation. A
minority of the respondents wanted to keep the two together. The SAR directed the team to bring the standard into
conformance with the latest version of the Sanctions Guidelines. Retention of documentation to demonstrate compliance is now
addressed, in most cases, solely in the “Data Retention” section of standards and does not need to be covered in requirements.
If an entity does not retain data and there is no impact to reliability, then the retention of that data, if needed to demonstrate
compliance, is covered under the Data Retention section.
Some respondents advocated modifying the order or sequence of the standard’s requirements. The SDT has considered various
sequence options and offers a re-sequencing proposal as Question #12 in the second Comment Form.
Organization
BCTC
Agree?
Question 4 Comment
Although it’s important to have these two separate aspects – documentation and implementation – separating
them spatially in the document itself makes the standard longer than necessary and creates redundancy. It
seems obvious that if you prepare elements of the Transmission Vegetation Management Program, they also
need to be implemented. The document would be easier to follow if the two elements were kept together.
Response: The SDT thanks you for your comments. The SDT determined that the requirements to document and implement are distinctly different
activities and therefore separated them. Having separate requirements allows for assignment of VRF’s and VSL’s that more closely reflect their
respective characteristics. The SDT has considered various sequence options and offers a re-sequencing proposal as Question #12 in the second
Comment Form.
Western Utility Arborists
Although it’s important to have these two separate aspects “documentation and implementation “separating
them spatially in the document itself makes the standard longer than necessary and creates redundancy. It
seems obvious that if you prepare elements of the Transmission Vegetation Management Program, they also
need to be implemented. The document would be easier to follow if the two elements were kept together.
Response: The SDT thanks you for your comments. The SDT determined that the requirements to document and implement are distinctly different
activities and therefore separated them. Having separate requirements allows for assignment of VRF’s and VSL’s that more closely reflect their
respective characteristics. The SDT have considered various sequence options and offer a re-sequencing proposal as Question #12 in the second
September 8, 2009
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Organization
Agree?
Question 4 Comment
Comment Form.
Progress Energy Florida
Disagree
The sub-requirements should be moved up to requirement level if the team desires to have different VRFs and
VSLs.
Response: The SDT thanks you for your comments. The Standards drafting team has dropped the sub requirement designations and the sub parts are
simply listed as part of R1.
Progress Energy Carolinas
Disagree
The sub-requirements should be moved up to requirement level if the team desires to have different VRFs and
VSLs.
Response: The SDT thanks you for your comments. The Standards drafting team has dropped the sub requirement designations and the sub parts are
simply listed as part of R1.
Southern California Edison
Company
Disagree
Q4: SCE does not agree with separating the documentation and implementation aspects of the Transmission
Vegetation Management Program into separate requirements R3 and R9 (respectively). SCE believes that
proposed R3 and corresponding M3 should be eliminated and replaced with a modified version of proposed
R9. SCE respectfully suggests that proposed R9 be revised to read: "Each Transmission Owner shall
implement and follow its Vegetation Management Program to the extent allowed by existing easement and/or
legal rights."
Response: The SDT thanks you for your comments. The team believes that conducting inspections is independently important and therefore should be
addressed in a separate requirement. The SDT debated the issue of whether to include "Each Transmission Owner shall implement and follow its
Vegetation Management Program to the extent allowed by existing easement and/or legal rights". The final consensus of the SDT was to exclude the
requirement because having the legal rights do not imply one is obligated to exercise those rights to their fullest extent. The SDT did not want to give
that impression.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Disagree
Although it’s important to have these two separate aspects “ documentation and implementation “ separating
them spatially in the document itself makes the standard longer than necessary and creates redundancy. It
seems obvious that if you prepare elements of the Transmission Vegetation Management Program, they also
need to be implemented. The document would be easier to follow if the two elements were kept together.
Response: The SDT thanks you for your comments. The SDT determined that the requirements to document and implement are distinctly different
activities and therefore separated them. Having separate requirements allows for assignment of VRF’s and VSL’s that more closely reflect their
respective characteristics. The SDT have considered various sequence options and offer a re-sequencing proposal as Question #12 in the second
Comment Form.
September 8, 2009
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
San Diego Gas & Electric
Agree?
Disagree
Question 4 Comment
The document would be easier to follow if kept together. Separation of the recommendations and
implementation will make this a redundant process, because both will say the same thing.
Response: The SDT thanks you for your comments. The SDT determined that the requirements to document and implement are distinctly different
activities and therefore separated them. Having separate requirements allows for assignment of VRF’s and VSL’s that more closely reflect their
respective characteristics. The SDT considered other sequence options and offer a re-sequencing proposal as Question #12 in the second Comment
Form.
JEA
Disagree
See comment from #3.
Response: The SDT thanks you for your comments. See response to Q #3.
Salt River Project
Disagree
Although we agree that it is important to identify both aspects of the program for "prepare/documentation" and
"implementation", we do not agree that this needs to be documented in separate requirements. It makes the
standard longer than necessary and creates redundancy. The document would be easier to follow if the two
elements were kept together in the same requirement. In addition, it is not defined what is "VRFs". We
understand that this was detailed in a previous draft document as "Violation Risk Factor". This needs to be
defined and clarified in order to provide comment back.
Response: The SDT thanks you for your comments. The SDT determined that the requirements to document and implement are separate and require
different levels of VRF’s and VSL’s. The team refers you to the Sanction Guidelines of North American Electric Reliability Corporation to explain the
use of VRF’s and VSL’s.
CenterPoint Energy
Disagree
Additional revisions are needed to clarify the requirements. For instance, R1.3 refers to "the objectives" of the
Transmission Vegetation Management Program, which are no longer a required element and are not specified
in M1.3. Reference to "the objectives" should be deleted. The last sentence of R1.3 should read: "It shall use
the methodologies outlined in the transmission vegetation management program."R1.4 requires a process for
a response to an "imminent threat of a vegetation related Sustained Outage", but R2 refers to implementing an
"imminent threat procedure" to "prevent an encroachment of the Critical Clearance Zone". The requirement
and the implementation should both refer to an "imminent threat of a vegetation related Sustained Outage".
Response: The SDT thanks you for your comments. The team is posting a revised standard and R1 identifies the required elements of the
Transmission Vegetation Management Program. The sub requirements have been changed to elements that roll up into R1 and an additional element
has been added to cover methods used to control vegetation – the word, “objectives” is not used in the revised standard.
MRO NERC Standards Review
September 8, 2009
Agree
The MRO believes that clarity was improved by separating documentation and implementation. The MRO
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Subcommittee
Question 4 Comment
suggests that moving the requirement for implementation so that it immediately follows the requirement for
documentation will further enhance clarity.
Response: The SDT thanks you for your comments. The SDT has considered various sequence options and offers a re-sequencing proposal as
Question #12 in the second Comment Form.
Midwest ISO Stakeholders
Standards Collaborators
Agree
This is a good change from a compliance perspective; the documentation requirements can now be assigned
lower VRFs than the implementation requirements.
Response: The SDT thanks you for your comments.
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 4
Response: The SDT thanks you for your comments.
Exelon
Agree
Refer to footnotes in R1.1 and 1.2. Are applicable entities to be held accountable to ANSI A300 (footnote 2)
and for providing documentation to support analysis that "local factors" were accounted for (footnote 3)?
These footnotes should be requirements or they should be removed and included in a Reference Document
not subject to compliance audit.
Response: The SDT thanks you for your comments. Please note the phrase in the current version of footnote 2,” while not a requirement of this
standard.” A300 is a recommended best practice and not a requirement. Footnotes may be used to provide explanatory information.
American Electric Power (AEP)
Agree
AEP agrees with these changes from Version 1.
Response: The SDT thanks you for your comments.
Platte River Power Authority
Agree
The separation allows lower sanctions and penalties to be assessed for weak documentation and higher
sanctions and penalties to be assessed for weak inspection programs and weak vegetation management.
However, the standard would be easier to follow if the two elements were kept together in the document.
Response: The SDT thanks you for your comments. The SDT determined that the requirements to document and implement are separate and require
different levels of VRF’s and VSL’s. The SDT has considered various sequence options and offers a re-sequencing proposal as Question #12 in the
second Comment Form.
City of Tallahassee
September 8, 2009
Agree
See Question 6 and 17.
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 4 Comment
Response: The SDT thanks you for your comments. See the responses to Questions 6 and 17.
Northern Indiana Public Service
Company
Agree
I agree with the separation and re-ordering of documentation and implementation requirements into two
distinct groups. This is a welcome improvement to the standard.
Response: The SDT thanks you for your comments. The SDT has considered various sequence options and offers a re-sequencing proposal as
Question #12 in the second Comment Form.
National Grid
Agree
These revisions and separation make it easier to match requirements and measures.
Response: The SDT thanks you for your comments.
Ameren
Agree
This is a good change from a compliance perspective; the documentation requirements can now be assigned
lower VRFs than the implementation requirements
Response: The SDT thanks you for your comments.
Duke Energy Corporation
Agree
This is a good change from a compliance perspective; the documentation requirements can now be assigned
lower VRFs than the implementation requirements.
Response: The SDT thanks you for your comments
Great River Energy
Agree
GRE believes that clarity was improved by separating documentation and implementation. GRE suggests that
moving the requirement for implementation so that it immediately follows the requirement for documentation
will further enhance clarity
Response: The SDT thanks you for your comments. The SDT has considered various sequence options and offers a re-sequencing proposal as
Question #12 in the second Comment Form.
Associated Electric Cooperative
Inc.
Agree
NPCC
Agree
WECC Reliability Coordination
Agree
September 8, 2009
55
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Western Area Power
Administration, Upper Great
Plains Region
Agree
SERC Vegetation Management
Subcommittee (VMS)
Agree
Kansas City Power & Light
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
SERC OC Standards Review
Group
Agree
Florida Power & Light
Agree
Santee Cooper
Agree
Southern Company
Agree
E.ON U.S.
Agree
Bonneville Power Administration
Agree
FirstEnergy
Agree
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
Central Maine Power Company
Agree
Northern California Power Agency
Agree
September 8, 2009
Question 4 Comment
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 4 Comment
(NCPA)
Tampa Electric Company
Agree
Orange and Rockland Utilities Inc.
Agree
American Transmission Company
Agree
Nebraska Public Power District
Agree
Long Island power Authority
Agree
USDA Forest Service,
Southwestern Region, Regional
Office for AZ and NM
Agree
Manitoba Hydro
Agree
Consumers Energy Company
Agree
Pacific Gas & Electric Co.
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
Consolidated Edison Company of
New York (CECONY)
Agree
WECC
Agree
Arizona Public Service Company
Agree
Baltimore Gas & Electric
Company
Agree
September 8, 2009
57
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Entergy Services
Agree
Pepco Holdings, Inc
Agree
Independent Electricity System
Operator
Agree
Northeast Utilities
Agree
Hydro-Quebec Transenergie
(HQT)
Agree
Buckeye Power, Inc.
Agree
September 8, 2009
Question 4 Comment
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
5. In R1.2 the Transmission Owner is required to have an inspection frequency of at least once per calendar year. Do you
agree with R1.2? If not, please explain.
Summary Consideration: The majority of the respondents were in favor of the one year frequency. Most of the minority
commenters wanted to leave the decision with the Transmission Owner. Since vegetation inspections can be included in
overhead maintenance inspections, the SDT did not consider the annual inspection requirement to be burdensome. Several
commenters asked for a definition of “inspection” and the SDT is proposing the following modification to an existing NERC
Glossary definition of “Vegetation Inspection:”
Vegetation Inspection: The systematic examination of vegetation conditions on an Active Transmission Line Right of Way.
This inspection may be combined with a general line inspection. The inspection includes the documentation of any vegetation
that may pose a threat to reliability prior to the next planned inspection or maintenance work, considering the current location
of the conductor and other possible locations of the conductor due to sag and sway for rated conditions.
Organization
BCTC
Agree?
Question 5 Comment
Clarification is required on exactly what an inspection is, which should perhaps be outlined in the white paper. At
BCTC although all lines are currently inspected at least once every year the thoroughness of the inspection will vary
with the local conditions. Some areas with limited vegetation management issues only require a patrol from the air
and are often inspected as part of a routine line patrol, where the lineman looks for vegetation concerns in addition to
undertaking maintenance work. Other areas require a detailed ground inspection. BCTC needs some assurance that
this inspection will not constitute a dedicated, comprehensive vegetation management inspection of the entire
operating system. . Therefore, BCTC needs the ability within the Transmission Vegetation Management Program to
define what an inspection is in the context of our utility operations.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections. The SDT
revised the NERC glossary term Vegetation Inspection to allow it to be combined with other line inspections.
Western Utility Arborists
September 8, 2009
Clarification is required on exactly what an inspection is, which should perhaps be outlined in the white paper. There
are areas where inspections are not necessary at all, such as lines over a parking lot, or in a remote desert area. The
Western Utilities need some assurance that this inspection will not constitute a dedicated, comprehensive vegetation
management inspection. Inspections are currently often part of a routine line patrol, where the lineman looks for
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 5 Comment
vegetation concerns in addition to undertaking maintenance work. Therefore, the Transmission Owner needs the
ability within their Transmission Vegetation Management Program to define what an inspection is in the context of
their utility operations.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections. The SDT
revised the NERC glossary term Vegetation Inspection to allow it to be combined with other line inspections.
Associated Electric
Cooperative Inc.
Disagree
While Associated Electric Cooperative Inc agrees with this requirement in general, there may be areas (e.g. highly
arid terrain, open water, etc.) where an annual interval is unnecessary and adds little or nothing to reliability.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
NPCC
Disagree
There were differing opinions within the group. Those entities with extensive overhead transmission felt the once a
year requirement was overly prescriptive and would not improve reliability, others were in agreement with the "at least
once per calendar year" requirement.
Response: The SDT thanks you for your comments. The consensus of the SDT is that annual inspections add to the reliability of the system.
Tennessee Valley Authority
Disagree
TVA suggests that R1.2 be changed by adding "except in cases where lines or significant sections of lines are over
terrain which is void of vegetation(such as bodies of deep water)or over terrain void of any vegetation that can grow
to a mature height that could threaten the conductors, then longer cycles will be acceptable". This would avoid
unnecessary expenses in such cases.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
Western Area Power
Administration, Rocky
Mountain Region
Disagree
Some areas such as highly developed urban areas, deserts, or grassland prairie may not be conducive to tall
vegetation growth and require frequent (annual) inspection.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
September 8, 2009
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Organization
Southern California Edison
Company
Agree?
Disagree
Question 5 Comment
Q5: SCE does not agree with imposing a one-size-fits-all inspection frequency of ?at least once per calendar year?
upon all U.S. Transmission Owners. The associated technical paper presents no credible evidence or statistical
corroboration to support the proposed inspection frequency. Until such time as a thorough industry study or similar
evidence is presented that demonstrates the proposed inspection frequency is cost effective and will enhance system
reliability, Transmission Owners should be allowed to establish their own inspection frequency rate. Regarding the
enforcement of a non-standardized inspection frequency, should a Transmission Owner incur a vegetation-to-line
contact that results in a Sustained Outage, upon review of the investigation results, the responsible Reliability
Coordinator and/or NERC could then impose a more stringent inspection frequency requirement upon the infracting
Transmission Owner. The imposition of more stringent inspection frequencies could be applied on a temporary or
permanent basis, depending on the severity of the outage, but lacking a demonstrated need, good performing
Transmission Owners should be allowed to establish their own inspection frequencies based upon their individual
needs and operating conditions. SCE respectfully suggests R1.2 be revised to read: "Specify a vegetation inspection
frequency that takes into account local and environmental factors."
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
SERC OC Standards Review
Group
Disagree
While the SERC OCSRG agrees with this requirement in general, there may be areas (e.g., desert terrain) where an
annual interval would be unnecessary and not cost effective.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
City of Tallahassee
Disagree
While TAL's specific conditions and current process would meet this requirement, I can envision where some
conditions may not require an annual inspection. These might include desert conditions, crop fields, over water, etc.
To dictate a specific one-year requirement could be burdensome to some utilities with no improvement to the
reliability of the BES.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
Xcel Energy
Disagree
Add a note of exception to the requirement for inspections on those lines that do not have vegetation management
issues (e.g. lines that traverse desert areas only).
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
September 8, 2009
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Organization
Agree?
Question 5 Comment
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
Disagree
USDA Forest Service,
Southwestern Region,
Regional Office for AZ and NM
It would seem also that the T.O. should be expected to react to circumstances that create the need for a more
frequent inspection cycle such as conditions that cause widespread vegetation mortality such as drought and/or
beetle infestations.
Response: The SDT thanks you for your comments. The standard does restrict the number of inspections and does require the Transmission Owner to
examine the local and environmental conditions that might require a greater frequency.
Consumers Energy Company
Disagree
FERC required NERC in Order 693 to develop appropriate inspection cycles based on local factors. Potential annual
tree growth varies considerably within the geography of the United States and FAC-003-1 recognized this factor and
left it up to the utility to determine the most appropriate inspection cycle for their system. This was in lieu of having
proper data readily available to determine inspection cycles for various areas that could be incorporated into the
standard. FAC-003-2 greatly decreases the minimum separation distance between conductors and vegetation.
Table 1 shows the minimum distance at sea level for a 345 kV line a 3.12 feet. This is considerably less than the
potential annual growth rate of many tree species in many areas of the United States. Therefore, the annual
inspection cycle would not be acceptable to identify tree growth that can violate the minimum distance before it
occurs. Consumers Energy strongly believes that using the Gallet formula to determine the minimum clearance
between conductors and vegetation will decrease the reliability of the system compared to the minimum clearance
requirements in FAC-003-1.
Response: The SDT thanks you for your comments. The consensus of the SDT is that the frequency of inspection does not drive the minimum clearance
the Transmission Owner operates from. The SDT would expect the minimum clearance to be driven by growth rate and maintenance frequency.
National Grid
Disagree
R1.2, M1.2 and M1.3 in the Standard all refer to calendar year. National Grid objects to inspections being based on a
calendar year. Transmission Owners should be able to define their own "year". (See Question No. 18.)
Response: The SDT thanks you for your comments. By using “once per calendar year” the standard does not confine the inspection to a specific date.
This improves flexibility in the inspection schedule.
Hydro One Networks Inc.
September 8, 2009
Disagree
Clarification is required on the requirements. The frequency and need for inspection is based on a number of factors
that include: type of vegetation on a right of way, change in growing conditions and the Transmission Owner’s
clearance standards (i.e., if the clearance standards are well above the Critical Clearance then the risk to reliability
may be very low, so why inspect for vegetation clearances on an annual basis?) This being the case, clarification is
needed on inspection requirements relative to the overall approach used to manage vegetation clearances. For
example, Hydro One conducts routine line inspections on an annual basis and identifies clearance issues. Would this
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Organization
Agree?
Question 5 Comment
meet the requirements of the standard?
Response: The SDT thanks you for your comments. Yes. The SDT added a definition for Vegetation Inspection to the standard.
NV Energy (fka Sierra Pacific / Disagree
Nevada Power Co.)
Clarification is required on exactly what an inspection is, which should perhaps be outlined in the white paper. There
are areas where inspections are not necessary at all, such as lines over a parking lot, or in a remote desert area. We
need some assurance that this inspection will not constitute a dedicated, comprehensive vegetation management
inspection. Inspections are currently often part of a routine line patrol, where the lineman looks for vegetation
concerns in addition to undertaking maintenance work. Therefore, the Transmission Owner needs the ability within
their Transmission Vegetation Management Program to define what an inspection is in the context of their utility
operations.
Response: The SDT thanks you for your comments. The SDT added a definition for Vegetation Inspection to the standard.
CenterPoint Energy
Disagree
The Standard and the Technical Reference provide no specific justification for defining a 1-year inspection frequency
and is arbitrary. The requirement itself does not take into account "local and environmental factors". Since the type
of inspection is not specified within the Standard, a frequency of at least once per calendar year is currently workable
for CenterPoint Energy, but it may not necessarily be appropriate for Transmission Owners with sparsely vegetated
service territories. The Technical Reference for R1.2 should state, "the Transmission Owner is given discretion as to
the inspection method", and "that while the inspection frequency is specified, it is not the intent of the Standard that all
vegetation be maintained on the same frequency". For example, CenterPoint Energy currently utilizes a 5-year
ground-based inspection cycle coupled with a 5-year cycle for vegetation maintenance, and performs a supplemental
annual aerial inspection.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations and this is explained in the Technical Reference. Vegetation inspections can be included in
overhead maintenance inspections. The SDT added a definition for Vegetation Inspection to the standard which would work provided you do your annual
flight.
Alberta Electric System
Operator
Disagree
The AESO believes that the inspection schedule should consider local and environmental factors that may impact the
anticipated growth rate of vegetation. In many of the areas in Alberta, due to cold climate and arid conditions, we
have slow vegetation growth rates. The requirement for minimum annual inspection is not necessary. We recommend
the inspection schedule be determined by the Transmission Owner and documented in its vegetation management
plan.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done at
September 8, 2009
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Organization
Agree?
Question 5 Comment
least annually to cover both engineering and vegetation situations. A more frequent cycle may specified by the Transmission Owner to account for local
conditions. Slow growth rates, arid conditions etc. which may render an annual frequency unnecessary for Vegetation Inspections can be included in
overhead maintenance inspections.
Pepco Holdings, Inc
Disagree
While an annual inspection is reasonable and appropriate for all but very low precipitation areas, In Order 693, the
Commission directs the ERO to develop compliance audit procedures, using relevant industry experts, which would
identify appropriate inspection cycles based on local factors. The SDT does not seem to have taken the local factors
into account. FERC also does not want to leave this up to the Transmission Owners. While the standards being
developed are moving many things to the RC, PHI sees that as the only way to have someone other than the
Transmission Owner determine an inspection cycle that would consider local factors.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done at
least annually to cover both engineering and vegetation situations. A more frequent cycle may specified by the Transmission Owner to account for local
conditions. Slow growth rates, arid conditions etc. which may render an annual frequency unnecessary for Vegetation Inspections can be included in
overhead maintenance inspections.
Hydro-Quebec Transenergie
(HQT)
Disagree
The frequency and need for inspection is based on a number of factors that include: type of vegetation on a right of
way, rainfall during any given year, climate (very slow growth in nordic area), when the last removal of vegetation was
done, etc. HQT believes R1.2 is overly prescriptive when a “at least once a year” becomes mandatory; these terms
should be removed from the Standard.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done at
least annually to cover both engineering and vegetation situations. A more frequent cycle may specified by the Transmission Owner to account for local
conditions. Slow growth rates, arid conditions etc. which may render an annual frequency unnecessary for Vegetation Inspections can be included in
overhead maintenance inspections.
Bonneville Power
Administration
Agree
It would be helpful to clarify what is expected in regards to what constitutes an inspection. This could be done in the
technical reference. Some Transmission Operators inspect vegetation as part of line patrol that focuses on more
than just the condition of vegetation along the Right of Way. It should be clear that the Transmission Owner, though
required to complete a inspection frequency of at least once per calendar year, has the ability to implement the type
of inspection it deems necessary. Also the frequency of once per calendar year may create some unintended
reporting difficulties if Transmission Owners currently track progress and completion of inspections using a different
convention than calendar year, e.g., fiscal year or other period. It may be helpful to change the wording of R1.2 from
"at least once per calendar year" to "once in a twelve month period."
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
September 8, 2009
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Organization
Agree?
Question 5 Comment
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
MRO NERC Standards
Review Subcommittee
Agree
The MRO suggests rewording the requirement to remove ". and environmental" . The MRO believes that local factors
includes environmental.
Response: The SDT thanks you for your comments. The SDT considers local conditions to account for design and operating situation and
environmental includes both the normal expected environmental conditions and changes from the norm such as drought major storms, fire etc.
SERC Vegetation
Management Subcommittee
(VMS)
Agree
While the SERC VMS agrees in general, there may be areas (i.e. desert terrain) where an annual interval would be
unnecessary and not cost effective.
Response: The SDT thanks you for your comments. The consensus of the SDT is that annual inspections add to the reliability of the system.
American Electric Power
(AEP)
Agree
AEP agrees with this change.
Response: The SDT thanks you for your comments.
Platte River Power Authority
Agree
The inspection frequency is reasonable.
Response: The SDT thanks you for your comments.
American Transmission
Company
Agree
We agree with a minimum inspection frequency, but believe that the additional verbiage "? that takes into account
local and environmental factors" should be deleted. The additional verbiage does not provide greater reliability only
more documentation. Proposed Language: Specify a vegetation inspection frequency of at least once per calendar
year.
Response: The SDT thanks you for your comments. The consensus of the SDT is that local and environmental factors might demand a greater frequency
than once per calendar year and vegetation inspections can be included in overhead maintenance.
Arizona Public Service
Company
September 8, 2009
Agree
Clarification is required on exactly what an inspection is, which should perhaps be outlined in the white paper. There
are areas where inspections are not necessary at all, such as lines over a parking lot, or in a remote desert area. APS
needs some assurance that this inspection will not constitute a dedicated, comprehensive vegetation management
inspection. Inspections are currently often part of a routine line patrol, where the forester or lineman looks for
vegetation concerns in addition to undertaking maintenance work. Therefore, the Transmission Owner needs the
65
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Organization
Agree?
Question 5 Comment
ability within their Transmission Vegetation Management Program to define what an inspection is in the context of
their utility operations.
Response: The SDT thanks you for your comments. The SDT added a definition for Vegetation Inspection to the standard.
Pacific Gas & Electric Co.
Agree
This requirement is appropriate to ensure adequate inspection frequencies, however, a clear definition of "inspection"
should be contained in either the standard or white paper.
Response: The SDT thanks you for your comments. The SDT added a definition for Vegetation Inspection to the standard.
JEA
Agree
Although there are probably few areas where this is appropriate, the entity should be able to reduce the required
number of inspections with RC approval if they are able to demonstrate that vegetation conditions surrounding
transmission lines does not warrant inspections at that frequency.
Response: The SDT thanks you for your comments. The consensus of the SDT is that inspection of any operating transmission line should be done
annually to cover both engineering and vegetation situations. Vegetation inspections can be included in overhead maintenance inspections.
Salt River Project
Agree
The Transmission owner needs the ability to define what an inspection is in the context of their utility operation.
Inspections may not constitute a dedicated, comprehensive vegetation management inspection, but could often be
part of a routine line patrol, where linemen or engineers look for vegetation concerns in addition to undertaking
maintenance work. Clarification of that would be helpful, suggest that could be documented in the Technical
Reference document.
Response: The SDT thanks you for your comments. The SDT added a definition for Vegetation Inspection to the standard.
Great River Energy
Agree
GRE suggests rewording the requirement to remove ". and environmental" . GRE believes that local factors takes into
account environmental.
Response: The SDT thanks you for your comments. The SDT considers local conditions to account for design and operating situation and
environmental includes both the normal expected environmental conditions and changes from the norm such as drought major storms, fire etc.
San Diego Gas & Electric
September 8, 2009
Agree
The term "inspection" needs to be better defined, as well as the term "calendar year."
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Organization
Agree?
Progress Energy Carolinas
Agree
Florida Power & Light
Agree
Santee Cooper
Agree
Southern Company
Agree
Question 5 Comment
WECC Reliability Coordination Agree
Western Area Power
Administration, Upper Great
Plains Region
Agree
Progress Energy Florida
Agree
Kansas City Power & Light
Agree
E.ON U.S.
Agree
FirstEnergy
Agree
Midwest ISO Stakeholders
Standards Collaborators
Agree
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
Exelon
Agree
Central Maine Power
Company
Agree
September 8, 2009
67
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Organization
Agree?
Northern California Power
Agency (NCPA)
Agree
Northern Indiana Public
Service Company
Agree
Tampa Electric Company
Agree
Orange and Rockland Utilities
Inc.
Agree
Ameren
Agree
Nebraska Public Power
District
Agree
Long Island power Authority
Agree
Manitoba Hydro
Agree
Edison Electric Institute
Agree
Consolidated Edison
Company of New York
(CECONY)
Agree
WECC
Agree
Baltimore Gas & Electric
Company
Agree
Duke Energy Corporation
Agree
Entergy Services
Agree
September 8, 2009
Question 5 Comment
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Organization
Agree?
Independent Electricity
System Operator
Agree
Northeast Utilities
Agree
Buckeye Power, Inc.
Agree
September 8, 2009
Question 5 Comment
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
6. In R1.3 the Standard requires that transmission vegetation management program specify an Annual Plan and
specifies parameters for the plan. Implementation of the Annual Plan is separated and placed in R9. Do you agree
with R1.3 and the separation of the implementation from the specification of the Annual Plan? If not, please explain.
Summary Consideration: The majority of the respondents are in favor of the changes. There was a minority of the
respondents that made a valid point that elements in the annual plan were lost in the posting. The SDT determined that the
requirement to document and implement are separate and require different levels of VRF’s and VSL’s. The SDT chose a
compromise wording to accommodate those points.
Organization
BCTC
Agree?
Question 6 Comment
The document would benefit from keeping the two requirements together, since they relate to the same topic.
Under the new wording in R1, the Transmission Vegetation Management Program no longer has a requirement to
include objectives. However, there is a phrase in R1.3 to “support the objectives…and methodologies…outlined in
the…program.” To be consistent with R1.3, BCTC recommends that R1.1 be reworded to specify the
methodologies and objectives that the Transmission Owner uses to control vegetation.
Response: The SDT thanks you for your comments. However, the SDT determined that the requirements to document and implement should be
separate and require different levels of Violation Risk Factors and Violation Severity Levels. Thus, the SDT respectfully does not adopt your
suggestion to keep the two requirements together. The SDT also disagrees with returning “objectives” to R1. We do, however, agree that there exists
a small dichotomy since “objectives” are no longer stated in R1 while being referenced in part 1.3. Subsequently the SDT has removed this wording
from part 1.3. Further, the SDT has revised R1 to require the Transmission Owner to specifically describe how it will conduct work to comply with the
Standard in lieu of requiring the Transmission Owner to only identify general objectives.
Western Utility Arborists
The document would benefit from keeping the two requirements together, since they relate to the same topic.
Under the new wording in R1, the Transmission Vegetation Management Program no longer has a requirement to
include objectives. However, there is a phrase in R1.3 to “support the objectives” and methodologies “outlined in
the “program.” To be consistent with R1.3, the Western Utilities recommends that R1.1 be reworded to specify the
methodologies and objectives that the Transmission Owner uses to control vegetation.
Response: The SDT thanks you for your comments. However, the SDT determined that the requirements to document and implement should be
separate and require different levels of Violation Risk Factors and Violation Severity Levels. Thus, the SDT respectfully does not adopt your
suggestion to keep the two requirements together. The SDT also disagrees with returning “objectives” to R1. We do, however, agree that there exists
a small dichotomy since “objectives” are no longer stated in R1 while being referenced in part 1.3. Subsequently the SDT has removed this wording
from part 1.3. Further, the SDT has revised R1 to require the Transmission Owner to specifically describe how it will conduct work to comply with the
September 8, 2009
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 6 Comment
Standard in lieu of requiring the Transmission Owner to only identify general objectives.
NPCC
Disagree
R1.2 and R1.3 should specifically state calendar year, and the Annual Plan and inspection follow the same
calendar year timing.
Response: The SDT thanks you for your comments. The SDT points out that these two parts, R1.2 and R1.3, refer to different aspects of the
Transmission Vegetation Management Program. Further, to assist in clarity, the SDT has revised part 1.3 and in doing so has removed the phrase
“during the year” since it added no value to the requirement. The SDT does not agree with your suggestion to base the annual plan on a calendar year
and feels that the Transmission Owner should retain the flexibility to determine the time period for - Requirement R1 clearly limits the scope of the
TVMP to work on the entity's Active Transmission Line Rights of Way - and the "annual work plan" is one element of the overall TVMP annual plan.
City of Tallahassee
Disagree
While I can agree with a separate requirement (R9) to implement the plan developed in R1.3, they need to both
have the flexibility desired in R1.3. I do not see that flexibility in R9. See response to question 17.
Response: The SDT thanks you for your comments. R9 is the implementation of 1.3 which is flexible. The flexibility of 1.3 carries through to R9.
Northern Indiana Public
Service Company
Disagree
I disagree with the elimination of the present requirement R2 (last sentence) that requires a Transmission Owner to
have proper quality control (QC) systems and procedures in place to document & track planned UVM work so as to
verify it was completed properly to work specifications. The need for this requirement was demonstrated as
recently as last year when a grow-in outage occurred at BG&E due to a contractor trimming the wrong tree at the
wrong location, a situation that could have been prevented with effective QC.
Response: The SDT thanks you for your comments. The consensus of the SDT is that in order to implement the plan the Transmission Owner must
complete its work plan to its standards. The level of QC is within the Transmission Owner’s purview.
USDA Forest Service,
Disagree
Southwestern Region,
Regional Office for AZ and NM
I think that the Transmission Owner should be able to specify the effective period of the plan whether it is one year
or ten years. Arizona utilities are starting to think in terms of multi-year corridor management plans. A one year
planning period could be specified as the minimum planning period.
Response: The SDT thanks you for your comments. The SDT agrees that long term plans can be of value and can be done within the standard. The
standard is trying to insure the immediate reliability work is budgeted and completed.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
September 8, 2009
Disagree
The document would benefit from keeping the two requirements together, since they relate to the same topic.
Under the new wording in R1, the Transmission Vegetation Management Program no longer has a requirement to
include objectives. However, there is a phrase in R1.3 to “support the objectives” and methodologies” outlined in
the “program.” To be consistent with R1.3, we recommend that R1.1 be reworded to specify the methodologies and
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Organization
Agree?
Question 6 Comment
objectives that the Transmission Owner uses to control vegetation.
Response: The SDT thanks you for your comments. However, the SDT determined that the requirements to document and implement should be
separate and require different levels of Violation Risk Factors and Violation Severity Levels. Thus, the SDT respectfully does not adopt your
suggestion to keep the two requirements together. The SDT also disagrees with returning “objectives” to R1. We do, however, agree that there exists
a small dichotomy since “objectives” are no longer stated in R1 while being referenced in part 1.3. Subsequently the SDT has removed this wording
from part 1.3. Further, the SDT has revised R1 to require the Transmission Owner to specifically describe how it will conduct work to comply with the
Standard in lieu of requiring the Transmission Owner to only identify general objectives.
Arizona Public Service
Company
Disagree
The document would benefit from keeping the two requirements together, since they relate to the same topic.
Under the new wording in R1, the Transmission Vegetation Management Program no longer has a requirement to
include objectives. However, there is a phrase in R1.3 to “support the objectives” and methodologies “outlined in
the “program.” To be consistent with R1.3, APS recommends that R1.1 be reworded to specify the methodologies
and objectives that the Transmission Owner uses to control vegetation.
Response: The SDT thanks you for your comments. However, the SDT determined that the requirements to document and implement should be
separate and require different levels of Violation Risk Factors and Violation Severity Levels. Thus, the SDT respectfully does not adopt your
suggestion to keep the two requirements together. The SDT also disagrees with returning “objectives” to R1. We do, however, agree that there exists
a small dichotomy since “objectives” are no longer stated in R1 while being referenced in part 1.3. Subsequently the SDT has removed this wording
from part 1.3. Further, the SDT has revised R1 to require the Transmission Owner to specifically describe how it will conduct work to comply with the
Standard in lieu of requiring the Transmission Owner to only identify general objectives.
Baltimore Gas & Electric
Company
Disagree
See response to question no. 17.
Response: The SDT thanks you for your comments. See response to comments on #17.
JEA
Disagree
See comment from #3.
Response: The SDT thanks you for your comments. See response to comments on #3.
Salt River Project
September 8, 2009
Disagree
The document would be easier to follow if the two elements were kept together in the same requirement (similar to
comments stated in Comment #4 above). It makes the standard longer than necessary and creates redundancy.
Also, under the new wording in R1, the Transmission Vegetation Management Program no longer has a
requirement to include objectives. However, there is a phrase in R1.3 to "support the objectives” and
methodologies “outlined in the..program". To be consistent with R1.3, it is recommended that R1.1 be reworded to
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 6 Comment
specify the methodologies and objectives that the Transmission Owner uses to control vegetation.
Response: The SDT thanks you for your comments. However, the SDT determined that the requirements to document and implement should be
separate and require different levels of Violation Risk Factors and Violation Severity Levels. Thus the SDT respectfully does not adopt your suggestion
to keep the two requirements together. The SDT also disagrees with returning “objectives” to R1. We do, however, agree that there is a small
dichotomy since “objectives” are no longer stated in R1, while being referenced in part 1.3. Subsequently, the SDT has removed this wording from
part 1.3 Further, the SDT has revised R1 to require the Transmission Owner to specifically describe how it will conduct work to comply with the
Standard in lieu of requiring the Transmission Owner to only identify general objectives.
Hydro-Quebec Transenergie
(HQT)
Disagree
R1.2 and R1.3 specify calendar year. The individual entities should define the 12 month period for their programs.
Response: The SDT thanks you for your comments. The annual work plan may be for a calendar year or for a fiscal year.
Western Area Power
Administration, Upper Great
Plains Region
Agree
The description of the annual plan now appears to require a detailed plan for each line. Under FAC-003-1,
Western (UGPR) identified higher priority vegetation during aerial inspection and handled those expediciously. We
then addressed a percentage of the lower priority trees based upon a number of agency defined factors (vegetation
priority, ground conditions, resource availability, etc). The less rigid annual plan allowed us the freedom to cut the
lower priority trees that made the best sense to cut. We are concerned that the additional rigidity will create a everchanging annual plan because we may have to adjust dozens of lines based on inspections. We question whether
it is prudent to occupy finite resources in continually modifying the annual plan when the real benefits accrue from
actually performing the vegetation management activities.
Response: The SDT thanks you for your comments. The SDT intent is for the Transmission Owner’s Transmission Vegetation Management Program to
be developed based on the unique requirements of each Transmission Owner’s system. For example, where the Transmission Owner has a heavily
forested or geographically large territory the annual plan may address many transmission lines on a cyclic basis along with additional items found on
the vegetation inspections. On the other hand, where the Transmission Owner has a very sparsely forested territory, or a small number of
transmission line miles, the Transmission Vegetation Management Program may necessitate an annual plan that only addresses items found on the
vegetation inspections. Therefore, the specificity of the annual plan is subject to the discretion of the Transmission Owner. We agree that only the
appropriate amount of resources should be applied to the execution and management of the annual plan, provided the overall Transmission Vegetation
Management Program is effective.
Progress Energy Florida
September 8, 2009
Agree
Annual Plan should be a defined term in the standard. Without a definition, the term may be interpreted differently
by industry and the regulator. The drafting team should raise the prominence of annual plan and define the
attributes of an annual plan.
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Organization
Agree?
Question 6 Comment
Response: The SDT thanks you for your comments. The SDT did attempt to address this concern by breaking the annual plan into 4 separate subrequirements. We feel this may help limit the range of subjective interpretations of this requirement.
Progress Energy Carolinas
Agree
Annual Plan should be a defined term in the standard. Without a definition, the term may be interpreted differently
by industry and the regulator. The drafting team should raise the prominence of annual plan and define the
attributes of an annual plan.
Response: The SDT thanks you for your comments. The SDT did attempt to address this concern by breaking the annual plan into 4 separate subrequirements. We feel this may help limit the range of subjective interpretations of this requirement.
Southern California Edison
Company
Agree
Q6: SCE agrees in part. Proposal R1.3, requiring Transmission Owners to establish an annual maintenance plan is
generally acceptable. However, SCE disagrees with including peripheral information in R1.3 and the institution of a
separate implementation requirement (R9). Further, we note that some portions of FAC-003-1 (R2) appear to have
been transplanted into proposed R1.3 and that the word “shall” has been replaced with the word “should”. SCE
believes that inserting the word “shall” into statements that are clearly advisory in nature does not necessarily
create enforceable requirements. As proposed, an enforcement auditor might incorrectly determine that the new
“requirement” statements in proposed R1.3, describing the need for “flexibility”, “consideration of permitting and
scheduling requirements”, and self-determined “methodologies” is a comprehensive list of items for the
maintenance plan. Because this list of program elements is not complete, SCE recommends all text following the
opening sentence be removed from R1.3 and inserted into the supporting technical paper. SCE respectfully
suggests that R1.3 be revised to read: "Specifies a plan that identifies the applicable lines to be maintained and
associated work to be performed."
Response: The SDT thanks you for your comments. The consensus of the SDT is the components of an annual work plan must be part of the
requirement to ensure that all plans are adequate. Major changes that could affect reliability must be made.
FirstEnergy
September 8, 2009
Agree
Although we agree with R1.3, we suggest it be broken up into subrequirements to allow for better clarity to the
reader as well as aid in the development of violation severity levels when developed. We suggest the
following:R1.3. Require an annual plan that includes the following as a minimum: (Note: Adjustments to the plan
within the year are permissible) R1.3.1. It shall identify the applicable lines to be maintained and associated work
to be performed during the year. R1.3.2. Is shall be flexible to adjust to changing conditions and to findings from
vegetation inspections. R1.3.3. It shall take into consideration permitting and scheduling requirements from
landowners or regulatory authorities. R1.3.4. It shall support the objectives of the transmission vegetation
management program and use the methodologies outlined in the transmission vegetation management program.
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Organization
Agree?
Question 6 Comment
Response: The SDT thanks you for your comments. Requirement R1.3 has been subdivided for clarity in proposed version 2.
MRO NERC Standards
Review Subcommittee
Agree
The MRO suggests removing the words "during the year" from sentence 1 and removing the words "within the
year" in sentence 3. The MRO believes that having it only within the plan year is too restrictive.
Response: The SDT thanks you for your comments. By definition an annual plan covers a one year period. This one year period, at the discretion of
the Transmission Owner, may or may not be constrained to a calendar year. However, in an effort to make the requirement more concise, the SDT did
remove the words “during the year” from the requirement but retained the words “within the year” in the requirement.
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 6 and proposes that the Annual Plan be a defined term.
Response: The SDT thanks you for your comments. The SDT did attempt to address this concern by breaking the annual plan into 4 separate subrequirements. We feel this may help limit the range of subjective interpretations of this requirement.
American Electric Power
(AEP)
Agree
AEP agrees with these changes.
Response: The SDT thanks you for your comments.
Platte River Power Authority
Agree
Under the new working in R1., the Transmission Vegetation Management Program no longer has a requirement to
include objectives. However, there is a phrase in R1.3. to "support the objectives.. and methodologies outlined in
the Transmission Vegetation Management Program". R1.3. should be consistent with the wording in R1.
Response: The SDT thanks you for your comments. The SDT has made changes to address this concern and the word, “objectives” is no longer used
in the revised standard.
American Transmission
Company
Agree
ATC agrees with separating the implementation Requirements from the Annual Plan Requirements.
Response: The SDT thanks you for your comments.
Manitoba Hydro
Agree
Agree with the separation - but suggest that the time horizon of one year be removed as some changes may push
the work beyond the current planning year.
Response: The SDT thanks you for your comments. By definition an annual plan covers a one year period. This one year period, at the discretion of
September 8, 2009
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Organization
Agree?
Question 6 Comment
the Transmission Owner, may or may not be constrained to a calendar year. If findings during the year from Vegetation Inspections justify changes to
the plan, such adjustments are allowed as long as they occur within the planning year, not after the fact.
San Diego Gas & Electric
Agree
To be consistent with R1.3, we recommend that R1.1 be reworded to specify the methodologies and objectives that
the Transmission Owner uses to control vegetation.
Response: The SDT thanks you for your comments. The SDT has made changes to address this concern.
CenterPoint Energy
Agree
See comments to Q4 above as well.
Response: The SDT thanks you for your comments. See response to comments on Q4.
Great River Energy
Agree
GRE suggests removing the words "during the year" from sentence 1 and removing the words "within the year" in
sentence 3. GRE believes that having it only within the plan year is too restrictive.
Response: The SDT thanks you for your comments. By definition an annual plan covers a one year period. This one year period, at the discretion of
the Transmission Owner, may or may not be constrained to a calendar year. However, in an effort to make the requirement more concise, the SDT did
remove the words “during the year” from the requirement but retained the words “within the year” in the requirement.
WECC Reliability Coordination Agree
Associated Electric
Cooperative Inc.
Agree
SERC Vegetation
Management Subcommittee
(VMS)
Agree
Kansas City Power & Light
Agree
Western Area Power
Administration, Rocky
Mountain Region
Agree
SERC OC Standards Review
Agree
September 8, 2009
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Organization
Agree?
Question 6 Comment
Group
Florida Power & Light
Agree
Santee Cooper
Agree
Southern Company
Agree
E.ON U.S.
Agree
Bonneville Power
Administration
Agree
Midwest ISO Stakeholders
Standards Collaborators
Agree
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
Exelon
Agree
Central Maine Power
Company
Agree
Northern California Power
Agency (NCPA)
Agree
Tampa Electric Company
Agree
Orange and Rockland Utilities
Inc.
Agree
Ameren
Agree
September 8, 2009
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Organization
Agree?
Nebraska Public Power
District
Agree
Long Island power Authority
Agree
Consumers Energy Company
Agree
National Grid
Agree
Pacific Gas & Electric Co.
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
Consolidated Edison
Company of New York
(CECONY)
Agree
WECC
Agree
Duke Energy Corporation
Agree
Entergy Services
Agree
Pepco Holdings, Inc
Agree
Northeast Utilities
Agree
Buckeye Power, Inc.
Agree
September 8, 2009
Question 6 Comment
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
7. In R1.4 the Standard requires the Transmission Owner to have an Imminent Threat Procedure and specifies elements
to be in that procedure. Do you agree with R1.4? If not, please explain.
Summary Consideration: Approximately half of the comments received were critical of the lack of a definition for imminent
threat. The SDT prefers to allow the verbiage “an imminent threat of a vegetation-related Sustained Outage” to stand without
further definition.
About the same number of commenters objected to the “prescriptive” list of other actions for the Transmission Operator, and
that language has been removed from R1.4.
R1.4
Require a process or procedure for response to imminent threats of a vegetation related Sustained Outage. The process or
procedure shall specify actions which shall include immediate communication of the threat to the responsible control center.
Commenters also expressed a desire to set the procedure for specific internal needs and the SDT modified the language to give
that latitude to the Transmission Owner when developing its Imminent Threat procedure.
Some comments referred to parts of the standard not asked about in this question and the SDT directed the commenters to
review the changes in R1, R2 and R4.
Organization
Associated Electric Cooperative
Inc.
Agree?
Disagree
Question 7 Comment
The language in R1.4, requiring notification of the Transmission Operator, is inconsistent with the Applicability in
Section A.4.1.1 which designates the Transmission Owner as the responsible entity.
Response: Thank you for your comment. The main purpose of requirement R1.4 is to enhance the responsible operator’s situational awareness of the
power system’s status. Therefore, the salient requirement of this procedure is notification of the responsible operator of any potential threat to the
power system. This requirement does not mandate any action of the responsible operator and thus, this entity would not need to be listed in the
Applicability section. Please also note that the wording in R1.4 has been altered to change the “Transmission Operator” to the “responsible control
center”, to better identify the appropriate responsible party.
NPCC
Disagree
September 8, 2009
While we strongly agree that an imminent threat procedure should be required in the Transmission Vegetation
Management Program, we disagree with some specific wording in R1.4. R1.4 requires immediate
communication of an imminent threat to the Transmission Operator, which we would normally agree with. R2
however requires that the imminent threat procedure be implemented when the Critical Clearance Zone (Critical
Clearance Zone ) is approached by vegetation. "Approached" is not defined as a specific distance, so this part
of the requirement is left up to the individual's interpretation. In cases where the Critical Clearance Zone is
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Deleted: Transmission Operator
Deleted: , and may include actions such
as a temporary reduction in line Rating,
switching lines out of service, or other
actions.
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Organization
Agree?
Question 7 Comment
approached by vegetation no threat to the system is possible if the vegetation is removed before it actually
grows into the Critical Clearance Zone . In many cases the vegetation can be removed without taking clearance
outages because the Critical Clearance Zone is large, and the conductor and vegetation are still relatively far
apart. In such cases there is no need to notify the Transmission Operator, although there is a need to remove
the vegetation immediately. We recognize that the opposite is also true, and that in some cases it will be
necessary to notify the Transmission Operator because a clearance outage or line de-rating may be required to
remove the vegetation. We therefore suggest a simple change to the wording of the second sentence of R1.4.
Change "?. specify actions which shall include immediate communication of the threat to the Transmission
Operator, and may include actions such as a temporary reduction in line Rating, switching lines out of service, or
other actions" to ".. specify actions which may include immediate communication of the threat to the
Transmission Operator, a temporary reduction in line Rating, switching lines out of service, or other actions”.
This change will address the issue which is described above and will allow each Transmission Operator to
develop an imminent threat procedure that best fits their system. It should also be noted that many Transmission
Operators have imminent threat procedures in place to address all imminent threats to their transmission system,
not just threats due to vegetation. It makes sense for Transmission Owners to have only one imminent threat
process, therefore the flexibility that can be achieved in the context of this standard would be helpful.
Response: Thank you for your comment. We agree with your comments concerning the Critical Clearance Zone and the elusiveness of the term
“approach”. Subsequently, the Critical Clearance Zone methodology has been removed from the Standard. The SDT also agrees that the main purpose
of the imminent threat requirement is to enhance the responsible control center’s situational awareness of the power system’s status. Please also
note that the wording has been altered to change the “Transmission Operator” to the “responsible control center” to better identify the appropriate
responsible party. The SDT maintains that the salient requirement of this procedure is notification of the responsible operator of any imminent threat
to the power system. Beyond this, it is left to the Transmission Owner to develop an imminent threat procedure that best fits its system.
SERC Vegetation Management
Subcommittee (VMS)
Disagree
The Requirement as written is too prescriptive and is open to interpretation, from an audit perspective, with use
of the term “immediate” communication and a partial list of activities. Many conditions or threats, requiring
immediate removal, would not require communication with the Transmission Operator, who is not an applicable
entity for this standard. The SERC VMS recommends that R1.4 be deleted. Since this is a "zero tolerance"
standard any Transmission Owner will remove any discovered threats to prevent outages. If R1.4 is not deleted,
the SERC VMS believes that imminent threats should be a defined term. The definition should be as follows:
?Imminent Threat: A vegetation condition which, if not addressed, will place a transmission line at a significant
risk of a Sustained Outage.?
Response: Thank you for your comment. We agree that an imminent threat can exist in many different forms. Part of your concern has been addressed
by the removal of the term “immediate”. However, the SDT does not agree with removing the imminent threat requirement. The main purpose of the
imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system. Please
note that the requirement wording has also been altered to change the designation “Transmission Operator” to the “responsible control center” to
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Organization
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Question 7 Comment
better identify the appropriate party. The salient requirement of the imminent threat procedure is notification of the responsible operator of any
imminent threat to the power system. Beyond this, it is left to the Transmission Owner to develop an imminent threat procedure that best fits its
system.
Progress Energy Florida
Disagree
Progress Energy agrees with the need for a Transmission Owner to have an Imminent Threat Procedure and
that the Transmission Operator should be immediately notified of imminent threats but only when it is appropriate
as defined by the Transmission Owner's imminent threat procedure. We disagree with the requirement to
immediately communicate with the Transmission Operator whenever the Critical Clearance Zone is approached.
Not every scenario is an issue that requires action by the Transmission Operator: It is possible that the Critical
Clearance Zone is being approached by vegetation at the lowest point of the Critical Clearance Zone whereas
the conductor may be at its highest point in the Critical Clearance Zone (potentially 30 feet away from the
vegetation) -- This typical situation does not merit notification to the Transmission Operator (which is required by
FAC-003-2 as currently written).
Response: Thank you for your comment. We agree with your comments concerning the Critical Clearance Zone methodology. Subsequently, the
Critical Clearance Zone methodology has been removed from the Standard. The SDT also agrees that the main purpose of the imminent threat
requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system. Please also note that the
requirement wording has been altered to change the “Transmission Operator” to the “responsible control center”. The SDT feels this better identifies
the appropriate party. The SDT maintains that the salient requirement of R1.4 is notifying the responsible operator of any imminent threat to the
power system.
Progress Energy Carolinas
Disagree
Progress Energy agrees with the need for a Transmission Owner to have an Imminent Threat Procedure and
that the Transmission Operator should be immediately notified of imminent threats but only when it is appropriate
as defined by the Transmission Owner's imminent threat procedure. We disagree with the requirement to
immediately communicate with the Transmission Operator whenever the Critical Clearance Zone is approached.
Not every scenario is an issue that requires action by the Transmission Operator: It is possible that the Critical
Clearance Zone is being approached by vegetation at the lowest point of the Critical Clearance Zone whereas
the conductor may be at its highest point in the Critical Clearance Zone (potentially 30 feet away from the
vegetation) -- This typical situation does not merit notification to the Transmission Operator (which is required by
FAC-003-2 as currently written).
Response: Thank you for your comment. We agree with your comments concerning the Critical Clearance Zone methodology. Subsequently, the
Critical Clearance Zone methodology has been removed from the Standard. The SDT also agrees that the main purpose of the imminent threat
requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system. Please also note that the
requirement wording has been altered to change the “Transmission Operator” to the “responsible control center”. The SDT feels this better identifies
the appropriate party. The SDT maintains that the salient requirement of R1.4 is notifying the responsible operator of any imminent threat to the power
September 8, 2009
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Organization
Agree?
Question 7 Comment
system.
SERC OC Standards Review
Group
Disagree
The Requirement as written is too prescriptive and is open to interpretation from an audit perspective with use of
the term “immediate” communication and a partial list of activities. Due to limitations of communication
capabilities in the field, "immediate" may not be practical. While the White Paper provides insight into what is
acceptable communications to the Transmission Operator, the standard is less prescriptive in describing what is
an acceptable communication path to the Transmission Operator. We recommend better descriptions in VSLs,
measures and the Reliability Standard Audit Worksheet as to what is acceptable. Many conditions or threats,
requiring immediate removal, would not require communication with the Transmission Operator, who is not an
applicable entity for this standard. The SERC OCSRG recommends that R1.4 be deleted. Since this is a "zero
tolerance" standard any Transmission Owner will remove any discovered threats to prevent outages. If R1.4 is
not deleted, the SERC OCSRG believes that imminent threats should be a defined term. The definition should
be as follows: “Imminent Threat: A vegetation condition which, if not addressed, will place a transmission line at
an immediate risk of a Sustained Outage.”
Response: Thank you for your comment. Part of your concern has been addressed by the removal of the term “immediate”. However, the SDT does
not agree with removing the imminent threat requirement. The main purpose of the imminent threat requirement is to enhance the responsible control
center’s situational awareness of reliability dangers to the power system. Please note that this requirement’s wording has also been altered to change
the designation “Transmission Operator” to the “responsible control center” to better identify the appropriate party. The salient requirement of the
imminent threat procedure is notification of the responsible operator of any imminent threat to the power system. Beyond this, it is left to the
Transmission Owner to develop an imminent threat procedure that best fits its system and field communication capabilities. The SDT also feels that it
is important for the aspects of the imminent threat procedure and the triggers be defined by the Transmission Owner. The Violation Severity Levels
for this requirement are now binary and self explanatory. The SDT is prepared to provide input in the revision of RSAWs, but under current practice,
RSAWs are not developed by standard drafting teams.
Florida Power & Light
Disagree
The definition of Imminent Threat procedure should be included in the Standard. As FERC has stated with
regard to the definition of sabotage, the industry should come up with a standard definition and it should not vary
from company-to-company. FPL further disagrees with defining Imminent Threat only in a white paper as
proposed by some. The Standard should not refer to other reference documents, especially when it is to add
clarity and should define the Imminent Threat procedure as well as its requirements within the body of the
Standard.
Response: Thank you for your comment. The SDT disagrees with your comments. We feel that the Transmission Owner should have the flexibility to
not only develop the imminent threat procedure but also define the triggers needed for its particular system. The main purpose of the imminent threat
requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system. The notification
requirement is a mandatory requirement for all Transmission Owners. Please note that this requirement’s wording has also been altered to change the
designation “Transmission Operator” to the “responsible control center” to better identify the appropriate party. Beyond this, it is left to the
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Transmission Owner to develop all other imminent threat procedure components.
Southern Company
Disagree
The standard requirement, as written, requires the "immediate notification" of the operator. This standard
requirement could be interpreted to mandate that this notification take place prior to any other action. There
could be times that this communication would take up valuable time needed to relieve the immediate threat. The
requirement should be modified to list examples of appropriate actions that could be taken. The Transmisison
Owner should be allowed the flexibility of developing a communication process that ensures timely notification of
a threat and the proper channels of communication that will be utilized in making the notification. The present
wording in the standard alone suggests the individual observing the threat in the field is directly responsible for
communicating with the Transmission Operator while the whitepaper tends to be more flexible. The
Transmission Owner may wish to have the vegetation contractor notify the Transmisison Owner's forester who in
turn will notify the Transmission Operator. While the whitepaper does an adequate job describing acceptable
responses, the standard does not. It is recommend the standard, VSL, and Reliability Standard Audit Worksheet
better explain what is an acceptable response to the Transmission OwnerP. The requirement then goes on to
address specific actions the operator "may" take in response to the notification. The imminent threat processes
should be limited to the steps taken to notify the Transmission Operator in a timely manner. FAC-003 is not the
appropriate place to address Transmission Operator decisions resulting from notification of a threat to the
system.
Response: Thank you for your comment. Part of your concern has been addressed by the removal of the term “immediate”. We agree that the main
purpose of this requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system. Further,
please note that the requirement wording has also been altered to change the designation “Transmission Operator” to the “responsible control center”
to better identify the appropriate party. Beyond this, it is left to the Transmission Owner to develop an imminent threat procedure that best fits its
system and field communication capabilities. The Violation Severity Levels for this requirement are now binary and self explanatory. The SDT is
prepared to provide input in the revision of RSAWs, but under current practice, RSAWs are not developed by standard drafting teams.
E.ON U.S.
Disagree
The Requirement as written is too prescriptive and is open to interpretation, from an audit perspective, with use
of the term “immediate” communication and a partial list of activities. Many conditions or threats, requiring
immediate removal, would not require communication with the Transmission Operator, who is not an applicable
entity for this standard. We suggest that R1.4 be deleted. Since this is a "zero tolerance" standard any
Transmission Owner will remove any discovered threats to prevent outages. If R1.4 is not deleted, we believe
that imminent threats should be a defined term. The definition should be as follows: “Imminent Threat: A
vegetation condition which, if not addressed, will place a transmission line at a significant risk of a Sustained
Outage.”
Response: Thank you for your comment. We agree that an imminent threat can exist in many different forms. Part of your concern has been
addressed by the removal of the term “immediate”. However, the SDT does not agree with removing the imminent threat requirement. The main
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purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power
system. Please note that the requirement wording has also been altered to change the designation “Transmission Operator” to the “responsible
control center” to better identify the appropriate party. The salient requirement of this procedure is notification of the responsible operator of any
imminent threat to the power system. Beyond this, it is left to the Transmission Owner to develop an imminent threat procedure that best fits its
system.
Midwest ISO Stakeholders
Standards Collaborators
Disagree
Transmission Owners should have a Vegetation Imminent Threat Procedure, and "Vegetation Imminent Threat"
should be a defined term, defined as: "Vegetation observed in the field encroaching upon a conductor within a
distance that is twice the Gallet clearance distances referenced in Table I of the draft standard FAC-003-2." In
this case, the threat would require an immediate response and would include communication to the
Transmission Operator. From there, the actions that the operator decides to take will be dependent on the
incident and system conditions. We do not need to be prescriptive with this requirement but rather allow the
Transmission Operator and appropriate field personnel the flexibility to make the right decisions to safely,
promptly and appropriately remove the vegetation threat. From a Transmission Owner's perspective, many
situations can constitute an imminent threat but this approach will clearly define a "Vegetation Imminent Threat"
as it relates to the Purpose of this standard. See our related comment on #11 below.
Response: Thank you for your comment. We agree that many situations can constitute an imminent threat. While we do not agree that an imminent
threat should be defined in the Standard, we do agree that the Transmission Owner should have the flexibility to develop an imminent threat procedure
that allows the appropriate decisions to address the vegetation threat. This requirement allows the Transmission Owner to develop an imminent threat
procedure that best fits its system. The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational
awareness of reliability dangers to the power system. Please note that the requirement’s wording has also been altered to change the designation
“Transmission Operator” to the “responsible control center” to better identify the appropriate party. The SDT feels this is a better approach than to
have a rigid definition of an imminent threat procedure.
SERC Compliance Staff
Disagree
SERC staff agrees with the concept of an imminent threat procedure, but disagrees with this requirement in its
current form. The use of the word "immediate" is ambiguous. There are many conditions or threats that may
require immediate removal, but would not require communication with the Transmission Operator and may
require communication with another entity. SERC staff suggests that the proper communication paths be
outlined by the Transmission Owner. Imminent threats should be a defined term, however SERC staff has not
developed an objective, unambiguous definition.
Response: Thank you for your comment. Part of your concern has been addressed by the removal of the term “immediate”. We agree that the main
purpose of the imminent threat requirement is the timely communication of a threat to the responsible operator. Therefore, the requirement wording
has been altered to change the designation “Transmission Operator” to the “responsible control center”. The main purpose of this requirement is to
enhance the responsible control center’s situational awareness of reliability dangers to the power system. While we do agree that the Transmission
Owner should outline the proper communication paths, we do not agree that an imminent threat should be defined in the Standard. The SDT feels the
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Transmission Owner should have the flexibility to develop an imminent threat procedure that best fits its system.
ITC HOLDINGS
Disagree
Agree & Disagree with the question: Agree with the need to have an Imminent Threat Procedure and upon
discovery of an IT, the Transmission Operations (Transmission Owner) should be notified. We Disagree
however, with the requirement as written as its too prescriptive and is open to interpretation, from an audit
perspective, with use of the term “immediate” communication and a partial list of activities that the Transmission
Owner may consider. Decisions on what specific system operating actions that could be taken are beyond the
responsibility of the vegetation management personnel. Disagree with the need to implement the imminent threat
procedure merely because a Critical Clearance Zone is being approached. It is possible that the Critical
Clearance Zone is being approached by vegetation at the lowest point of the Critical Clearance Zone where
the conductor may be at its highest point in the Critical Clearance Zone , (potentially 20 or 30 feet from
vegetation) and wouldn’t necessitate notification to the Transmission Owner. Is there a desired distance from the
Critical Clearance Zone where this procedure must be implemented since all vegetation within a Right-of-Way
will approach the Critical Clearance Zone as it grows? R1.4 should be changed to ?Require a process for
response to vegetation related imminent threat to applicable lines and not the Critical Clearance Zone
Response: Thank you for your comment. We agree with your comments concerning the Critical Clearance Zone and the elusiveness of the terms
“approach” and “immediate”. Subsequently, the Critical Clearance Zone methodology has been removed from the Standard. Also, the term
“immediate” has been removed. The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational
awareness of the power system’s status. Please also note that the wording has been altered to change the “Transmission Operator” to the
“responsible control center” to better identify the appropriate responsible party. The SDT maintains that the salient requirement of the imminent
threat procedure is notification of the responsible operator of any imminent threat to the power system. Beyond this, it is left to the Transmission
Owner to develop an imminent threat procedure that best fits its system.
Tennessee Valley Authority
Disagree
TVA recommends that R1.4 and R2 both be removed from this Standard. This is a "zero tolerance" Standard
with significant penalties for outage violations. These penalty conditions are the necessary and sufficient
conditions for the Transmission Owner to immediately react to any discovered threats to prevent potential
outages.
Response: Thank you for your comments. While the drafting team does agree that the penalties for the “zero tolerance” aspect of the Standard
certainly provide a strong incentive, we still feel that a requirement for an imminent threat procedure should be included in the Standard. The main
purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power
system. Please note that this requirement’s wording has been altered to change the designation “Transmission Operator” to the “responsible control
center” to better identify the appropriate party. The salient part of this procedure is notification of the responsible operator of any imminent threat to
the power system. Beyond this, the Transmission Owner should develop all other components of the imminent threat procedure to best fit its system.
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American Electric Power (AEP)
Agree?
Disagree
Question 7 Comment
AEP agrees with the need for a Transmission Owner to have an Imminent Threat Procedure and that the
Transmission Operator should be immediately notified of imminent threats. However, AEP disagrees with the
requirement that the Transmission Operator be notified merely because the Cricitical Clearance Zone (Critical
Clearance Zone ) has been approached. It is possible that the Critical Clearance Zone is encroached by
vegetation at the lowest point of the Critical Clearance Zone whereas the conductor may be at its highest point
in the Critical Clearance Zone (potentially 20 or 30 feet away from the vegetation). This situation does not merit
notification to the Transmission Operator. Please also refer to our comments regarding Critical Clearance Zone
in AEP's responses to Questions 15 and 18.
Response: Thank you for your comment. We agree with your comments concerning the Critical Clearance Zone and the elusiveness of the term
“approach”. Subsequently, the Critical Clearance Zone methodology has been removed from the Standard. The SDT feels that the main purpose of the
imminent threat requirement is to enhance the responsible control center’s situational awareness of the power system’s status. Please also note that
the wording has been altered to change the “Transmission Operator” to the “responsible control center” to better identify the appropriate responsible
party. The SDT maintains that the salient requirement of this procedure is notification of the responsible operator of any imminent threat to the power
system. Beyond this, it is left to the Transmission Owner to develop an imminent threat procedure that best fits its system.
Tampa Electric Company
Disagree
TECO aggres with the need for the Imminent Threat Procedure. However, the use of the new Critical Clearance
Zone could create a "fill in the blank" standard. We need to lock these clearances down as an industry so as to
define what is an imminent threat and what the Critical Clearance Zone is in terms of specific distances.
Response: Thank you for your comments. The SDT agrees with your concern of having a standard with “fill in the blank” requirements. We have
made some major changes to this requirement due to the overwhelming response from industry that the imminent threat requirement was needed but
should not be overly prescriptive. The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational
awareness of reliability dangers to the power system. Please note that the requirement wording has also been altered to change the designation
“Transmission Operator” to the “responsible control center” to better identify the appropriate party. The salient part of the imminent threat procedure
is notification of the responsible operator of any imminent threat to the power system.
Using the Critical Clearance Zone as an undefined “trigger” for implementing the imminent threat process has been removed from the Standard. The
Critical Clearance Zone methodology has been deleted from the Standard.
Orange and Rockland Utilities
Inc.
September 8, 2009
Disagree
While we agree that the imminent threat procedure should be included in the Transmission Vegetation
Management Program, the requirement is overly prescriptive and should be revised to allow Transmission
Owners flexibility to develop imminent threat procedures which best fit their systems and protocols. We
recommend that R1.4 be reworded as follows: "Require a process or procedure for response to vegetationrelated imminent threats to applicable lines. The imminent threat procedure shall require action to eliminate
vegetation-related imminent threats, and shall be implemented upon discovery of such conditions". In addition,
the definition of "Imminent Threat" should be defined. We suggest the following: "A condition which places a
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transmission line at significant risk of an outage in the very near term". An example of a vegetation-related
imminent threat would be an uprooted tree leaning precariously toward a conductor which is certain to make
contact with the conductor as the tree falls. Many Transmission Operators have imminent threat procedures in
place to address all imminent threats to their transmission systems, not just imminent threats due to vegetation.
In many cases it would make sense for Transmission Owners to have one imminent threat process that covers
all imminent threat conditions. The flexibility being recommended would facilitate this.
Response: Thank you for your comment. The SDT agrees that the requirement was overly prescriptive. The requirement has been revised to focus on
the main purpose of the imminent threat requirement; which is to enhance the responsible control center’s situational awareness of reliability dangers
to the power system. Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the
“responsible control center” to better identify the appropriate party. The salient part of this procedure is notification of the responsible operator of any
imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and procedures that best
fit its systems and protocols; thereby providing for the flexibility that you have suggested. Along with this line of reasoning, we do not agree that an
imminent threat should be defined in the Standard. Again, the SDT feels that the Transmission Owner should have the flexibility to define what
constitutes an imminent threat to its individual power system. This flexibility also allows the Transmission Owner to have one imminent threat process
in place to cover all imminent threats to its transmission systems, not just imminent threats due to vegetation as you have noted.
American Transmission
Company
Disagree
We agree that entities should have a Vegetation Imminent Threat Procedure, but that the term should be
defined. Also see related comments to Question #11.
Response: Thank you for your comment. We have made some major changes to this requirement due to the overwhelming response from industry
that the imminent threat requirement was needed, as long as it was not an overly prescriptive requirement. We do not agree that an imminent threat
should be defined in the Standard. The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational
awareness of reliability dangers to the power system. Please note that the requirement wording has also been altered to change the designation
“Transmission Operator” to the “responsible control center” to better identify the appropriate party. The salient requirement of an imminent threat
procedure is notification of the responsible operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to
determine the follow up activities and procedures that best fit its system. The SDT feels this is a better approach than to have a rigid definition of an
imminent threat procedure.
Nebraska Public Power District
Disagree
NPPD agrees that a Transmission Owner should have an imminent threat procedure and the Transmission
Owner be immediately notified of any threats. NPPD disagrees with prescribing what needs to be done as a
result of the threat. This is condition based and staff can make the right decision as to what corrective actions
are necessary.
Response: Thank you for your comment. The SDT agrees that prescribing what needs to be done as a result of the threat should not be included as
part of the Standard requirement. This language has been removed from the text as you have suggested. The SDT also agrees that the main purpose
of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system.
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Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible control
center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible operator of
any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and procedures that
best fit its system.
Consumers Energy Company
Disagree
Consumers Energy believes that each Transmission Owner/Operator should have a Vegetation Imminent Threat
Procedure. We disagree with this requirement because "vegetation imminent threat" is not defined in the
standard. As interpreted, the "vegetation imminent threat" is only what is needed to avoid violating the Gallet
formula minimum distance which would allow vegetation approaching close to 3 feet of separation on 345 kV
conductors. At this distance, removal of the tree cannot occur without removing the line from service per OSHA
rules. Therefore, the tree can "cause" an outage but be acceptable under this standard. Consumers Energy
believes that vegetation must be maintained so that extraordinary measures needed to remove the vegetation
threat do not have to occur in order to complete the work. Thus, the minimum distance to "trigger" an imminent
threat must be greater than the OSHA minimum working distance and therefore the Gallet formula does not
provide the protection that FERC demands. During high load periods options a system operator may have to
mitigate the vegetation threat may not be available; you may not be able to remove the line from service, derate
the line, etc., so the operator must "hope" to get through the high load period without the vegetation causing a
outage. Allowing vegetation to approach the Gallet formula distance is unacceptable and severely decreases
the reliability of the system.
Response: Thank you for your comment. The SDT does not agree that a vegetation imminent threat should be defined in the Standard. The Critical
Clearance Zone methodology has been removed from the Standard. We feel that the Transmission Owner should have the flexibility to not only
develop the imminent threat procedure but also define the triggers needed for its particular system. The main purpose of the imminent threat
requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system. The notification
requirement is a mandatory requirement for all Transmission Owners. Please note that this requirement’s wording has also been altered to change the
designation “Transmission Operator” to the “responsible control center” to better identify the appropriate party. The SDT maintains that the salient
requirement of an imminent threat procedure is notification of the responsible operator of any imminent threat to the power system. Beyond this, it is
left to the Transmission Owner to determine the follow up activities and procedures that best fit its system. Aside from the negative economic and
operational impacts associated with unscheduled facility outages, failures by the Transmission Owner to effectively execute follow up activities and
procedures will most likely lead to a violation(s) of other requirements related to Minimum Vegetation Clearance Distance (MVCD) encroachment or
sustained outages.
Ameren
September 8, 2009
Disagree
Transmission Owners should have a Vegetation Imminent Threat Procedure, and "Vegetation Imminent Threat"
should be a defined term, defined as: "Vegetation observed in the field encroaching upon a conductor within a
distance defined in the Vegetation Management plan." In this case, the threat would require an immediate
response and would include communication to the Transmission Operator. From there, the actions that the
operator decides to take will be dependent on the incident and system conditions. We do not need to be
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prescriptive with this requirement but rather allow the Transmission Operator and appropriate field personnel the
flexibility to make the right decisions to safely, promptly and appropriately remove the vegetation threat. From a
Transmission Owner's perspective, many situations can constitute an imminent threat but this approach will
clearly define a "Vegetation Imminent Threat" as it relates to the Purpose of this standard. While a definition of
"Vegetation Imminent Threat - Vegetation observed in the field encroaching upon a conductor within a distance
that is twice the Gallet clearance distances referenced in Table I of the draft standard FAC-003-2" would be
acceptable and far superior to that which is proposed, it will still be difficult for field personnel to identify, at each
foot of a transmission circuit, wherein twice the Gallet distance would be found. See comment on #11 below.
Response: Thank you for your comment. We agree with your assessment that the Standard needs an imminent threat requirement, but as it was
written, the requirement was overly prescriptive. As a result, and because much of the industry agreed with you, we have made some major changes
to this requirement. The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of
reliability dangers to the power system. Please note that the requirement wording has also been altered to change the designation “Transmission
Operator” to the “responsible control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is
notification of the responsible operator of any imminent threat to the power system.
We further agree that many situations can constitute an imminent threat, distance from the vegetation to the conductor being only one of such
situations, so the references to the Critical Clearance Zone methodology as a defined “trigger” for implementing the imminent threat process has been
removed from the Standard. For that matter, the Critical Clearance Zone methodology has been deleted from the Standard. While we do not agree that
an imminent threat should be defined in the Standard, we do agree that the Transmission Owner should have the flexibility to develop an imminent
threat procedure that allows the appropriate decisions to address the vegetation threat. The requirement, as it has been reworded, allows the
Transmission Owner to develop an imminent threat procedure that best fits its system. The SDT feels this is a better approach than to have a rigid
definition of an imminent threat procedure.
Consolidated Edison Company
of New York (CECONY)
Disagree
CECONY currently has procedures that mandate response to imminent threats. The Standard should be made
more general and not identify the specific actions that shall be taken in the procedure. The second sentence of
R1.4 should be deleted and the first sentence should read, 'Require a process or procedure to respond to
vegetation-related imminent threats." This adds the necessary flexibility that utilities require and avoids additional
redundant processes or procedures from being developed.
Response: Thank you for your comment. The SDT agrees that the requirement should be more general and has revised the requirement to focus on
the main purpose of the imminent threat requirement; which is, to enhance the responsible control center’s situational awareness of reliability dangers
to the power system. Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the
“responsible control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the
responsible operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up
activities and procedures that best fit its systems and protocols, thereby providing for the flexibility that you have suggested.
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Duke Energy Corporation
Agree?
Disagree
Question 7 Comment
Duke believes that Transmission Owners should have a Vegetation Imminent Threat Procedure, and "Vegetation
Imminent Threat" should be a defined term, defined as: "Vegetation observed in the field encroaching upon a
conductor within a distance that is twice the Gallet clearance distances referenced in Table I of the draft
standard FAC-003-2." In this case, the threat would require an immediate response and would include
communication to the Transmission Operator. From there, the actions that the operator decides to take will be
dependent on the incident and system conditions. We do not need to be prescriptive with this requirement but
rather allow the Transmission Operator and appropriate field personnel the flexibility to make the right decisions
to safely, promptly and appropriately remove the vegetation threat. From a Transmission Owner's perspective,
many situations can constitute an imminent threat but this approach will clearly define a "Vegetation Imminent
Threat" as it relates to the Purpose of this standard. See our related comment on #11 below.
Response: Thank you for your comment. While we do not agree that an imminent threat should be defined in the Standard, we do agree with your
assessment that the Standard needs an imminent threat requirement, but as it was written, the requirement was overly prescriptive. As a result, and
because much of the industry agreed with you, we have made some major changes to this requirement. The Critical Clearance Zone methodology has
been deleted from the Standard. The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational
awareness of reliability dangers to the power system. Please note that the requirement wording has also been altered to change the designation
“Transmission Operator” to the “responsible control center” to better identify the appropriate party. The salient requirement of an imminent threat
procedure is notification of the responsible operator of any potential threat to the power system. Beyond this, it is left to the Transmission Owner to
determine the “triggers”, follow up activities, and procedures that best fit its system; thereby providing for the flexibility that you have suggested.
The SDT feels this is a better approach than to have a rigid definition of an imminent threat procedure.
Entergy Services
Disagree
1. The requirement should state that each Transmission Owner will be responsible for creating and maintaining
a Vegetation Imminent Threat Process. This process will clearly define how the Transmission Owner defines a
vegetation imminent threat.
2. The requirement needs to state that only vegetation conditions identified, to the Transmission Owner, by
regular field inspections, including aerial inspections, and other internal and external verifiable reports of
vegetation imminent threats will be managed through this process.
3. If the standard requires a process to mitigate potential immediate threats to the system, the term ?vegetation
imminent threat? must be defined. This definition must not delineate the precise steps that are required to be
taken to allow experts as many options as necessary to address each vegetation condition specifically.
4. The list of possible mitigating actions should be removed from the standard since it is not an all inclusive list.
Listing these actions in the standard may imply that the entity must do one or all of the actions to be in
compliance. The entity must have sufficient latitude to evaluate each possible vegetation condition and apply
the most appropriate mitigation steps, up to and including the removal of the identified vegetation.
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Response: Thank you for your comments.
1. The SDT prefers to allow the verbiage “an imminent threat of a vegetation-related Sustained Outage” to stand without further definition. The SDT
agrees that the Standard needs an imminent threat requirement. However, as it was written for the initial posting, the requirement was overly
prescriptive. As a result, and because much of the industry agreed with you, the SDT has made some changes to this requirement. The main purpose
of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system.
Please note that the requirement wording has also been altered to change the designation “Transmission Operator” to the “responsible control center”
to permit communication with the relevant entity for the Transmission Owner. The salient requirement of an imminent threat procedure is notification
of the responsible operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the “triggers”,
follow up activities, and procedures that best fit its system, thereby providing for the flexibility that you have suggested. The SDT feels this is a better
approach than to have a rigid definition of an imminent threat procedure.
2. See response 1 above.
3. See response 1 above.
4. See response 1 above.
Salt River Project
Disagree
Agree with R1.4, however with the suggested change: Remove the language "?and may include actions such as
a temporary reduction in line Rating, switching lines out of service, or other actions.". Any standard should not
contain advisory-type language, it should be declarative in tone. The suggested actions are not the
responsibility of the vegetation management program.
Response: Thank you for your comment. The advisory type language has been removed from the requirement as you have suggested. The SDT also
agrees that these “advisory” actions could fall outside the responsibility of some utilities’ Transmission Vegetation Management Program. The main
purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power
system. Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible
control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible
operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and
procedures that best fit its situation.
Northeast Utilities
September 8, 2009
Disagree
Agree with the need to have and implement when necessary an imminent threat procedure. Disagree with the
need to implement the imminent threat procedure merely because a Critical Clearance Zone is being
approached, as required by R2. Is there a desired distance from the Critical Clearance Zone where this
procedure must be implemented, since all vegetation within a right-of-way will "approach" the Critical Clearance
Zone as it grows? How will time of year and operating conditions be factored in, which may change the
requirements to perform control during periods of low temperature or low load? It would not be necessary to
perform all the requirements of an imminent threat procedure when there is adequate clearance to schedule the
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work without jeopardizing the reliability of the system. For example, in mid winter a line is 8 feet from a tree there is little chance of the line reacing maximum sag at that time of year and the present condition does not
constitute an imminent threat at that time. Also, disagree with the requirement for the imminent threat procedure
to include actions that could be taken by the Transmission OwnerP (reduction in line rating, switching). The
requirement should be limited to notifications to the Transmission OwnerP, since decisions on what specific
system operating actions to take are beyond the responsibility of the Transmission Owner. The decision on what
actions to take needs to be performed either by the Transmission OwnerP, or by the Transmission OwnerP in
conjunction with the Transmission Owner.
Response: Thank you for your comments. We agree with your comments concerning the Critical Clearance Zone and the elusiveness of the term
“approach”. Subsequently, the Critical Clearance Zone methodology as it refers to the imminent threat process has been removed from the Standard.
The SDT also agrees that the main purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of
the power system’s status. . Please also note that the wording has been altered to change the “Transmission Operator” to the “responsible control
center” to better identify the appropriate responsible party. The salient requirement of an imminent threat procedure is notification of the responsible
operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to develop an imminent threat procedure that
best fits its system, and allows the Transmission Owner to make appropriate decisions on follow up actions.
Hydro-Quebec Transenergie
(HQT)
September 8, 2009
Disagree
While we strongly agree that an imminent threat procedure should be required in the Transmission Vegetation
Management Program, we disagree with some specific wording in R1.4. R1.4 requires immediate
communication of an imminent threat to the Transmission Operator, which we would normally agree with. R2
however requires that the imminent threat procedure be implemented when the Critical Clearance Zone (Critical
Clearance Zone ) is approached by vegetation. "Approached" is not defined as a specific distance, so this part
of the requirement is left up to the individual's interpretation. In cases where the Critical Clearance Zone is
approached by vegetation no threat to the system is possible if the vegetation is removed before it actually
grows into the Critical Clearance Zone . In many cases the vegetation can be removed without taking clearance
outages because the Critical Clearance Zone is large, and the conductor and vegetation are still relatively far
apart. In such cases there is no need to notify the Transmission Operator, although there is a need to remove
the vegetation immediately. We recognize that the opposite is also true, and that in some cases it will be
necessary to notify the Transmission Operator because a clearance outage or line de-rating may be required to
remove the vegetation. We therefore suggest a simple change to the wording of the second sentence of R1.4.
Change "?. specify actions which shall include immediate communication of the threat to the Transmission
Operator, and may include actions such as a temporary reduction in line Rating, switching lines out of service, or
other actions" to ".. specify actions which may include immediate communication of the threat to the
Transmission Operator, a temporary reduction in line Rating, switching lines out of service, or other actions".
This change will address the issue which is described above and will allow each Transmission Operator to
develop an imminent threat procedure that best fits their system. It should also be noted that many Transmission
Operators have imminent threat procedures in place to address all imminent threats to their transmission system,
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not just threats due to vegetation. It makes sense for Transmission Owners to have only one imminent threat
process; therefore the flexibility that can be achieved in the context of this standard would be helpful.
Response: Thank you for your comments. We agree with your comments concerning the Critical Clearance Zone and the elusiveness of the term
“approach”. Subsequently, the Critical Clearance Zone methodology has been removed from the Standard. The SDT feels that the main purpose of the
imminent threat requirement is to enhance the responsible control center’s situational awareness of the power system’s status. The wording about
other follow up actions that could be taken has been removed from the requirement. Please also note that the wording has been altered to change
the “Transmission Operator” to the “responsible control center” to better identify the appropriate responsible party. The SDT maintains that the
salient requirement of an imminent threat procedure is notification of the responsible operator of any imminent threat to the power system. Beyond
this, it is left to the Transmission Owner to develop an imminent threat procedure that best fits its system.
Pepco Holdings, Inc
Disagree
While an imminent threat procedure is prudent and reasonable, it does not need to consider a Critical Clearance
Zone as addressed in our comments on other questions. In fact, one can quickly provide examples of imminent
threats when the threat is not even on the right of way. The Transmission Owner should simply have an
imminent threat procedure to address identified imminent or potential imminent threats.
Response: Thank you for your comment. We agree with your comments concerning the Critical Clearance Zone methodology. Subsequently, the
Critical Clearance Zone methodology has been removed from the Standard. The SDT feels that the main purpose of the imminent threat requirement is
to enhance the responsible control center’s situational awareness of the power system’s status. Please also note that the requirement wording has
been altered to change the “Transmission Operator” to the “responsible control center” to better identify the appropriate responsible party. The SDT
maintains that the salient requirement of an imminent threat procedure is notification of the responsible operator of any imminent threat to the power
system. Beyond this, the SDT agrees that it should be left to the Transmission Owner to develop an imminent threat procedure that best fits its
system.
Southern California Edison
Company
Agree
Q7: SCE agrees in part with the content of R1.4 because of its similarity to existing requirement R1.5 in FAC003-1. However, we disagree with the drafter’s inclusion of peripheral information following the first sentence.
We also note that the second sentence of proposed R1.4 includes both a requirement and a recommendation.
SCE believes this and similar recommendations are best suited for the supporting technical paper. SCE
respectfully suggests that R1.4 be revised to read: "Specify a process or procedure for communicating an
impending vegetation-to-line contact that may result in a sustained outage and the appropriate response
measures.”
Response: Thank you for your comment. The SDT feels that the main purpose of the imminent threat requirement is to enhance the responsible
control center’s situational awareness of the power system’s status. We agree with your suggestions to exclude some of the peripheral language
included in this requirement. Thus, the SDT has removed references to the Critical Clearance Zone, the word “immediate”, and the wording referring
to other actions that may be taken by the responsible operator. Please also note that the wording has been altered to change the “Transmission
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Operator” to the “responsible control center” to better identify the appropriate responsible party.
Western Utility Arborists
Agree
We agree with 1.4, with the following qualification: Any standard that is developed should not contain advisorytype language” it should be declarative in tone. For example, in R1.4, the ending clause that begins “and may
include actions” should be removed because it is advisory in nature. The suggested actions are not even the
responsibility of the vegetation management program.
Response: Thank you for your comments. The advisory type language has been removed from the requirement as you have suggested. The SDT also
agrees that these “advisory” actions could fall outside the responsibility of some utilities’ Transmission Vegetation Management Program. The main
purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power
system. Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible
control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible
operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and
procedures that best fit its situation.
Bonneville Power Administration
Agree
BPA agrees with 1.4, with the following change. The ending phrase: "and may include actions such as a
temporary reduction in line Rating, switching lines out of service, or other actions" should be eliminated. Not
only does BPA feel it is inappropriate to use advisory-type rather than declarative language in a Standard, BPA
feels it is also questionable to give examples of imminent response actions that are often not within the direct
capability of a vegetation program to enact. Eliminating the reference to these possible actions leaves it up to
the Transmission Operator to decide what the eminent threat response is.
Response: Thank you for your comment. The advisory type language has been removed from the requirement as you have suggested. The SDT also
agrees that these “advisory” actions could fall outside the direct capability of some utilities’ Transmission Vegetation Management Program. The main
purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power
system. Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible
control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible
operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and
procedures that best fit its situation.
FirstEnergy
Agree
The safety of the personnel required to remove a tree or vegetation on or near an energized conductor must be
considered when implementing the imminent threat procedure. Although this is a reliability standard, the safety
of the personnel may be one "trigger" to implement the imminent threat procedure. That being said, the workers
on site, in their judgment, are not able to remove the vegetation safely then the imminent threat procedure would
be implemented. See comments for Critical Clearance Zone .
Response: Thank you for your comment. The SDT also believes human safety must be major consideration in this requirement. The Transmission
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Owner may include in its Imminent Threat procedure appropriate considerations for personnel safety as a trigger. The main purpose of the imminent
threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system. The SDT made
major changes to make the requirement less prescriptive. Also, the wording has been altered to change the designation “Transmission Operator” to
the “responsible control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the
responsible operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up
activities and procedures that best fit its situation. The Critical Clearance Zone methodology has been removed from the Standard.
MRO NERC Standards Review
Subcommittee
Agree
The MRO agrees and believes that it is very important for the applicable entities to posses a Imminent Threat
Procedure. The MRO also believes that the term "Imminent Threat" is subjective an should be defined.
Response: Thank you for your comment. We have made some major changes to this requirement due to the overwhelming response from industry
that the imminent threat requirement was needed, as long as it was not an overly prescriptive requirement. We do not agree that an imminent threat
should be defined in the Standard. The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational
awareness of reliability dangers to the power system. Please note that the requirement wording has also been altered to change the designation
“Transmission Operator” to the “responsible control center” to better identify the appropriate party. The salient requirement of an imminent threat
procedure is notification of the responsible operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to
determine the follow up activities and procedures that best fit its system. The SDT feels this is a better approach than to have a rigid definition of an
imminent threat procedure.
Western Area Power
Administration, Rocky Mountain
Region
Agree
The Technical Reference document could be expanded to explain that a well rounded Imminent Threat
Procedure should contain many mitigation alternatives to appropriately address a wide range of field situations,
including a "no immediate field action is required" option. For example, further investigation of a potential
imminent threat situation may reveal that the situation has been erroneously reported or incorrectly measured
and therefore no immediate vegetation removal actions are required. A utility's Imminent Threat Procedure may
also address situations beyond just vegetation related incidents.
Response: Thank you for your comment. The SDT agrees that many situations can constitute an imminent threat beyond just vegetation related
incidents. The requirement has been rewritten to focus on the main purpose of the imminent threat requirement; which is to enhance the responsible
control center’s situational awareness of reliability dangers to the power system. Please note that this requirement’s wording has also been altered to
change the designation “Transmission Operator” to the “responsible control center” to better identify the appropriate party. The salient requirement of
an imminent threat procedure is notification of the responsible operator of any potential threat to the power system. Beyond this, it is left to the
Transmission Owner to determine the follow up activities and procedures that best fit the wide range of field situations that are possible to encounter.
Platte River Power Authority
September 8, 2009
Agree
Imminent threat is not a defined term in the NERC Glossary of Terms so it could be construed as a fill-in-theblank requirement by FERC as each Transmission Owner could define Imminent Threat differently. Imminent
threat should be defined or the requirement should be reworded to define what types of situations would require
a procedure. Also, the language, "and may include actions such as a temporary reduction in line rating, switching
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lines out of service, or other actions" should be removed from the standard but could be included in the imminent
threat procedure or definition.
Response: The SDT has made some major changes to this requirement due to the overwhelming response from industry that the imminent threat
requirement was needed, as long as it was not an overly prescriptive requirement. For instance, we agree that the wording referring to other follow up
actions that may be taken by the operator is too prescriptive and has been removed from this requirement.
The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the
power system. Please note that the requirement wording has also been altered to change the designation “Transmission Operator” to the
“responsible control center” to better identify the appropriate party. The SDT feels this is a better approach than to have a rigid definition of an
imminent threat procedure. The salient requirement of an imminent threat procedure is notification of the responsible operator of any imminent threat
to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and procedures that best fit the wide range
of field situations that are possible to encounter.
USDA Forest Service,
Southwestern Region, Regional
Office for AZ and NM
Agree
The USFS would be expecting the Transmission Owner to be documenting the imminent threat procedures in an
operating plan or corridor management plan that would be approved by the designated USFS decision maker. If
such procedures are documented in the Transmission Owner's Transmission Vegetation Management Program
and are compatible with USFS resource management direction, then the imminent threat procedures could be
incorporated in the agency-approved operating plan by reference. If the Transmission Owner disputes any
restrictions that are placed by the USFS on the imminent threat procedures, the USFS has an administrative
appeals process which the Transmission Owner can use, but those procedures can be time-consuming and
probably would not be perceived by the Transmission Owner as being neutral for negotiation purposes. It might
help if a third federal party like NERC could help resolve disputes between the Transmission Owner and the
USFS on the imminent threat procedures. Although the USFS would object to unreasonable intrusion of NERC
into normal USFS land management prerogatives, imminent threat procedures would seem to be a topic for
which NERC should take a very strong position, especially with a standard that identifies minimum vegetation
clearances as related to prevention of arcing potential, or in other words, vegetation that should be considered
hazardous and in immediate need of treatment.
Response: Thank you for your comments. The SDT developed this standard to apply to Transmission Owners in support of bulk electric system
reliability. While there may be similar areas of regulation between the purview of NERC and the USFS, this standard is not intended to be incompatible
with any USFS resource management direction. That being said, any NERC standard approved by the FERC does not need to be incorporated into “the
agency-approved operating plan”. In regard to the suggestion that NERC assist in resolving disputes between USFS and Transmission Owners, this
would be beyond the scope of NERC.
The SDT suggests that USFS and affected Transmission Owners review language in permits and change that language to allow perpetual ingress and
egress and vegetation maintenance without case-by-case application and review. Such a change would prevent current problems where it takes
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upwards of one year before vegetation maintenance is allowed to proceed.
The SDT has made some major changes to this requirement due to the overwhelming response from industry that the imminent threat requirement was
needed, as long as it was not an overly prescriptive requirement. For instance, we agree that the wording referring to other follow up actions that may
be taken by the operator is too prescriptive and has been removed from this requirement.
The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the
power system. Please note that the requirement wording has also been altered to change the designation “Transmission Operator” to the
“responsible control center” to better identify the appropriate party. The SDT feels this is a better approach than to have a rigid definition of an
imminent threat procedure. The salient requirement of an imminent threat procedure is notification of the responsible operator of any imminent threat
to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and procedures that best fit the wide range
of field situations that are possible to encounter.
Manitoba Hydro
Agree
Suggest removing, "and may include actions such as a temporary reduction in line rating, switching lines out of
service, or other actions", as this is outside the scope of a vegetation management program.
Response: Thank you for your comment. The language you mention has been removed from the requirement as you have suggested. The SDT agrees
that these actions could fall outside the scope of some utilities’ Transmission Vegetation Management Program. The main purpose of the imminent
threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system. Please note that
this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible control center” to better
identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible operator of any imminent
threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and procedures that best fit its
situation.
Pacific Gas & Electric Co.
Agree
PG&E agrees an imminent threat procedure is a critical component of the standard and should be contained in
the Transmission Vegetation Management Program. See additional comments for Q11.
Response: Thank you for your comment. See the responses to comments on Q11.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Agree
We agree with 1.4, with the following qualification: Any standard that is developed should not contain advisorytype language? it should be declarative in tone. For example, in R1.4, the ending clause that begins “and may
include actions” should be removed because it is advisory in nature. The suggested actions are not even
applicable under the scope of a vegetation management program.
Response: Thank you for your comment. The advisory type language has been removed from the requirement as you have suggested. The SDT also
agrees that these “advisory” actions could fall outside the scope of some utilities’ Transmission Vegetation Management Program. The main purpose
of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power system.
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Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible control
center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible operator of
any potential threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and procedures that
best fit its situation
San Diego Gas & Electric
Agree
We recommend that any advisory language be removed, and replaced with a declaration to the utilities.
Response: Thank you for your comment. The advisory type language has been removed from the requirement as you have suggested, The remaining
declaratory language addresses the main purpose of the imminent threat requirement which is to enhance the responsible control center’s situational
awareness of reliability dangers to the power system. Please note that this requirement’s wording has also been altered to change the designation
“Transmission Operator” to the “responsible control center” to better identify the appropriate party. The salient requirement of an imminent threat
procedure is notification of the responsible operator of any potential threat to the power system. Beyond this, it is left to the Transmission Owner to
determine the follow up activities and procedures that best fit its situation
WECC
Agree
But for clarity, "Imminent Threat Procedure" should be replaced with "Vegetation Imminent Threat Procedure".
Response: Thank you for your comment. The SDT believes that the context is sufficiently clear.
Arizona Public Service Company Agree
APS agrees with 1.4, with the following qualification: Any standard that is developed should not contain advisorytype language? it should be declarative in tone. For example, in R1.4, the ending clause that begins “and may
include actions” should be removed because it is advisory in nature. The suggested actions are not even the
responsibility of the vegetation management program.
Response: Thank you for your comment. The advisory type language has been removed from the requirement as you have suggested. The SDT also
agrees that these “advisory” actions could fall outside the responsibility of some utilities’ Transmission Vegetation Management Program. The main
purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power
system. Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible
control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible
operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and
procedures that best fit its situation.
Baltimore Gas & Electric
Company
September 8, 2009
Agree
This requirement references Danger trees which according to ANSI A-300, Part 7 is any tree that could fall on
the conductor. Should this more appropriately be changed to Hazard tree which is a structurally unsound tree?
It might be helpful if an imminent threat were defined, e.g. trees that are presently encroaching in or near the
Critical Clearance Zone , or trees that by virtue of their hazardous condition appear to be likely to fall into or
near the Critical Clearance Zone in the near future. (or just leave the explanation to the White Paper)
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Response: Thank you for your comment. We agree with most of your comments and have made some major changes to this requirement due to the
overwhelming response from industry that the imminent threat requirement was needed, as long as it was not an overly prescriptive requirement.
Many situations can constitute an imminent threat, “danger” or “hazard” trees being only one of those situations. Further, due to the undefined
“triggers” associated with the Critical Clearance Zone methodology, this approach has been removed from the Standard.
The main purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the
power system. Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the
“responsible control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the
responsible operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the “triggers”, follow
up activities, and procedures that best fit its situation. The SDT feels this is a better approach than to have a rigid definition of an imminent threat.
JEA
Agree
It is appropriate to require procedures to respond to "emergency” conditions; however Imminent Vegetation
Threat should be a defined term.
Response: Thank you for your comment. The SDT prefers to allow the verbiage “an imminent threat of a vegetation-related Sustained Outage” to stand
without further definition.
BCTC
Agree
We agree with 1.4, with the following qualification: Any standard that is developed should not contain advisorytype language—it should be declarative in tone. For example, in R1.4, the ending clause that begins “…and may
include actions…” should be removed because it is advisory in nature. The suggested actions are not even the
responsibility of the vegetation management program.
Response: Thank you for your comment. The advisory type language has been removed from the requirement as you have suggested. The SDT also
agrees that these “advisory” actions could fall outside the responsibility of some utilities’ Transmission Vegetation Management Program. The main
purpose of the imminent threat requirement is to enhance the responsible control center’s situational awareness of reliability dangers to the power
system. Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible
control center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible
operator of any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and
procedures that best fit its situation.
Great River Energy
Agree
GRE agrees and believes that it is very important for the applicable entities to posses an Imminent Threat
Procedure. GRE recommends that the Imminent Threat procedure be renamed "Vegetation Imminent Threat
Procedure" so as to clearly identify the procedure in the event that a company has imminent threat procedures
for more than one situation.
Response: Thank you for your comment. We agree that many situations can constitute an imminent threat; however, the SDT did not rename the
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overall procedure as you have suggested. It is acceptable to have the imminent threat procedure for this standard included in a larger corporate
procedure or set of procedures that address a wider array of threats. Instead the requirement has been rewritten to focus on the main purpose of the
imminent threat requirement; which is to enhance the responsible control center’s situational awareness of reliability dangers to the power system.
Please note that this requirement’s wording has also been altered to change the designation “Transmission Operator” to the “responsible control
center” to better identify the appropriate party. The salient requirement of an imminent threat procedure is notification of the responsible operator of
any imminent threat to the power system. Beyond this, it is left to the Transmission Owner to determine the follow up activities and procedures that
best fit its situation. The SDT feels that this approach allows the Transmission Owner the flexibility to have imminent threat procedures for more than
one situation which remain outside the specific requirements of the vegetation Standards.
Santee Cooper
Agree
Exelon
Agree
Central Maine Power Company
Agree
WECC Reliability Coordination
Agree
Western Area Power
Administration, Upper Great
Plains Region
Agree
Kansas City Power & Light
Agree
City of Tallahassee
Agree
Northern California Power
Agency (NCPA)
Agree
Northern Indiana Public Service
Company
Agree
Long Island power Authority
Agree
National Grid
Agree
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Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
CenterPoint Energy
Agree
Buckeye Power, Inc.
Agree
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8. Requirement 1 section R1.5 replaces Version 1 sub-requirement R1.4. This section is now referred to as interim
corrective action process. This process addresses situations where vegetation maintenance activities cannot be
performed as planned. The term corrective action plan is used in lieu of mitigation plan to avoid confusion with other
uses in NERC of “mitigation plan”. Do you agree with R1.5? If not, please explain.
Summary Consideration: Many of the stakeholders asked about the use of the word “interim” in R1.5 and what a constraint
is. The SDT explains that 1.3 of the version 2 standard is intended to allow Transmission Owners to adjust the annual work plan
to reflect such changes as a long term fix. Part 1.5 is intended to address an interim constraint such as customer refusals,
governmental agency imposed restrictions, etc. To help clarify, the SDT added the word “temporarily” to the language noted in
requirement R1.5. The SDT also added a new requirement R1.6 to address long term strategies.
1.5
Specify an interim corrective action process for use when the Transmission Owner is temporarily constrained from
performing vegetation maintenance as planned.
1.6
Specify the maintenance strategies used (such as minimum vegetation-to-conductor distance or maximum vegetation
height) to ensure that Table 1 clearances in Attachment 1 are never violated. The maintenance strategies shall consider
the sag and sway of the conductor throughout its operating range under rated conditions.
Organization
Agree?
Question 8 Comment
The specifics of a "plan" as required by R1.4 in version 1 of the Standards has been replaced with the
generalities of a "process" required by R1.5 in version 2 of the Standards. At the time of an audit, the adequacy
of a general process is harder to measure than the adequacy of the specific mitigation measures that were
previously required by R1.4 in version 1 of the Standards. It is unclear what an auditor will be looking for to
determine compliance with R1.5 - will the auditor be looking for generalities or specifics? Further, if a utility has
documented their interim corrective action process, but it is not followed, is this a violation of the Standards?
Western Area Power
Administration, Rocky Mountain
Region
Response: Thank you for your comments. The SDT intended to require a documented process for Transmission Owners to develop plans which
address instances such as customer refusals, government agency imposed constraints, etc. It is not intended solely for situations where initial desired
clearances could not be achieved (as in requirement R1.4 of version 1 of FAC-003). The measure for Interim Corrective Action requires it be included in
the Transmission Vegetation Management Program and failure to do so would be a violation.
City of Tallahassee
September 8, 2009
Disagree
The use of the term "interim corrective action" implies that a permanent solution or return to the original plan
must be pursued. I would change this to "alternate maintenance" process to prevent non-compliance if the
Transmission Owner is constrained and has reached an agreement with the land owner that works to maintain
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the reliability of the line.
Response: Thank you for your comment. Requirement R1, Part 1.5 requires the Transmission Owner to specify a process in its Transmission
Vegetation Management Program that the Transmission Owner may use when vegetation maintenance work is temporarily constrained. Constraints
may include temporary situations such as caused by customer refusals, governmental agency imposed restrictions, etc. If a Transmission Owner
reaches an agreement for “alternate maintenance” in these situations, Requirement R1,Part 1.3.3 allows for adjustment of the annual work plan.
Alternative maintenance actions as suggested are now addressed in new Requirement R1,Part 1.6 as noted above in the consideration of comments to
address long term maintenance strategies to ensure Table 1 clearance distances are never violated.
Northern Indiana Public Service Disagree
Company
The existing R1.4 is focused on identifying where vegetation clearance objectives cannot be met at the time UVM
work is performed due to restrictions outside of the Transmission Owner's immediate control. The proposed
revised standard is focused on situations where work scheduled in the annual plan cannot be performed as
planned for any reason. Can a constraint on planned work be internal such as budget related? Why bother with a
corrective process for constrained planned work if the work not completed as planned poses no risk of causing
an outage? I strongly believe that the sole focus of this provision must specifically address individual locations
where, due to restrictions outside of the Transmission Owner owner's control, vegetation clearances specified in
the Transmission Vegetation Management Program cannot be obtained. This section of the standard should be
about trees being closer to conductors than they should be due to factors beyond the Transmission Owner's
control, rather than whether or not planned work was performed.
Response: Thank you for your comments. Interim corrective actions are intended to address situations such as customer refusals, governmental
agency imposed constraints, etc. Requirement R1, Part 1.3 requires that the annual work plan shall be documented and Requirement R1, Part 1.3.3
permits adjustments to the annual work plan. A Requirement R1, Part 1.6 was added to address long term maintenance strategies to ensure Table 1
clearance distances are never violated.
Tampa Electric Company
Disagree
The phrasing above references a "corrective action plan". However, the standard as written is stated as an
"interim corrective action process". These are not one and the same. Interim implies a truly temporary condition.
As described on page 21 of the Technical reference, however, some of these operational issues may not be
"interim".
Response: Thanks for your comments. The SDT agree that “interim” should have been included in the question. The Technical Reference document
does not appear to be in conflict with this. To add clarity the SDT added the word temporarily to Requirement R1, Part 1.5 and long term strategies are
addressed in new Requirement R1, Part 1.6 a to address long term maintenance strategies to ensure Table 1 clearance distances are never violated.
Manitoba Hydro
September 8, 2009
Disagree
Agree with the change in terminology - but would suggest that wording clarify that this is not only for situations
where the utility is unexpectedly prevented from implementing its annual plan - but also for areas where it is
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Question 8 Comment
unable to implement its clearance requirements due to property rights limitations.
Response: Thank you for your comment. Requirement R1, Part 1.5 requires the Transmission Owner to specify a process in its Transmission
Vegetation Management Program that the Transmission Owner may use when vegetation maintenance work is temporarily constrained. Constraints
may include temporary situations such as caused by customer refusals, governmental agency imposed restrictions, etc. Requirement R1, Part 1.6 was
added to address long term maintenance strategies to ensure Table 1 clearance distances are never violated.
National Grid
Disagree
National Grid agrees replacing mitigation plan with corrective action process. However, National Grid questions
the use of "interim" for a corrective action process in R1.5, and suggests striking "interim".
Response: Thank you for your comment. Requirement R1, Part 1.5 requires the Transmission Owner to specify a process in its Transmission
Vegetation Management Program that the Transmission Owner may use when vegetation maintenance work is temporarily constrained. Constraints
may include temporary situations such as caused by customer refusals, governmental agency imposed restrictions, etc. To add clarity the SDT added
the word “temporarily” to Requirement R1, Part 1.5.
CenterPoint Energy
Disagree
Since there is no longer a reference to defined clearances in the Standard, it is unclear under what specific
"constrained" conditions R1.5 applies. R1.5 does not have a sister requirement for implementation within the
Standard which implies it has a diminished value. R1.5 and M1.5 should be deleted as a requirement and
measure, but should be footnoted as best practice as was ANSI A300 in R1.1.
Response: Thank you for your comments. The SDT intended to require a documented process for Transmission Owners to develop plans which
address instances such as customer refusals, government agency imposed constraints, etc. It is not intended solely for situations where initial desired
clearances could not be achieved (as in requirement R1.4 of version 1 of FAC-003). A new Requirement R1, Part1.6 was added to address long term
maintenance strategies to ensure Table 1 clearance distances are never violated.
American Transmission
Company
Agree
ATC agrees with the concept but disagrees with the proposed language. ATC believes the term "interim" should
be removed from R 1.5. In some cases, a corrective action can end up being a long term/normal fix. Proposed
Language: Specify a corrective action process that will be used when established clearances or methodologies
are altered.
Response: Requirement R1, Part 1.3 requires that the annual work plan shall be documented. Requirement R1, Part 1.3.3 permits adjustments to the
annual work plan. A long term fix would be an adjustment to the annual work plan. In Requirement R1, Part 1.5, the SDT intended to require a
documented process for Transmission Owners to develop plans which address instances such as customer refusals, government agency imposed
constraints, etc. It is not intended solely for situations where initial desired clearances could not be achieved (as in requirement R1.4 of version 1 of
FAC-003). To add clarity the SDT added the word “temporarily” to Requirement R1, Part 1.5. Long term strategies are addressed in new requirement
R1.6 as noted above in the consideration of comments to address long term maintenance strategies to ensure Table 1 clearance distances are never
September 8, 2009
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Question 8 Comment
violated.
Southern California Edison
Company
Agree
Q8: SCE agrees in part with the revisions to R1.5, including the proposed phrase "corrective action process".
However, we do not believe it is necessary to include the term "Transmission Owner" in the sentence because
the entire standard is clearly applicable to Transmission Owners. SCE respectfully suggests that proposed R1.5
be revised to read: "Specify an interim corrective action process for use when planned vegetation maintenance is
deterred."
Response: Thank you for your comment. The SDT considered your suggested language and feels the language used in the draft standard is
appropriate in order to maintain consistency with other parts of the standard.
Western Utility Arborists
Agree
Yes, we agree.
Response: Thank you for your participation.
FirstEnergy
Agree
We agree with the concept of a corrective action plan. However, it is not clear what flexibility the Transmission
Owner is afforded in making adjustments to the work plan that may carry over from one calendar year to the next.
Legal issues with property owners or other factors may prevent the utility from carrying out the work plan as
scheduled. Also, we question the use of the term "constrained". It should be clear as to what constitutes
appropriate or valid constraints.
Response: Thank you for your comments. Requirement R1, Part 1.3.3 permits adjustments to the annual work plan. As to your next concern,
Requirement R1, Part 1.5 requires the Transmission Owner to specify a process in its Transmission Vegetation Management Program that the
Transmission Owner may use when vegetation maintenance work is temporarily constrained. Constraints may include temporary situations such as
caused by customer refusals, governmental agency imposed restrictions, etc. Refer to the Technical Reference document for additional information.
MRO NERC Standards Review
Subcommittee
Agree
The MRO believes that the term "interim" should be removed from R1.5. The term Interim is subjective.
Response: Thank you for your comment. The SDT uses “interim” to convey the temporary nature of these situations. To add clarity the SDT added the
word “temporarily” to Requirement R1. Part 1.5 and a new Requirement R1, Part 1.6 was added to address long term maintenance strategies to ensure
Table 1 clearance distances are never violated.
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 8
Response: Thank you for your participation.
September 8, 2009
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Platte River Power Authority
Agree?
Agree
Question 8 Comment
The term corrective action plan adds clarity.
Response: Thank you for your participation.
USDA Forest Service,
Agree
Southwestern Region, Regional
Office for AZ and NM
In my opinion, problems between the Transmission Owner and the USFS over the Transmission Vegetation
Management Program should be worked out before a Transmission Vegetation Management Program is ever
finalized. A dispute resolution process outside the control of either party would be very helpful and would
probably facilitate quicker solutions than if the Transmission Owner and the USFS are left to work out problems
on their own. If a Transmission Vegetation Management Program is prepared in a vacuum, the problems may not
come to light until some kind of outage actually occurs. It would be much better to flush any disagreements and
deal with them before any outages actually occur.
Response: Thank you for your comment. We agree with the sentiment of collaboration and cooperation expressed. We are somewhat constrained by
the types of entities that must be subject to this standard. The USFS, as a government agency, is not under the purview of the FERC and is not
compelled to comply with this standard however well intended. The SDT would support a dispute resolution process that resolves potential
disagreements consistent with the purpose of this standard.
BCTC
Agree
Yes, we agree.
Response: Thank you for your participation.
Great River Energy
Agree
GRE believes that the term "interim" should be removed from R1.5. The term Interim is subjective.
Response: Thank you for your comment. Requirement R1, Part 1.5 requires the Transmission Owner to specify a process in its Transmission
Vegetation Management Program that the Transmission Owner may use when vegetation maintenance work is temporarily constrained. Constraints
may include temporary situations such as caused by customer refusals, governmental agency imposed restrictions, etc. To add clarity the SDT added
the word temporarily to Requirement R1, Part 1.5 and long term strategies are addressed in new Requirement R1, Part1.6 to address long term
maintenance strategies to ensure Table 1 clearance distances are never violated.
Progress Energy Carolinas
Agree
Associated Electric Cooperative Agree
Inc.
NPCC
Agree
September 8, 2009
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Organization
Agree?
WECC Reliability Coordination
Agree
Western Area Power
Administration, Upper Great
Plains Region
Agree
SERC Vegetation Management
Subcommittee (VMS)
Agree
Progress Energy Florida
Agree
Kansas City Power & Light
Agree
SERC OC Standards Review
Group
Agree
Florida Power & Light
Agree
Santee Cooper
Agree
Southern Company
Agree
E.ON U.S.
Agree
Bonneville Power
Administration
Agree
Midwest ISO Stakeholders
Standards Collaborators
Agree
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
September 8, 2009
Question 8 Comment
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Organization
Agree?
Exelon
Agree
Central Maine Power Company
Agree
American Electric Power (AEP)
Agree
Northern California Power
Agency (NCPA)
Agree
Orange and Rockland Utilities
Inc.
Agree
Ameren
Agree
Nebraska Public Power District
Agree
Long Island power Authority
Agree
Consumers Energy Company
Agree
Pacific Gas & Electric Co.
Agree
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Agree
San Diego Gas & Electric
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
Consolidated Edison Company
of New York (CECONY)
Agree
September 8, 2009
Question 8 Comment
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Organization
Agree?
WECC
Agree
Arizona Public Service
Company
Agree
Baltimore Gas & Electric
Company
Agree
Duke Energy Corporation
Agree
Entergy Services
Agree
Pepco Holdings, Inc
Agree
JEA
Agree
Independent Electricity System
Operator
Agree
Salt River Project
Agree
Northeast Utilities
Agree
Hydro-Quebec Transenergie
(HQT)
Agree
Buckeye Power, Inc.
Agree
September 8, 2009
Question 8 Comment
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9. Clearance 1 in Version 1 was a “fill-in-the-blank” requirement and was removed from the standard. Do you agree? If
not, please explain.
Summary Consideration: Most of the industry comments are in favor of removing the “fill-in-the-blank” requirement. Some
disagreed, citing the benefit of having perceived leverage that a Clearance 1 afforded them. The SDT points out that ANSI A300
remains a “best practice” referenced in the proposed standard and may be useful in dealing with public and private parties. In
addition, the SDT added Requirement R1.6:
1.6
Specify the maintenance strategies used (such as minimum vegetation-to-conductor distance or maximum vegetation
height) to ensure that Table 1 clearances in Attachment 1 are never violated. The maintenance strategies shall consider
the sag and sway of the conductor throughout its operating range under rated conditions.
The SDT believes that Clearance 1 may be unnecessarily restrictive in stipulating conductor-to-vegetation distances (as some
commenters have done to comply) and therefore removed Clearance 1 in favor of Requirement R1, Part 1.6. which specifically
allows for vegetation-to-ground distances to be used while at the same time accounting for the sag and sway of the conductor
throughout its operating range under rated conditions.
Organization
Agree?
Florida Power & Light
Question 9 Comment
FPL neither agrees or disagrees with this removal but provides the following comment. FPL's experience
regarding Clearance 1 is that it was an effective way of demonstrating a measurable requirement for compliance
when dealing with public entities. The use of a corrective action process to mitigate instances where this
clearance was not met before violations occurred is also very effective in promoting reliability and safety in the
Standard.
Response: Thank you for your comment. The SDT team acknowledges the comment with regard to the usefulness of Clearance 1 in dealing with public
entities and has attempted to retain that capability in Requirement R1, Part 1.6. Furthermore the use of a corrective action process is retained in this
latest version but is renamed as an “interim correction action” in lieu of “Mitigation Plan” to avoid confusion with a Compliance Program term.
Western Utility Arborists
September 8, 2009
Disagree
The Western Utilities do not agree with the removal of Clearance 1. We recommend adding it back to the
document, but reworded and moved to include it as a measurement (M), rather than a requirement (R) under the
new standard. Many utilities feel that Clearance 1 provides justification and leverage for operational clearances
when dealing with organizations such as municipalities. Without Clearance 1, utilities could be mandated in
specific situations to clear so that the vegetation is just beyond the Critical Clearance Zone at all times. This
could result in pruning at six month intervals, which is not feasible or cost-effective.
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Question 9 Comment
Response: Thank you for your comment. The SDT notes that information contained in a Measure would not be mandatory nor enforceable and
therefore has minimal usefulness as leverage. The SDT points out that ANSI A300 remains a “best practice” referenced in the proposed standard and
may be useful in dealing with the public and private parties. The addition of Requirement R1, Part 1.6 allows for vegetation-to-ground working
distances to be used while at the same time accounting for the sag and sway of the conductor throughout its operating range under rated conditions.
The SDT believes this is superior to Clearance 1 as this gives Transmission Owners more flexibility in how they can achieve the reliability objective of
Requirement R1.
Bonneville Power Administration
Disagree
BPA opposes removal of Clearance 1. Clearance 1 provides a regulatory justification for a Transmission Owner
to apply and extend proactive vegetation threat prevention programs on its rights of way easements across
municipal, state, tribal, other federal and private properties. In many cases, without the regulatory leverage of a
Clearance 1 requirement, Transmission Owners would be limited to maintaining less effective and higher risk
vegetation management practices where it has legal restrictions, then it presently can implement under the
present version of FAC 003-01. BPA recommends that Clearance 1 be placed back into the document, but as a
Measure and not a Requirement.
Response: Thank you for your comment. The SDT notes that information contained in a Measure would not be mandatory nor enforceable and
therefore has minimal usefulness as leverage. The SDT points out that ANSI A300 remains a ”best practice” referenced in the proposed standard and
may be useful in dealing with the public and private parties. The addition of Requirement R1, Part 1.6 allows for vegetation-to-ground working
distances to be used while at the same time accounting for the sag and sway of the conductor throughout its operating range under rated conditions.
The SDT believes this is superior to Clearance 1 as this gives Transmission Owners more flexibility in how they can achieve the reliability objective of
Requirement R1.
Exelon
Disagree
We do not understand the reference to "fill in the blank" requirement for clearance 1. As commonly understood,
a "fill in the blank" standard /requirement is one that was assigned to the RRO. Clearance 1 in FAC-003-1 is a
Transmission Owner requirement. The reference to a clearing zone should be retained, as each Transmission
Owner will need to define this in their program so as to avoid encroachments into the Critical Clearance Zone .
Response: Thank you for your comment. The choice of a Clearance 1 distance is left to each Transmission Owner and as such is characterized as a
fill-in-the blank style requirement. The SDT team believes each Transmission Owner is free to set any working distances it deems appropriate in order
to accomplish its Transmission Vegetation Management Program objectives.
Central Maine Power Company
September 8, 2009
Disagree
Central Maine Power Company disagrees with removal of clearance 1. The clearance 1 was included so that
professional arborists could establish the clearance necessary for a transmission owner to reduce the risk of a
tree caused power outage. The transmission owner should use ANSI- Standard A300, including PART 7, and
other publications to develop best management practices which include clearances at time of maintenance.
Clearance 1 provides leverage for Transmission Owners to achieve the clearances stated in their Transmission
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Agree?
Question 9 Comment
Vegetation Management Program.
Response: Thank you for your comment. The SDT notes that information contained in a Measure would not be mandatory nor enforceable and
therefore has minimal usefulness as leverage. The SDT points out that ANSI A300 remains a ”best practice” referenced in the proposed standard and
may be useful in dealing with the public and private parties. The addition Requirement R1, Part 1.6 allows for vegetation-to-ground working distances
to be used while at the same time accounting for the sag and sway of the conductor throughout its operating range under rated conditions. The SDT
believes this is superior to Clearance 1 as this gives Transmission Owners more flexibility in how they can achieve the reliability objective of
Requirement R1.
USDA Forest Service,
Southwestern Region, Regional
Office for AZ and NM
Disagree
If it is possible for NERC to identify minimum clearance standards as related to arcing potential for hazardous
vegetation, it would definitely help USFS field administrators to have some kind of hard and fast standards. If
that kind of approach is not reasonable in light of the need to adjust standards for various load conditions and
vegetation growth rates, then a prescribed formula for calculating minimum clearances would be the next best
thing.
Response: Thank you for your comment. The SDT proposes the table of Minimum Vegetation Clearance Distances in this revised version of the
standard in Requirement R4, which prohibits vegetation encroachment inside minimum vegetation clearance distances that are developed with Gallet
equations for flashover (arcing).
National Grid
Disagree
National Grid takes exception to the term "fill-in-the-blank". National Grid disagrees with the elimination of
Clearance 1. The Clearance 1 requirement in FAC-003-1 was meant to allow a Transmission Owner to
establish clearances to be achieved at the time of vegetation management work, and be sensitive to local and
regional conditions. National Grid believes that Clearance 1 is needed for public education and safety reasons.
Clearance 1 standards allow utilities to specify a cyclic programmatic approach, and gives the utility leverage
with local and state regulators and the public to achieve significantly larger than minimal clearances.
Response: Thank you for your comment. The choice of a Clearance 1 distance is left to each Transmission Owner and as such is characterized as a
fill-in-the blank style requirement. The SDT team believes each Transmission Owner is free to set any working distances it deems appropriate in order
to accomplish its Transmission Vegetation Management Program objectives. The SDT points out that ANSI A300 remains a ”best practice” referenced
in the proposed standard and may continue to be useful in dealing with the public and private parties. The addition of Requirement R1, Part 1.6 allows
for vegetation-to-ground working distances which can be larger than minimal clearances to be used while at the same time accounting for the sag and
sway of the conductor throughout its operating range under rated conditions. The SDT believes this is superior to Clearance 1 as this gives
Transmission Owners more flexibility in how they can achieve the reliability objective of Requirement R1.
September 8, 2009
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Platte River Power Authority
Agree?
Disagree
Question 9 Comment
Clearance 1 could be defined in the standard in tables developed using IEEE Standards for various voltages,
line spans and altitudes. Clearance 1 provides justification and leverage for operational clearances when dealing
with organizations such as municipalities. Without Clearance 1, utilities could be mandated in specific situations
to clear so that the vegetation is just beyond the Critical Clearance Zone at all times. This could result in
pruning at six month intervals, which is not feasible or cost-effective.
Response: Thank you for your comment. The SDT proposes the table of Minimum Vegetation Clearance Distances in this revised version of the
standard in Requirement R4, which prohibits vegetation encroachment inside minimum vegetation clearance distances that are developed with Gallet
equations for flashover (arcing). The SDT points out that the ANSI A300 remains a ”best practice” referenced in the proposed standard and may be
useful in dealing with the public such as municipalities and private parties. The addition of Requirement R1, Part 1.6 allows for vegetation-to-ground
working distances to be used while at the same time accounting for the sag and sway of the conductor throughout its operating range under rated
conditions. The SDT believes this is superior to Clearance 1 as this gives Transmission Owners more flexibility in how they can achieve the reliability
objective of Requirement R1.
Northern Indiana Public Service
Company
Disagree
I am strongly opposed to the removal of Clearance 1 from the standard. Being able to point to this provision has
been invaluable to internal communications with upper management and external discussions with land owners
and the public concerning UVM. In fact, other than the patrol/inspection requirements, no other provision in the
standard has been as essential to preventing grow-in tree contacts than Clearance 1. It has forced
Transmission Owner's across the country to re-claim overgrown ROW and re-commit to consistent UVM
practices. We all know how easy it is for Transmission Owner's to get weak in the knees in the face of public
opposition to proper and prudent UVM work even when it is clear what needs to be done. This dynamic is what
led us to the 2003 blackout to begin with. I would like to see the drafting team consider expanding upon the
existing model and create three clearances:
1. A clearance at the time work is performed,
2. An action threshold clearance which would trigger the Transmission Owner would take immediate action to
clear encroaching vegetation posing an unacceptable outage risk, and
3. A no closer than clearance in which vegetation would never be allowed to encroach in order to prevent
flashover.
Response: Thank you for your comment. The SDT team acknowledges the comment with regard to the usefulness of Clearance 1 to internal
communications and in dealing with public entities and has attempted to retain that capability Requirement R1. Part 1.6. The addition of Requirement
R1, Part 1.6 allows for vegetation-to-ground working distances to be used while at the same time accounting for the sag and sway of the conductor
throughout its operating range under rated conditions. The SDT believes this is superior to Clearance 1 as this gives Transmission Owners more
flexibility in how they can achieve the reliability objective of Requirement R1.
September 8, 2009
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Organization
Agree?
Question 9 Comment
In regard to working distances or as you put it , each Transmission Owner continues to able to set any working distances it deems appropriate in order
to accomplish its Transmission Vegetation Management Program objectives when complying with Requirement R1, Part 1.6.
With respect to your 3rd comment, the proposed version of the standard has Requirement R4, which prohibits vegetation encroachment inside
Minimum Vegetation Clearance Distances that are developed with Gallet equations for flashover.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Disagree
We do not agree with the removal of Clearance 1. We recommend adding it back to the document, but reworded
and moved to include it as a measurement (M), rather than a requirement (R) under the new standard. Many
utilities feel that Clearance 1 provides justification and leverage for operational clearances when dealing with
organizations such as municipalities. Without Clearance 1, utilities could be mandated in specific situations to
clear so that the vegetation is just beyond the Critical Clearance Zone at all times. This could result in pruning
at six month intervals, which is not feasible or cost-effective.
Response: Thank you for your comment. The SDT notes that information contained in a Measure would not be mandatory nor enforceable and
therefore has minimal usefulness as leverage. The SDT points out that ANSI A300 remains a “Best Practice” referenced in the proposed standard and
may be useful in dealing with the public and private parties. The addition of Requirement R1, Part 1.6 allows for vegetation-to-ground working
distances to be used while at the same time accounting for the sag and sway of the conductor throughout its operating range under rated conditions.
The SDT believes this is superior to Clearance 1 as this gives Transmission Owners more flexibility in how they can achieve the reliability objective of
Requirement R1.
San Diego Gas & Electric
Disagree
We do not agree with the removal of Clearance 1. We recommend that it be added back into the document, but
reworded and moved so it be included as a measurement, rather than a requirement. Without Clearance 1,
utilities could be mandated in specific situations to clear so that vegetation is just beyond the Critical Clearance
Zone at all times, which is not feasible or cost effective.
Response: Thank you for your comment. The SDT notes that information contained in a Measure would not be mandatory nor enforceable and
therefore has minimal usefulness as leverage. The SDT points out that ANSI A300 remains a “Best Practice” referenced in the proposed standard and
may be useful in dealing with the public and private parties. The addition of Requirement R1, Paart 1.6 allows for vegetation-to-ground working
distances to be used while at the same time accounting for the sag and sway of the conductor throughout its operating range under rated conditions.
The SDT believes this is superior to Clearance 1 as this gives Transmission Owners more flexibility in how they can achieve the reliability objective of
Requirement R1.
Hydro One Networks Inc.
September 8, 2009
Disagree
We would agree only if the standard is revised to include the removal of incompatible vegetation as outlined in
our response to question 3 above. If not, then added direction or requirements are needed to introduce the
elements that combine (to a greater degree than exists under the revised standard) reliability and vegetation
management. Clearance 1 accomplished this to some degree.
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Organization
Agree?
Question 9 Comment
Response: Thank you for your comment. The SDT considered the insertion of the phrase “incompatible vegetation” however decided against it
because incompatibility may be arguable and add to disagreement among interested parties. The SDT agrees with the commenter that all vegetation
that is identified by the annual work plans and maintenance strategies should be targeted for removal. Each Transmission Owner is free to use any
effective approach it deems appropriate in order to accomplish its Transmission Vegetation Management Program objectives. The proposed version
of the standard has Requirement R4, which prohibits vegetation encroachment inside Minimum Vegetation Clearance Distances that are developed
with Gallet equations for flashover.
Arizona Public Service Company
Disagree
APS disagrees with removal of clearance one. Clearance one should be achieved at time of maintenance which
is part of the vegetation program. This gives leverage with dealing with state and federal agencies, tribal and
private landowners. This isn't a fill in the blank requirement, however it should be based on sound science in
regards to vegetation management. A professional arborist/forester can determine the appropriate amount of
vegetation that needs to be obtained at the time of maintenance. APS suggest the following language change
for clearance 1. The Transmission Owner shall maintain ROW on Federal, State, Tribal and Private lands in
accordance with ANSI-Standard A300 (Part 1)-2001 and (Part 7)-2006 in consultation with companion
publication Best Management Practices: Integrated Vegetation Management, 2007. If all utilities followed this
standard this would increase the reliability of the bulk electric system and reduce the risk of vegetation outages.
Response: Thank you for your comment. The SDT agrees that any requirement must be based on sound science and believes the Transmission Owner
will continue to able to set any working distances it deems appropriate in order to accomplish its Transmission Vegetation Management Program
objectives when complying with Requirement R1, Part 1.6. The stipulation that the Standard applies to Federal, State, Tribal and Private Lands is
contained in the Applicability section. The SDT points out that ANSI A300 remains a “best practice” referenced in this standard and as such may be
useful in dealing with state and federal agencies, tribal and private landowners, etc.
BCTC
Disagree
BCTC do not agree with the removal of Clearance 1. We recommend adding it back to the document, but
reworded and moved to include it as a measurement (M), rather than a requirement (R) under the new standard.
Many utilities feel that Clearance 1 provides justification and leverage for operational clearances when dealing
with organizations such as municipalities. Without Clearance 1, utilities could be mandated in specific situations
to clear so that the vegetation is just beyond the Critical Clearance Zone at all times. This could result in
pruning at six month intervals, which is not feasible or cost-effective.
Response: Thank you for your comment. The SDT notes that information contained in a Measure would not be mandatory nor enforceable and
therefore has minimal usefulness as leverage. The SDT points out that ANSI A300 remains a ”best practice” referenced in the proposed standard and
may be useful in dealing with the public and private parties. The addition of Requirement R1, Part 1.6 allows for vegetation-to-ground working
distances to be used while at the same time accounting for the sag and sway of the conductor throughout its operating range under rated conditions.
The SDT believes this is superior to Clearance 1 as this gives Transmission Owners more flexibility in how they can achieve the reliability objective of
Requirement R1.
September 8, 2009
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Organization
Salt River Project
Agree?
Disagree
Question 9 Comment
Recommend adding it back to the document, however, only if it is changed to become a measurement (M)
rather than a requirement (R). Leaving it in as a measurement provides justification and leverage for operational
clearances when dealing with landowners. Without Clearance 1 landowners may only allow vegetation
clearance just at the Critical Clearance Zone at all times, which is not a feasible, cost-effective, or responsible
way for utilities to manage vegetation clearance.
Response: Thank you for your comment. The SDT notes that information contained in a Measure would not be mandatory nor enforceable and
therefore has minimal usefulness as leverage. The SDT points out that ANSI A300 remains a “best practice” referenced in the proposed standard and
may be useful in dealing with the public and private parties. The addition of Requirement R1, Part 1.6 allows for vegetation-to-ground working
distances to be used while at the same time accounting for the sag and sway of the conductor throughout its operating range under rated conditions.
The SDT believes this is superior to Clearance 1 as this gives Transmission Owners more flexibility in how they can achieve the reliability objective of
Requirement R1.
American Electric Power (AEP)
Agree
AEP agrees with the removal of Clearance 1 from the Standard.
Response: Thank you for your comment.
NPCC
Agree
We agree but believe that the Transmission Vegetation Management Program should target removal of all
incompatible vegetation on the Active Right of Way as described in the response to question 3.
Response: Thank you for your comment. The SDT agrees with the commenter that any vegetation located within the Active Transmission Line ROW
should be targeted for removal using means and strategies described in its Transmission Vegetation Management Program.
Western Area Power
Administration, Upper Great
Plains Region
Agree
While Western (UGPR) agrees with the removal of Clearance 1, we believe it is advantageous for Transmission
Owners to have a "trigger distance" in order to have some additional time to plan and schedule vegetation work.
The trigger distance is advantageous only if the Regulators do NOT interpret it to be an extended Critical
Clearance Zone and do NOT enforce based on "trigger distance" instead of the Critical Clearance Zone .
Response: Thank you for your comment. The SDT team believes the addition of Requirement R1, Part 1.6 continues to allow each Transmission Owner
to set any working distances it deems appropriate in order to accomplish the objectives with this Standard. This Requirement 1 Part 1.6 is superior to
Clearance 1 as it gives Transmission Owners more flexibility in how they can achieve the reliability objective of Requirement R1.
MRO NERC Standards Review
Subcommittee
September 8, 2009
Agree
The MRO agrees and fully supports the removal of Clearance 1. The MRO believes that the Gallet equation is a
more effective way of determining the required clearances.
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Organization
Agree?
Question 9 Comment
Response: Thank you for your comment.
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 9
Response: Thank you for your comment.
Orange and Rockland Utilities
Inc.
Agree
We generally agree, however please see comments included in question 18.
Response: Thank you for your comment.
Baltimore Gas & Electric
Company
Agree
While I may agree with the removal of this requirement strictly for reasons of simplification and selfdetermination, the current requirement forced utilities to structure their Transmission Vegetation Management
Program to develop safeguards to keep trees from encroaching into the Clearance 2 envelope. The proposed
change will leave the clearance issue beyond the Critical Clearance Zone unaddressed. Responsible utilities
will take the appropriate measures and other utilities will not.
Response: Thank you for your comment. Each Transmission Owner is free to use any effective approach it deems appropriate in order to accomplish
its Transmission Vegetation Management Program objectives. The SDT believes there are significant disincentives against the behavior you warn
about in the revised version.
CenterPoint Energy
Agree
Designation of Clearance 1 is not required to meet the purpose of the Standard.
Response: Thank you for your comment.
Hydro-Quebec Transenergie
(HQT)
Agree
We agree but believe that the Transmission Vegetation Management Program should target removal of all
incompatible vegetation on the Active Right of Way as described in the response to question 3.
Response: Thank you for your comment. The SDT agrees with the commenter that any vegetation that are located within the Active Transmission Line
ROW should be targeted for removal using means and strategies described in its Transmission Vegetation Management Program.
Great River Energy
Agree
GRE agrees and fully supports the removal of Clearance 1. GRE believes that the Gallet equation is a more
effective way of determining the required clearances.
Response: Thank you for your comment.
September 8, 2009
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Organization
Agree?
Southern California Edison
Company
Agree
Associated Electric Cooperative
Inc.
Agree
WECC Reliability Coordination
Agree
SERC Vegetation Management
Subcommittee (VMS)
Agree
Progress Energy Florida
Agree
Kansas City Power & Light
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Progress Energy Carolinas
Agree
SERC OC Standards Review
Group
Agree
Santee Cooper
Agree
Southern Company
Agree
E.ON U.S.
Agree
FirstEnergy
Agree
Midwest ISO Stakeholders
Standards Collaborators
Agree
September 8, 2009
Question 9 Comment
Q9: No comments.
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Organization
Agree?
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
City of Tallahassee
Agree
Northern California Power
Agency (NCPA)
Agree
Tampa Electric Company
Agree
Question 9 Comment
American Transmission Company Agree
Ameren
Agree
Nebraska Public Power District
Agree
Long Island power Authority
Agree
Manitoba Hydro
Agree
Consumers Energy Company
Agree
Pacific Gas & Electric Co.
Agree
Edison Electric Institute
Agree
Consolidated Edison Company of
New York (CECONY)
Agree
WECC
Agree
Entergy Services
Agree
September 8, 2009
119
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Organization
Agree?
Pepco Holdings, Inc
Agree
JEA
Agree
Northeast Utilities
Agree
Independent Electricity System
Operator
Agree
Duke Energy Corporation
Agree
Buckeye Power, Inc.
Agree
September 8, 2009
Question 9 Comment
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
10. Personnel Qualifications in R1.3 in Version 1 was a “fill-in-the-blank” requirement and was removed from Version 2 of
the standard. Do you agree? If not please explain.
Summary Consideration: Most commenters agree with the deletion of R1.3 from the approved standard. The” fill in the
blank” requirement that was included in version 1 allowed the Transmission Owner to set its own standard for personnel
qualifications rather than require the same set of qualifications for personnel in all entities. The SDT recommended removing
the requirement as it is not enforceable and recommended against replacing the “fill-in-the-blank” element with a continentwide set of personnel qualifications. The SDT believes that any set of personnel qualifications enforced on a continent-wide
basis would result in a set of “lowest common denominator” qualifications that would be too stringent for some entities, and too
lax for others – with no apparent reliability benefit. Instead, the SDT recommended letting entities set their own internal
personnel qualifications to best meet their own needs.
Organization
Central Maine Power Company
Agree?
Disagree
Question 10 Comment
Central Maine Power Company disagrees with the removal of the qualification statement. The individual
responsible for this critical program must be qualified through experience, training, and education. The
International Society of Arboriculture has a certification program that can help with guidelines for qualified
arborists.
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
Northern Indiana Public Service
Company
Disagree
If the standard continues to allow T.O.’s to design and implement their own TVMPs and expect them to use
BMPs, ANSI A300, develop methods and practices, adapt schedules and plans to changing conditions, etc.,
then it is reasonable to expect that T.O. personnel responsible for the TVMP to be experts in the field of utility
vegetation management with appropriate training, certifications, licenses and credentials. I do not agree with
eliminating this requirement. Quite the opposite, I believe that the requirement needs to be more specific as to
minimum qualifications key personnel must meet. There are more requirements & qualifications to drive a
semi-truck than to design and implement a program (UVM) critical to the operation of the nation’s electric grid.
Does that make sense?
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
USDA Forest Service,
Southwestern Region, Regional
September 8, 2009
Disagree
Perhaps standard M8 could be expanded or clarified to require the Transmission Owner to describe how
employees, especially field supervisors, are trained to implement the plan and to prove that the training was
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Organization
Agree?
Office for AZ and NM
Question 10 Comment
actually provided. Some problems have arisen in the USFS Southwestern Region because some Transmission
Owners are not providing adequate supervision of field work.
Response: The SDT thanks you for your comment. The requirement that was dropped between the version 1 and version 2 spoke to the qualifications
of development and implementation of the TVMP and not the adequacy of the field supervision. This does not relieve the TO from providing adequate
field supervision.
National Grid
Disagree
National Grid takes exception to the term “fill-in-the-blank”. National Grid would like Personnel Qualifications
to remain in Standard FAC-003-2.
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
San Diego Gas & Electric
Disagree
We feel there must be appropriate knowledge to do the work, and that Transmission Owners must at least
have internal standards related to personnel qualifications.
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
Arizona Public Service
Company
Disagree
APS disagrees with the removal of personnel qualifications. The person responsible for vegetation
management program should have experience and training in vegetation management and system operations.
The International Society of Arboriculture has an ISA Certified Arborist and Utility Specialist certification. This
requires the credential holder to have minimal qualifications before sitting for the certification and on going
training to maintain the credential. The industry has already responded by providing the information as part of
the current standard FAC-003-1. It makes no sense to remove personnel qualifications from the revision.
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
British Columbia Transmission
Corp.
Disagree
BCTC does not agree with the elimination of this requirement. We feel strongly there must be appropriate
knowledge to do the work, and that Transmission Owners must have internal standards related to personnel
qualifications. We understand that several utilities would like this requirement removed because it created
problems in the auditing process. It is unfortunate that this important requirement for an effective vegetation
management program has been removed due misapplication of the intent during audits.
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
September 8, 2009
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Organization
Agree?
Question 10 Comment
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
Central Maine Power Company
Disagree
Central Maine Power Company disagrees with the removal of the qualification statement. The individual
responsible for this critical program must be qualified through experience, training, and education. The
International Society of Arboriculture has a certification program that can help with guidelines for qualified
arborists.
Response: The SDT thanks you for your response. While we agree that the International Society of Arboriculture certifications are credible
qualifications for a large work force, these same programs may be too stringent and unnecessary for utilities only needing a very small work force.
It is unknown if certification by ISA or similar organizations has impacted reliability for any Transmission Owner.
Northern Indiana Public Service
Company
Disagree
If the standard continues to allow T.O.’s to design and implement their own Transmission Vegetation
Management Programs and expect them to use BMPs, ANSI A300, develop methods and practices, adapt
schedules and plans to changing conditions, etc., then it is reasonable to expect that T.O. personnel
responsible for the Transmission Vegetation Management Program to be experts in the field of utility
vegetation management with appropriate training, certifications, licenses and credentials. I do not agree with
eliminating this requirement. Quite the opposite, I believe that the requirement needs to be more specific as to
minimum qualifications key personnel must meet. There are more requirements & qualifications to drive a
semi-truck than to design and implement a program (UVM) critical to the operation of the nation’s electric grid.
Does that make sense?
Response: The SDT thanks you for your response. The SDT concurs that some Transmission Vegetation Management Programs are highly complex
and would require highly trained arborists and vegetation management personnel to develop such programs. However, there are many programs that
are substantially less complex and do not require that level of expertise. We feel that utilities with complex programs would by nature acquire
appropriately trained personnel to implement their programs.
USDA Forest Service,
Southwestern Region, Regional
Office for AZ and NM
Disagree
Perhaps standard M8 could be expanded or clarified to require the Transmission Owner to describe how
employees, especially field supervisors, are trained to implement the plan and to prove that the training was
actually provided. Some problems have arisen in the USFS Southwestern Region because some Transmission
Owners are not providing adequate supervision of field work.
Response: The SDT thanks you for your comment. The requirement that was dropped between the version 1 and version 2 spoke to the qualifications
of development and implementation of the Transmission Vegetation Management Program and not the adequacy of the field supervision.
National Grid
September 8, 2009
Disagree
National Grid takes exception to the term “fill-in-the-blank”. National Grid would like Personnel Qualifications
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Organization
Agree?
Question 10 Comment
to remain in Standard FAC-003-2.
Response: The SDT thanks you for your response. A” fill in the blank” requirement as stated in version 1 allowed the Transmission Owner to set its
own standard and does not substantively add to the effectiveness of the Standard.
British Columbia Transmission
Corp.
Disagree
BCTC does not agree with the elimination of this requirement. We feel strongly there must be appropriate
knowledge to do the work, and that Transmission Owners must have internal standards related to personnel
qualifications. We understand that several utilities would like this requirement removed because it created
problems in the auditing process. It is unfortunate that this important requirement for an effective vegetation
management program has been removed due misapplication of the intent during audits.
Response: The SDT thanks you for your response. A” fill in the blank” requirement as stated in version 1 allowed the Transmission Owner to set its
own standard and does not substantively add to the effectiveness of the Standard.
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 10
Response: The SDT thanks you for your response.
Exelon
Agree
Agree but same comment as above, we do not understand the reference to “fill in the blank” requirement for
R1.3. As commonly understood, a “fill in the blank” standard /requirement is one that was assigned to the
RRO.
Response: The SDT thanks you for your response. A” fill in the blank” requirement as stated in version 1 allowed the TO to set its own standard as
opposed to RRO. In either case the concept of a “fill in the blank requirement” does not substantively add to the effectiveness of the Standard.
Tampa Electric Company
Agree
While we agree with the removal of “fill-in the blank” requirements, we recommend the inclusion of professional
qualifications for staff involved in this Standard. Reading the 42 page technical reference and the attached
comment form, all involved need to really understand the Standard as well as industry practices.
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
Baltimore Gas & Electric
Company
September 8, 2009
Agree
Similar to the response to no. 9, the end result is what counts and each utility will be responsible and
accountable for their actions. Qualifications unlike clearance requirements, are far-removed from results and
can easily be left unaddressed in the new std.
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Organization
Agree?
Question 10 Comment
Response: The SDT thanks you for your response.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Agree
We are in agreement with the elimination of this requirement, but not without some qualifications. We feel
strongly there must be appropriate knowledge to do the work, and that Transmission Owners must at least
have internal standards related to personnel qualifications. It is unfortunate that this important requirement for
an effective vegetation management program has been removed due to concerns with the auditing program.
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
CenterPoint Energy
Agree
Designation of Personnel Qualifications are not required to meet the purpose of the Standard.
Response: The SDT thanks you for your response.
American Electric Power (AEP)
Agree
AEP agrees that the Standard should not stipulate or require personnel qualifications.
Response: The SDT thanks you for your response.
Platte River Power Authority
Agree
The requirement should be removed because it is a “fill-in-the-blank” requirement. Defining the proper amount
of personnel qualifications and training would be too prescriptive for utilities with small vegetation management
programs and not prescriptive enough for utilities with large vegetation management programs.
Response: The SDT thanks you for your comments.
Western Utility Arborists
Agree
The Western Utilities are in agreement with the elimination of this requirement. However, we feel strongly there
must be appropriate knowledge to do the work, and that Transmission Owners must at least have internal
standards related to personnel qualifications.
Response: The SDT thanks you for your response. Internal standards related to personnel qualifications, while not a requirement of the Standard,
remain the internal responsibility of the Transmission Owner in the overall context of complying with the requirements of FAC-003-2.
Southern California Edison
Company
Agree
SERC OC Standards Review
Agree
September 8, 2009
Q10: No comments.
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Organization
Agree?
Question 10 Comment
Group
Florida Power & Light
Agree
Santee Cooper
Agree
Progress Energy Carolinas
Agree
SERC Vegetation Management
Subcommittee (VMS)
Agree
Progress Energy Florida
Agree
Kansas City Power & Light
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
City of Tallahassee
Agree
Northern California Power
Agency (NCPA)
Agree
Long Island power Authority
Agree
Manitoba Hydro
Agree
Consumers Energy Company
Agree
Pacific Gas & Electric Co.
Agree
Duke Energy Corporation
Agree
Associated Electric Cooperative Agree
September 8, 2009
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Organization
Agree?
Question 10 Comment
Inc.
NPCC
Agree
WECC Reliability Coordination
Agree
Western Area Power
Administration, Upper Great
Plains Region
Agree
Orange and Rockland Utilities
Inc.
Agree
American Transmission
Company
Agree
Ameren
Agree
Nebraska Public Power District
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
Consolidated Edison Company
of New York (CECONY)
Agree
WECC
Agree
Entergy Services
Agree
Pepco Holdings, Inc
Agree
JEA
Agree
September 8, 2009
127
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Organization
Agree?
Independent Electricity System
Operator
Agree
Salt River Project
Agree
Northeast Utilities
Agree
Hydro-Quebec Transenergie
(HQT)
Agree
Buckeye Power, Inc.
Agree
Great River Energy
Agree
Southern Company
Agree
E.ON U.S.
Agree
Bonneville Power
Administration
Agree
FirstEnergy
Agree
MRO NERC Standards Review
Subcommittee
Agree
Midwest ISO Stakeholders
Standards Collaborators
Agree
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
September 8, 2009
Question 10 Comment
128
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
11. The IEEE 516 standard distances were replaced with the Gallet equation distances. Clearance 2 was replaced by the
Critical Clearance Zone. The Critical Clearance Zone is defined as the zone of all possible positions of the conductor
at the line’s designed operating ratings including wind factors. (Please refer to pages 22-32 in the Technical
Reference Document on the Critical Clearance Zone for further background for this question.) The imminent threat
procedure, R2, requires action to be taken to prevent an outage when the Critical Clearance Zone is approached. Do
you agree with R2? If not please explain.
Summary Consideration: The majority of responders (61%) disagreed with the concept of the imminent threat procedure
being associated with the Critical Clearance Zone (CCZ). The key concerns that commenters raised were associated with the
Critical Clearance Zone and included the following:
•
It is a good concept but is theoretical and difficult to administer in the field
•
Respondents preferred a more defined distance that is real-time and measurable
•
The word "approach" caused concern due to being vague and open to interpretation
Although there was no clear minority view, a number of respondents recommended eliminating R2 or R4 because of practical
difficulties associated with the CCZ and their belief that R5, R6, and R7 were sufficient to achieve reliability
In response, the SDT modified R2 so that it does not use the CCZ to trigger the imminent threat procedure implementation. R2
now requires the Transmission Owner to implement its imminent threat procedure when it has knowledge of such a threat
obtained through normal operating procedures. The SDT decided not to be prescriptive in the definition of a vegetation
imminent threat. Rather, the Transmission Owner should have the flexibility of defining its own procedure per the TVMP. In
addition R4 has been modified and now requires the Transmission Owner to prevent vegetation encroachment of the Minimum
Vegetation Clearance Distances (MVCD) as observed in real time and eliminates the use of the CCZ for this purpose.
R2. Each Transmission Owner shall implement its imminent threat procedure when the Transmission Owner has actual knowledge of
such a threat, obtained through normal operating practices.
Organization
BCTC
Agree?
Formatted: Indent: Left: 0",
Pattern: Clear (Custom
Color(RGB(211,220,233)))
Question 11 Comment
BCTC feels that changing to the Gallet equation will not have a large impact on its vegetation management
operations, so we have no concerns.
We agree with R2, but feel that this clause makes R4 redundant, as per our discussion under Comment # 15
below. We recommend the removal of R4 entirely from the standard.
September 8, 2009
Deleted: or notification from others,
that the Critical Clearance Zone is
approached by vegetation to prevent an
encroachment of the Critical Clearance
Zone.
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Organization
Agree?
Question 11 Comment
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
Western Utility Arborists
The Western Utilities feel that changing to the Gallet equation will not have a large impact on its vegetation
management operations, so we have no concerns. We agree with R2, but feel that this clause makes R4
redundant, as per our discussion under Comment # 15 below. We recommend the removal of R4 entirely from
the standard.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat upon discovery of such a threat. The Critical Clearance Zone has been replaced with Minimum Vegetation
Clearance Distance (MCVD) in R4.
Associated Electric
Cooperative Inc.
Disagree
The phrase “Critical Clearance Zone is approached” in R2 is nebulous and probably unenforceable. The
determination and visualization of the Critical Clearance Zone and approaching vegetation encroachment,
under field conditions, is a practice in application of theoretical conductor locations in real time. Would the
Transmission Owner be found in noncompliance if evidence showed vegetation had “approached” within 20
feet, 2 feet, 2 inches or some other arbitrary distance of the CCZ and the TO failed to implement its imminent
threat procedure?
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
Western Area Power
Administration, Upper Great
Plains Region
September 8, 2009
Disagree
The CCZ as defined would very specifically outline a zone that needs to remain clear of vegetation to avoid a
violation, but that specificity could be an overly burdensome concept to implement and/or monitor.
Theoretically, there could be an infinite number of allowable vertical and horizontal (for outside phases)
clearances depending on your location within each span. Theoretically, you may need to clear cut at midspan (depending on retreatment intervals, growth rate, etc.) while allowing a 40 foot tree closer to the
structure, along with everything in between depending on your location within the span. To fully comply with
the CCZ as defined, each Transmission Owner would have to have a table of allowable vertical and horizontal
clearances for every few feet on every available span length within each line section. Producing such tables
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Organization
Agree?
Question 11 Comment
would be a significant burden to each Transmission Owner, but without them, the Transmission Owner could
not verify that vegetation had not encroached within the CCZ. In order to produce the tables outlined above,
the Transmission Owner would need to identify what design parameter(s) are applicable for the "correct"
CCZ? We remain concerned that weather conditions in excess of those parameters could lead to a
vegetation contact/outage and proving that weather conditions were in excess of design criteria would be
extremely difficult or impossible for all spans on a lengthy transmission line. It is not uncommon to have
weather stations 50 or more miles away from points on our transmission system. In order to certify/verify
compliance, the Transmission Owner would have to physically take their table to the field and verify vertical
and horizontal clearances from the edge of the theoretical envelope (not the actual conductor position) for all
vegetation within the span. This would be a time-consuming, burdensome, cumbersome process if
Regulators are going to require specific evidence in order for the Transmission Owner to document their
annual certification.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat upon discovery of such a threat. The Critical Clearance Zone
has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
SERC Vegetation
Management Subcommittee
(VMS)
Disagree
The SERC VMS recommends that R2 be deleted. Since this is a "zero tolerance" standard any Transmission
Owner will remove any discovered threats to prevent outages. While we agree that the implementation of an
imminent threat procedure may be a valid concept, visualization of the Critical Clearance Zone (CCZ) and
determining an approaching encroachment is a practice in application of theoretical conductor locations in real
time.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
Progress Energy Florida
Disagree
The Critical Clearance Zone as currently defined is too academic. Implementation of R2 would require field
operations staff to determine the theoretical position of the line during inspections to decide whether to
engage the imminent threat procedures. The academic/theoretical aspects of the Critical Clearance Zone
definition are not practical or enforceable. The criteria for a violation needs to be limited to the position of the
conductor in real time.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat upon discovery of such a
threat. The Critical Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
September 8, 2009
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Organization
Western Area Power
Administration, Rocky
Mountain Region
Agree?
Disagree
Question 11 Comment
As discussed in the Technical Reference document, the CCZ is a complicated theoretical envelope
surrounding all rated operating positions of the conductor. Its dynamic shape is constantly changing and is
contingent upon location within the span. Calculation of the size and shape of CCZ is based, in part, upon the
design parameters of the transmission facility. However, as-built or long term maintenance conditions can
often diverge from the original design requirements over time. Ground elevations can also change as a result
of man made or natural causes from the original design elevations recorded on plan and profile engineering
drawings. Consequently, precise field measurement of the as-built CCZ is extremely problematic and
strategies that utilize the calculation of allowable right-of-way tree heights can be hindered by unrecorded
deviations from the original design criteria. Allowable tree height strategies also become increasingly more
difficult and impractical with increasing extremes in terrain. While the CCZ is a very important concept for an
effective vegetation management program it is far to theoretical, dynamic, and impractical to field measure for
use as a clear and precise boundary for regulatory purposes. In addition, the R2 requirement for action when
the imprecise and theoretical CCZ boundary is "approached" by vegetation is an even more subjective and
unmeasurable. The "rate of approach" is really the key issue of concern. The rate of vegetation approach is
a function of many variables including species type and site specific growing conditions. For example, a
Century Plant which can grow six inches a day is obviously a much greater concern than a Lodgepole Pine on
a dry mountain top which grows only a few inches a year. As such, there is no practical way to define or
measure for regulatory purposes those "approach" situations that legitimately require immediate action from
those "approach" situations that do not. The wording and concepts of R2 are therefore to imprecise to be
used as clear requirements for Standards compliance.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat upon discovery of such a threat. The Critical Clearance Zone
has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
Progress Energy Carolinas
Disagree
The Critical Clearance Zone as currently defined is too academic. Implementation of R2 would require field
operations staff to determine the theoretical position of the line during inspections to decide whether to
engage the imminent threat procedures. The academic/theoretical aspects of the Critical Clearance Zone
definition are not practical or enforceable. The criteria for a violation needs to be limited to the position of the
conductor in real time.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat upon discovery of such a threat. The Critical Clearance Zone
has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
SERC OC Standards Review
September 8, 2009
Disagree
The SERC OCSRG recommends that R2 be deleted. Since this is a "zero tolerance" standard any
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Agree?
Group
Question 11 Comment
Transmission Owner will remove any discovered threats to prevent outages. While we agree that the
implementation of an imminent threat procedure may be a valid concept, visualization of the Critical Clearance
Zone and determining an approaching encroachment is a practice in application of theoretical conductor
locations in real time.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
Florida Power & Light
Disagree
FPL agrees that the Gallet equation is a better method to determine a Critical Clearance Zone. However, FPL
does not agree with the application of the zone for several reasons outlined below. ? There are many
environmental and engineering variables and assumptions included in the calculation of the Critical Clearance
Zone. ? These assumptions are not clearly defined in the standard. ? Unless there is a significant
intrusion into the Critical Clearance Zone, an engineer and surveyor would be necessary at all times to
determine a violation. ? The success of this standard lies with a standard the field personnel can
implement. When making actual trimming or removal decisions, the field personnel are not adequately skilled
to do much more than make a rough guess at the Critical Clearance Zone. This standard must establish
measurable and auditable parameters for field operations. ? In Requirement R2, determination of when to
activate the Imminent Threat Procedure becomes unclear due to the difficulty in determining when the Critical
Clearance Zone is encroached.
? As written, off ROW trees falling through the Critical Clearance Zone
become a violation of Requirement R4. Unless an outage occurred, how would the utility determine that a
violation occurred? In FAC 003-1 an outage of this nature is defined as Category 3 and is not a violation.
Since fall-in tree interruptions have never been contributors to cascading events or blackouts they should not
be a violation of a NERC standard. Consequently, as written, it is highly questionable whether this Standard is
sufficiently specific and clear to be enforceable. The many questions and levels of confusion introduced with
the application of the Critical Clearance Zone concept suggests that neither the industry nor NERC will ever
know if compliance is met. Such a high level of ambiguity requires that the Critical Clearance Zone concept
be revisited and most likely replaced with a measure that is workable for both the industry and NERC. To
further this effort, FPL has outlined some alternative suggestions described in the answer to question 18.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
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Southern Company
Agree?
Disagree
Question 11 Comment
As written, R2 requires activation of the imminent threat process when the Critical Clearance Zone (CCZ) is
"approached" by vegetation. The term "approach" is vague and open to interpretation. Since vegetation is
dynamic in nature, it is constantly "approaching" any pre-defined zone. There could also be many examples
given of encroachments into the theoretical CCZ that would neither threaten the transmission line conductor
nor cause a reduction in the capacity of the transmission line. This concept would be better suited to be a
“trigger point” that, if found, would be incentive for the Transmission Owner to take immediate action or ensure
future action occurs on schedule. This action may be as urgent as implementation of the immediate threat
procedure or as non-urgent as making sure that the upcoming maintenance on that line is scheduled
appropriately. We are concerned this revision of FAC-003 continues to take a zero tolerance approach to
compliance, which is contrary to the philosophy utilized in other NERC standards. A state of non-compliance
should not exist simply because vegetation encroached within a pre-defined zone by a fractional inch, but only
when an event, such as a sustained outage, occurs due to the Transmission Owner's failure to maintain
adequate clearance between conductors and vegetation.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
E.ON U.S.
Disagree
E.ON U.S. suggests that R2 be deleted. Since this is a "zero tolerance" standard any Transmission Owner will
remove any discovered threats to prevent outages. While we agree that the implementation of an imminent
threat procedure may be a valid concept, visualization of the Critical Clearance Zone and determining an
approaching encroachment is a practice in application of theoretical conductor locations in real time.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
FirstEnergy
September 8, 2009
Disagree
The CCZ is not equal to Clearance 2 in FAC-003-1. Per requirement R4, any encroachment into the CCZ is a
violation of the standard even if an outage does not occur. This is too strict because it refers to a "0"
tolerance even for encroachments that do not affect reliability. This can be an extremely costly standard to
comply with that may or may not improve reliability. The CCZ distance is a difficult to determine from one
moment to the next based upon the description and calculations outlined. The conditions on the right of way
are dynamic and ever changing. It would be more proactive for the TO to focus on implementing the TVMP
rather than expending time and money trying to determine if the CCZ has been violated. A better approach
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Question 11 Comment
would be to establish a minimum clearance at all times rather than to monitor encroachment to a theoretical
CCZ.
Response: Thank you for your comment. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response,
the SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the
Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced
with Minimum Vegetation Clearance Distance (MCVD) in R4.
Midwest ISO Stakeholders
Standards Collaborators
Disagree
he CCZ is a good theoretical concept to aid industry in understanding the overall movement of conductors, but
it is an impractical concept for field application. Due to the variability in the size of the CCZ as you move along
a conductor, as well as changes from span to span or even line to line due to design parameters, loading or
weather-related issues, the CCZ concept should not be tied to an imminent threat procedure. Vegetation
approaching the CCZ does not constitute an imminent threat. It may be months to years before this
vegetation ever gets to a proximity distance from the conductor to be within a "spark-over" distance as defined
by the Gallet equations. Requirement R2 should support the purpose of this standard by requiring
implementation of the Vegetation Imminent Threat Procedure when the Transmission Owner has visual, field
knowledge that vegetation is encroaching upon a conductor within some specific distance that is a multiple of
the Gallet distances referenced in Table I of FAC-003-2 (to be conservative we suggest two to three times the
Gallet distances). Failure to implement the Vegetation Imminent Threat Procedure in such instances would
be a violation of R2.As R2 is currently stated, a Transmission Owner cannot comply with R2 unless the
imminent threat procedure is continuously being implemented, because vegetation that is growing is always
approaching the CCZ. "Approaching the CCZ" cannot be the trigger for implementation of the Vegetation
Imminent threat Procedure. Instead, the trigger should be an encroachment within some observed field
distance. Requirement R2 could be reworded as follows: ?Each Transmission Owner shall implement its
Vegetation Imminent Threat Procedure when the Transmission Owner has knowledge, obtained through
normal operating practices or notification from others, that vegetation is encroaching upon a conductor within
a distance that is twice the Gallet clearance distances referenced in Table I." Using a multiple of the Gallet
distances provides a safety factor. Assessing a violation for failure to appropriately implement the Vegetation
Imminent Threat Procedure or for a sustained vegetation-related outage incents the proper behavior.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4. The proposed standard revision specifies the MVCD as a starting point and TOs may apply multiples at
its own discretion in order to achieve its TVMP objectives and adhere to applicable safety standards.
September 8, 2009
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SERC Compliance Staff
Agree?
Disagree
Question 11 Comment
SERC staff agrees that the implementation of an imminent threat procedure may be a valid concept; however
visualization of the Critical Clearance Zone and determining an approaching encroachment will be difficult
from a practical matter. There also needs to be definition of what is meant by "approaching" if this is used.
While it may be a technically sound approach to designate the clearance zone to be tied to the conductor
movement envelope as found in the NESC, this results in a banana-shaped zone that is difficult to
substantiate in the field by entity and compliance personnel. It may be better, and more reasonable to define
a constant zone around a conductor that would be the same throughout the span. The clearance zone should
not include the limitation that the zone cannot extend outside the active right of way.
Response: Thank you for your comment. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response,
the SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the
Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced
with Minimum Vegetation Clearance Distance (MCVD) in R4.
ITC HOLDINGS
Disagree
Just because vegetation is approaching the CCZ doesn't represent an imminent threat and should not be set
to an imminent threat procedure. Implementation of R2 would require field personnel to determine the
speculative position of the line during inspections to decide whether to engage the imminent threat
procedures. While we agree that an imminent threat procedure should be implemented to address vegetation
related imminent threats as soon as they are identified, we believe that an approach of the CCZ should not be
used to generate implementation. The term "approached" does not identify a specific distance, so it’s not clear
to what extend vegetation would have to approach the CCZ to require implementation of the imminent threat
process. ITC agrees that the implementation of an imminent threat procedure may be a valid concept, but
visualization of the CCZ and determining approaching vegetation is a practice in hypothetical conductor
locations in real time. This may be a good imaginary concept in understanding conductor movement but it's
impractical for field applications.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
Tennessee Valley Authority
Disagree
TVA recommends that R2 be removed from this standard. Since this is a "zero tolerance" standard there is a
very significant incentive for the Transmission Owner to inspect and plan maintenance to prevent potential
outages. The Gallet Equations should be kept within the white paper solely for the TO to reference for
developing maintenance and inspection cycles.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
September 8, 2009
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Agree?
Question 11 Comment
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
Exelon
Disagree
Comments: 1) In spite of the rigor associated with the Gallet equations, the definition of CCZ is imprecise as
the Ratings to be used are not specified. In addition, Exelon is concerned that it will be difficult to determine
the CCZ for each span under all possible operating conditions. Implementing an imminent threat procedure
(R2) in combination with the CCZ may be unworkable under actual field conditions. 2) We are concerned that
CCZ is only fully defined in the Technical Reference documentation and not in the standard itself. As stated in
the NERC Standards Process Manual, Elements of a Reliability Standard, "Supporting documents to aid in the
implementation of a standard may be referenced by the standard but are not part of the standard itself." There
needs to be enough specificity as to the definition of CCZ in FAC-003-2 so that adequate documentation and
evidence of compliance can be developed.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
American Electric Power (AEP) Disagree
AEP agrees with the need for a TO to have an Imminent Threat Procedure and that the Transmission
Operator should be immediately notified of imminent threats. However, AEP disagrees with the requirement
that the Transmission Operator be notified merely because the CCZ has been approached. Vegetation
approaching the CCZ does not necessarily constitute an imminent threat. It is possible that the CCZ is
encroached by vegetation at the lowest point of the CCZ whereas the conductor may be at its highest point in
the CCZ (potentially 20 or 30 feet away from the vegetation). This situation does not merit notification to the
Transmission Operator. Please also refer to our comments regarding CCZ in AEP's responses to Questions
15 and 18.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
September 8, 2009
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Platte River Power Authority
Agree?
Disagree
Question 11 Comment
Changing to the Gallet equation will not have a large impact on vegetation management operations, keeping
Clearance 1 and 2 with tables developed using IEEE Standards for various voltages, line spans and altitudes
is preferable. Actions should be taken to prevent an outage when vegetation encroaches Clearance 2.
Response: Thank you for your comment. The SDT chose to use Gallet equations over IEEE primarily because Gallet is more appropriate for
determining the probability of flashover. The IEEE standard was developed for human safety purposes.
Northern Indiana Public
Service Company
Disagree
While I agree with the argument that the Gallet equatiion is a better technical or scientific method than IEEE
516 for determining realistic conductor to tree flashover distances, I do not agree that the new proposed
clearance tables serve any useful purpose as a vegetation clearance standard from an operational
perspective. The FAC-003-2 Technical Reference itself points to this fact when it states, "even if the exact
size and shape of the C.C.Z. is known, it becomes nearly impossible in the field to correlate and accurately
superimpose the C.C.Z. around the conductor." The Tech. Ref. goes on to say that "it is anticipated that
many T.O.s will establish a work trigger well outside the C.C.Z." I agree wholeheartedly with that concept and
believe that the Gallet clearance tables should be used by TO's to develop the more important "work trigger"
or "action threshold" clearances. This revision is overly focused on C.C.A.'s that have no practical operational
application while being silent to the more critical to reliability issue of "work trigger/action threshold"
clearances. This needs to be addressed if we hope to be successful at achieving the goal of zero preventable
tree related outages.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
Tampa Electric Company
Disagree
This is a good start. The Critical Clearance Zone (CCZ) is a very real and practical concept; however, it is not
transferable to field conditions. This could result in a "fill in the blank" standard relative to what the Critical
Clearance Zone will be in terms of distance. As I read this, it will be a sliding scale from insulator to mid span
and back for each designated line voltage. The max wind speed to be used and other assumptions behind the
determination of this zone may be as involved a Gallet's formula. This will lead to complications during
operational inspection and verification of these clearances.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
September 8, 2009
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Organization
Agree?
Question 11 Comment
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
Orange and Rockland Utilities
Inc.
Disagree
While we agree that the imminent threat procedure should be implemented to address vegetation-related
imminent threats as soon as they are identified, we believe that an "approach" of the CCZ should not be used
to trigger implementation. The term "approached" does not identify a specific distance, so it is not clear to
what extent vegetation would have to approach the CCZ in order to require implementation of the imminent
threat process. This is left to the discretion of individual interpretation, is confusing to field personnel, and
presents compliance and auditing problems. Imminent threats which are based on vegetation clearances
should be identified based on specific clearances, not undefined approach distances. In practical field
application the CCZ is an invisible area that changes shape and size along the length of the conductor. It is
impossible to readily identify in the field without engineering calculations and precise measurements or the
use of technology such as Aerial Laser Survey (ALS) using Light, Detection and Ranging (LIDAR) technology.
Therefore under normal circumstances the location, size, and shape of the CCZ and vegetation
encroachments of the CCZ can only be roughly estimated. Even with the use of ALS, which is relatively
accurate, information is often not available for months after the survey flight. We believe that under normal
circumstances imminent threats which are based on vegetation clearances should be identified in terms of
specific distances from the conductor. While it is not possible for an inspector to readily identify a vegetation
encroachment of the CCZ in the field, an inspector could more easily estimate a specified short distance
between a conductor and vegetation in real time and initiate implementation of the imminent threat procedure
based on that assessment. This assessment would be significantly more accurate than attempting to measure
the distance between vegetation and the CCZ, which is not visible and constantly changes size and shape
throughout the span. In cases where the Transmission Owner chooses to deploy ALS, the CCZ rather than
the conductor could be used as the reference because in most cases the CCZ could be identified relative to
approaching vegetation with a reliable degree of accuracy. Still a specific distance should be used to trigger
implementation of the imminent threat procedure because of the issues previously raised with the use of the
word "approached".
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
American Transmission
Company
September 8, 2009
Disagree
ATC believes that the Critical Clearance Zone (CCZ) is a good theoretical concept to aid industry in
understanding the overall movement of conductors, but it is an impractical concept for field application. Due to
the variability in the size of the CCZ as you move along a conductor, as well as changes from span to span or
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Question 11 Comment
even line to line due to design parameters, loading or weather-related issues, the CCZ concept should not be
tied to an imminent threat procedure. Vegetation approaching the CCZ does not constitute an imminent
threat. It may be months to years before this vegetation ever gets to a proximity distance from the conductor
to be within a "spark-over" distance as defined by the Gallet equations. Requirement R2 should support the
purpose of this standard by requiring implementation of the Vegetation Imminent Threat Procedure when the
Transmission Owner has visual, field knowledge that vegetation is encroaching upon a conductor within some
specific distance that is a multiple of the Gallet distances referenced in Table I of FAC-003-2 (to be
conservative we suggest two to three times the Gallet distances). Failure to implement the Vegetation
Imminent Threat Procedure in such instances would be a violation of R2.As R2 is currently written, a
Transmission Owner cannot comply with R2 unless the imminent threat procedure is continuously being
implemented or monitored, because vegetation that is growing is always approaching the CCZ. "Approaching
the CCZ" cannot be the trigger for implementation of the Vegetation Imminent threat Procedure. Instead, the
trigger should be an encroachment within some observed field distance. Requirement R2 could be rewritten
as follows: ?Each Transmission Owner shall implement its Vegetation Imminent Threat Procedure when the
Transmission Owner has knowledge, obtained through normal operating practices or notification from others,
that vegetation is encroaching upon a conductor within a distance that is twice the Gallet clearance distances
referenced in Table I." Using a multiple of the Gallet distances provides a safety factor. Assessing a violation
for failure to appropriately implement the Vegetation Imminent Threat Procedure or for a sustained vegetationrelated outage would promote the proper behavior.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4. The proposed standard revision specifies the MVCD as a starting point and TOs may apply multiples at
its own discretion in order to achieve its TVMP objectives and adhere to applicable safety standards.
Ameren
September 8, 2009
Disagree
The CCZ is a good theoretical concept to aid industry in understanding the overall movement of conductors,
but it is an impractical concept for field application. Due to the variability in the size of the CCZ as you move
along a conductor, as well as changes from span to span or even line to line due to design parameters,
loading or weather-related issues, the CCZ concept should not be tied to an imminent threat procedure.
Vegetation "approaching" the CCZ does not constitute an imminent threat. In fact, the moment after
vegetation is cut, it begins again to "approach" this zone. It may be months to years before this vegetation
ever gets to a proximity distance from the conductor to be within a "spark-over" distance as defined by the
Gallet equations. Requirement R2 should support the purpose of this standard by requiring implementation of
the Vegetation Imminent Threat Procedure when the Transmission Owner has visual, field knowledge that
vegetation is encroaching upon a conductor within some specific distance. As R2 is currently stated, a
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Agree?
Question 11 Comment
Transmission Owner cannot comply with R2 unless the imminent threat procedure is continuously being
implemented, because vegetation that is growing is always approaching the CCZ. "Approaching the CCZ"
cannot be the trigger for implementation of the Vegetation Imminent threat Procedure. Instead, the trigger
should be an encroachment within some observed field distance.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
Nebraska Public Power District Disagree
The CCZ is a good concept to explain the flight path of a conductor under all conditions but it would be
impractical to use in the field. There are too many variables to consider and an encroachment does not
constitute an immediate threat.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
Manitoba Hydro
Disagree
The imminent threat process trigger should be well defined, and the vague "approaching" terminology needs
to be changed. Imminent threat implies and that an elevated risk of contact exists. That is not the case if the
vegetation is merely approaching the CCZ. The objective of the overall Vegetation Management program is to
prevent an encroachment. The imminent threat procedure should be triggered by discovery of an
encroachment into the CCZ. Even when an actual encroachment into the CCZ occurs - while the odds of an
outage event have increased - the likelihood of a contact is still minimal, as other environmental factors still
need to be in place (i.e. high temperature and/or high wind conditions).If this approach to an imminent threat
process trigger, then the violation of this requirement implies a violation of R4, which prohibits the
encroachment of the CCZ, and therefore either R2 or R4 could be removed, or they could be combined into
one requirement.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
The Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
Consumers Energy Company
September 8, 2009
Disagree
Absolutely disagree! The Gallet formula distances do not provide adequate protection of the system. The
"Critical Clearance Zone" concept is not workable in the field. Every foot of every span would have a different
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Question 11 Comment
CCZ that cannot be measured in the field without survey type equipment and knowledge of current line
loadings. The clearance requirement needs to be uniform along the span for field crews to effectively achieve
compliance. It appears that the drafting team hopes to minimize violations of vegetation violating FAC-003-1
Clearance 2 distances by decreasing the clearance distance between the conductor and vegetation using the
Gallet formula. If NERC believes that FAC-003-1 Clearance 2 distances are too conservative, then the Gallet
formula distance needs to be increased by some multiplier (2 or3) to achieve adequate safeguard for growing
vegetation. Most trees in the United States in the size range that could exist beneath conductors achieve
height growth of 3 feet or more annually. A tree in May may have adequate clearance per the proposed CCZ
and in July violate that clearance causing an outage. Therefore, if the CCZ is to remain as is then the
transmission owner/operator must have a defined imminent threat distance considerably greater than the CCZ
and must be great enough that field personnel can safely remove the threat without de-energizing or de-rating
the line.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4. The proposed standard revision specifies the MVCD as a starting point and TOs may apply multiples at
its own discretion in order to achieve its TVMP objectives and adhere to applicable safety standards.
Pacific Gas & Electric Co.
Disagree
PG&E agrees the Gallet equation is superior to IEEE 516 and the imminent threat procedure is a critical
component of the standard but disagrees that initiation of the procedure be based on such ambiguous
language as "approaching the CCZ". Approaching could be any and all vegetation that is live and growing
and CCZ is a theoretical calculation not a real time event. As written, the standard would require the TO to
initiate an emergency action when such action may not be warranted or necessary to prevent an outage.
PG&E recommends using a clearly defined and measureable threshold to determine when the imminent
threat procedure must be initiated. A reasonable threshold would be 3 times the Gallet clearance distances
referred to in Table 1 or when vegetation is threatening to fall into or otherwise impact a line.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4. The proposed standard revision specifies the MVCD as a starting point and TOs may apply multiples at
its own discretion in order to achieve its TVMP objectives.
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San Diego Gas & Electric
Agree?
Disagree
Question 11 Comment
We do not agree with replacing Clearance Zone 2 with the Critical Clearance Zone. We recommend the
removal of R4 entirely from the standard.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
Consolidated Edison Company Disagree
of New York (CECONY)
CECONY is in favor of using the Gallet equations as they provide a more realistic clearance distance for
vegetation. We understand and agree that establishing a Critical Clearance Zone (CCZ) would provide the
specific area that a conductor could possibly travel through during various field and weather conditions but we
do not agree that this is the most practical approach. The main issue is that the wording '...the Critical
Clearance Zone is approached by vegetation.....' is very vague and left open to wide interpretation which
causes inconsistency and confusion throughout the industry. The CCZ changes throughout the length of each
conductor in each span so a field inspector's job and an auditor's job become much more complicated when
trying to confirm compliance when vegetation is present in the Actiove ROW. We feel that the time spent
trying to measure and calculate the CCZ and then confirm compliance would be better spent initiating a
response plan to safely remove the vegetation. The imminent threat procedure would only be implemented if
vegetation encroaches beyond a specific distance from the conductor, not as it approaches the theoretical
CCZ. Advanced technology would be required if a vegetation approach distance to the CCZ was to be
calculated in the field. This is a very costly and time consuming requirement and does not efficiently meet the
Standard's goal of ensuring reliability.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
Duke Energy Corporation
September 8, 2009
Disagree
No. Duke believes that the CCZ is a good theoretical concept to aid industry in understanding the overall
movement of conductors, but it is an impractical concept for field application. Due to the variability in the size
of the CCZ as you move along a conductor, as well as changes from span to span or even line to line due to
design parameters, loading or weather-related issues, the CCZ concept should not be tied to an imminent
threat procedure. Vegetation approaching the CCZ does not constitute an imminent threat. It may be years
before this vegetation ever gets to a proximity distance from the conductor to be within a "spark-over" distance
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Agree?
Question 11 Comment
as defined by the Gallet equations. Requirement R2 should support the purpose of this standard by requiring
implementation of the Vegetation Imminent Threat Procedure when the Transmission Owner has visual, field
knowledge that vegetation is encroaching upon a conductor within some specific distance that is a multiple of
the Gallet distances referenced in Table I of FAC-003-2 (to be conservative we suggest two times the Gallet
distances). Failure to implement the Vegetation Imminent Threat Procedure in such instances would be a
violation of R2.As R2 is currently stated, a Transmission Owner cannot comply with R2 unless the imminent
threat procedure is continuously being implemented, because vegetation that is growing is always
approaching the CCZ. "Approaching the CCZ" cannot be the trigger for implementation of the Vegetation
Imminent threat Procedure. Instead, the trigger should be an encroachment within an observed distance from
vegetation to conductor that is twice the Gallet distances in Table I. Requirement R2 could be reworded as
follows: ?Each Transmission Owner shall implement its Vegetation Imminent Threat Procedure when the
Transmission Owner has knowledge, obtained through normal operating practices or notification from others,
that vegetation is encroaching upon a conductor within a distance that is twice the Gallet clearance distances
referenced in Table I." Using a multiple of the Gallet distances provides a safety factor. Assessing a violation
for failure to appropriately implement the Vegetation Imminent Threat Procedure or for a sustained vegetationrelated outage incents the proper behavior.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
The proposed standard revision specifies the MVCD as a starting point and TOs may apply multiples at its own discretion in order to achieve its TVMP
objectives and adhere to applicable safety standards.
Entergy Services
Disagree
: 1. Entergy suggests that the requirement for activation of the vegetation imminent threat process should not
be tied to the Critical Clearance Zone and that the each entity should define the activation of their vegetation
imminent threat process. Tying the activation of the imminent threat process to the Critical Clearance Zone is
limited in that this criterion does not address the possibilities of vegetation falling into the line or Critical
Clearance Zone.
2. In the sentence “Critical Clearance Zone approached by vegetation” the use of “approached” is subjective
and not specifically quantifiable. Effective, uniform activation of the imminent threat process will require
objective measurement criteria.
3. The standard needs to include a clear statement to the effect that when the Transmission Operator is
notified of a potential vegetation problem, obtained by normal operations and inspections, the entity will
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Agree?
Question 11 Comment
activate the Vegetation Imminent Threat Process.
4) This requirement, as stated, is redundant. The requirements for maintaining the Critical Clearance Zones
and / or avoiding vegetation outages, and the associated Violation Risk Factors and Violation Severity Levels,
already reinforce the desired behavior of the entity to identify and mitigate any potential issues before the
possibility of vegetation causing an outage.
Response: Thank you for your comment.
1) The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT modified R2 to remove the
use of the CCZ to trigger Imminent Threat procedure implementation. The Critical Clearance Zone has been replaced with Minimum Vegetation
Clearance Distance (MCVD) in R4. These changes may address your concerns.
2) Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The word,
“approached” is not used in the revised standard.
3) Requirement R1 Part 1.4 specifies the TVMP have an Imminent Threat procedure that includes notification of the responsible control center.
4) The SDT believes that having to implement an Imminent Threat procedure is proactive behavior and is in support of prevention of outages.
Pepco Holdings, Inc
Disagree
R5, R6 and R7 make this requirement redundant and unnecessary - it should be deleted. It is largely
unenforceable and does not make the standard clear, specific and regulatory enforceable. Further, PHI
believes the concept of enforcing no encroachment into the Critical Clearance Zone is a flawed approach.
Response: Thank you for your comment. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response,
the SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the
Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced
with Minimum Vegetation Clearance Distance (MCVD) in R4.
The SDT believes that having to implement an Imminent Threat procedure is proactive behavior and is in support of prevention of outages.
JEA
Disagree
The use of Gallet equations is not practical either for field use or for demonstrating compliance.
Response: Thank you for your comment. The SDT chose to use Gallet equations over IEEE primarily because Gallet is more appropriate for
determining the probability of flashover and the SDT believes holds distinct advantages for use in vegetation management applications. IEEE 516 is
developed for human safety purposes.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
September 8, 2009
Agree
We feel that changing to the Gallet equation will not have a large impact on its vegetation management
operations, so we have no concerns. We agree with R2, but feel that this clause makes R4 redundant, as per
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Agree?
Question 11 Comment
our discussion under Comment # 15 below. We recommend the removal of R4 entirely from the standard.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
WECC
Agree
Yes but the wording is ambiguous. Vegetation under a transmission line is always "approaching" or growing
towards the transmission line. Entities should define a specific distance greater than the Critical Clearance
Zone when they are required to implement their Imminent Threat Procedures.
Response: Thank you for your comment. The proposed standard revision specifies a “Minimum Vegetation Clearance Distance” as a starting point
and TOs may apply greater distances at their discretion in order to trigger implementation of the Imminent Threat procedure. The word,
“approaching” is not used in the revised standard.
Baltimore Gas & Electric
Company
Agree
Again, each utility is responsible and accountable for it's actions. The Gallet clearances are a much better
approximation of a true spark gap than the present requirement. Without a clearance one requirement, the
closer tolerance produced by the Gallet equation will leave little room for error when a line is at or approaching
it's max. engineered sag. When vegetation gets in the new CCZ (if adopted), it will be likely that an outage
will be imminent. With the present clearance 1 and clearance 2 requirements, there is more of a buffer for
encroaching vegetation.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
The proposed standard revision specifies the MVCD as a starting point and TOs may apply multiples at its own discretion in order to achieve its TVMP
objectives and adhere to applicable safety standards.
CenterPoint Energy
September 8, 2009
Agree
We agree with replacing IEEE 516 standard distances with the Gallet equation standard distances. However,
the term "Critical Clearance Zone" refers to the "limits of the Active Transmission Line Right-of-way" which
has no specific definition as to its limits within the proposed revised Standard. (See comments to Q3 above.)
R2 should be reworded to coordinate with R1.4. (See comments to Q4 above.)
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Agree?
Question 11 Comment
Response: Thank you for your comments. Please see our responses to Questions 3 and 4 comments as well as the summary consideration for this
question Based on stakeholder comments, the SDT made significant modifications to Requirement R2 and removed the concept of the CCZ.
Salt River Project
Agree
Although we agree that using the Gallet equation is more definitive than using IEEE 516, we still question from
an engineering prespective as to how and why this method was chosen. It is stated in the Technical
Reference paper that the Gallet Equation is a well known method of computing the required strike distance for
proper insulation coordination. It is our understanding it's purpose is for designing towers, to define the "tower
window" or opening inside of a tower under normal conditions. Because this is not a method designed
specifically for vegetation management, was there any physical testing involved in choosing this approach,
such as testing in both wet and dry conditions? We would recommend additional information to clarify this
method to use for vegetation management. See additional comments in Comment #18 below. In addition, we
feel this clause makes R4 redundant, as per our comments under Comment #15 below.
Response: Thank you for your comment. The Gallet equations indeed are useful in tower design; however it is not exclusively for that purpose. The
decision whether to use Gallet is not contingent upon testing and none were considered or conducted. No physical testing was utilized by the SDT;
however, the Gallet Equation method and its explanation in the White Paper do have their basis in physical testing in both laboratory and field
conditions. The Gallet Equation method is not solely applicable to tower structure design, but to any application requiring spark-over calculations.
The SDT believes that the Gallet Equation method holds distinct advantages over the IEEE 516 method for use in vegetation management
applications.
Southern California Edison
Company
September 8, 2009
Agree
Q11: SCE agrees in part with proposed R2. The use of the Gallet equation and the replacement of the
existing Clearance 2 requirement with the Critical Clearance Zone is acceptable. However, SCE strongly
disagrees with establishing a separate requirement for implementing an imminent threat procedure should
there be an encroachment of the Critical Clearance Zone because it forms the basis of an unnecessary zerotolerance enforcement policy. Read in context with corresponding Measure 2, R2 appears to require
Transmission Owners to prove that a Critical Clearance Zone encroachment did or did not occur and also
prove that that an imminent threat procedure was or was not properly invoked. Although SCE agrees that
CCZ encroachments should be addressed timely, we disagree with the notion and underlying assumption that
a CCZ incursion will always lead to a flash-over or a vegetation-to-line contact. If the goal of FAC-003-2 is to
prevent sustained outages (due to vegetation-to-line contacts) that could lead to Cascading, emphasizing
“prevention” is understandable, however, enforcing prevention measures is an entirely different matter. Under
the proposed requirements, a vegetation-to-line contact could conceivably represent two distinct violations of
FAC-003-2. SCE believes this type of regulatory double jeopardy is patently unfair and forcing Transmission
Owners to prove a CCZ encroachment did or did not occur is equally unfair and unenforceable. Because R1.4
adequately addresses the Transmission Owner’s responsibility regarding the implementation of an imminent
threat procedure, SCE respectfully recommends that proposed R2 and corresponding M2 be removed from
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Agree?
Question 11 Comment
FAC-003-2.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat upon discovery of such a threat. The Critical Clearance Zone has been replaced with Minimum Vegetation
Clearance Distance (MCVD) in R4.
Buckeye Power, Inc.
Agree
I agree with R2. I like the language changes, but decreasing the clearances will not improve reliability.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical Clearance Zone has been replaced with Minimum
Vegetation Clearance Distance (MCVD) in R4.
Great River Energy
Agree
GRE agrees and believes that the Gallet equation yields a less subjective measurement. GRE believes R2
should be modified to be more definitive. The imminent threat procedure should be implemented when
vegetation “enters” the Critical Clearance Zone (CCZ). It is GRE's opinion that approaching the CCZ is
subjective and as such very difficult to enforce.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Requirement R2 now requires the Transmission
Owner to implement its imminent threat procedure. The Critical Clearance Zone has been replaced with Minimum Vegetation Clearance Distance
(MCVD) in R4.
USDA Forest Service,
Southwestern Region,
Regional Office for AZ and NM
Agree
Attachment 1 is very conservative. I think that the clearance distances shown on the attachment should be
expanded to create, in effect, a standard that reflects maximum line loading and maximum line sag. I would
also like to see some flexibility built into the process so that the Transmission Owner and the USFS could
negotiate some consideration for vegetation growth rates. The end result would generate a standard that
would give the Transmission Owner the security of knowing that vegetation would not grow into the potential
arcing zone for some reasonable amount of time - some kind of entry cycle.
Response: Thank you for your comment. The SDT has retained the use of Gallet equations in the proposed draft standard revision but has
discontinued the use of the CCZ. The SDT received a substantial number of negative comments on the matter of R2 and the CCZ. In response, the SDT
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Organization
Agree?
Question 11 Comment
modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation. Measure M2 requires that the entity have evidence
showing dates and activities accomplished to meet the R2 implementation requirement. The SDT notes that the proposed standard revision does not
preclude the USFS and the TO from negotiating consideration for vegetation growth rates and in fact it is a good idea.
City of Tallahassee
Agree
As long as we do not have to have evidence of using the calculation! We should be able to use Table I as
provided.
Response: Thank you for your comment. Please see the summary response. Many commenters disagreed with this requirement and it has been
substantially modified.
Bonneville Power
Administration
Agree
BPA agrees with R2, but refer to comments submitted regarding R4 (please see our response to Question
#15) for related recommendations to R2.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
MRO NERC Standards Review Agree
Subcommittee
The MRO agrees and believes that the Gallet equation yields a less subjective measurement. The MRO
believes R2 should be modified to be more definitive. The imminent threat procedure should be implemented
when vegetation “enters” the critical clear zone. Fines and violations for approaching the zone is not
measurable or enforceable. The MRO believes that "approached" is subjective and not enforceable and
should be removed from the requirement.
Response: Thank you for your comment. The SDT modified R2 to remove the use of the CCZ to trigger Imminent Threat procedure implementation.
Requirement R2 now requires the Transmission Owner to implement its imminent threat procedure upon discovery of such a threat. . The Critical
Clearance Zone has been replaced with Minimum Vegetation Clearance Distance (MCVD) in R4.
Northern California Power
Agency (NCPA)
Agree
Santee Cooper
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
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Arizona Public Service
Company
Agree?
Question 11 Comment
Agree
Independent Electricity System Agree
Operator
Northeast Utilities
Agree
Hydro-Quebec Transenergie
(HQT)
Agree
NPCC
Agree
WECC Reliability Coordination
Agree
Kansas City Power & Light
Agree
National Grid
Agree
Long Island power Authority
Agree
Central Maine Power Company
September 8, 2009
No comment
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12. The Standard Drafting Team revised the spark-over (also referred to as “flashover”) distance thresholds utilizing
technically-equivalent Gallet equations in lieu of IEEE 516 minimum air insulation distance (MAID) calculations that
were used in FAC-003-1. The rationale is that the minimum air insulation distances in IEEE 516 were safety
clearances developed under laboratory conditions and thus there exists concern these distances may be too
conservative to apply to lines operating in actual field conditions. Do you agree with this? If not, please explain.
Summary Consideration: The majority of responders (90%) agreed with this change. The minority view favored the
continued use of IEEE 516 and four responders advocating removing the tables from the standard.
After reviewing the industry comments, the SDT continues to support the merits of using the Gallet equations and maintaining
the tables in the standard. IEEE 516 values are safety clearances developed under laboratory conditions and thus these
distances are inappropriate for vegetation spark-over clearances associated with lines operating in actual field conditions. In
addition, IEEE Standards are subject to change which the SDT did not desire to have the Vegetation Reliability associated with
an IEEE Standard that may change without proper consideration of the impact to the Vegetation Reliability Standard.
By using the Gallet distances, the SDT feels this is a technically sound, independent value that represents a true spark-over
threshold distance. One must remember this is a minimum distance and the new requirement of 1.6 specifies the Transmission
Owner develop a maintenance strategy to ensure these clearances are never violated.
Organization
SERC Compliance Staff
Question 12
Disagree
Question 12 Comment
While the actual sparkover distance may be more correctly calculated using the Gallet equations, SERC staff
believes it is a less conservative approach to the goal of preventing vegetation related outages. If the concept
of the CCZ will remain in the standard, we suggest that the tables based on the Gallet equations be removed
from the standard and be kept in the technical white paper solely to assist in developing a common
understanding of the theory behind the establishment of a CCZ. However, the CCZ will continue to be a very
difficult, if not impossible, aspect of the standard to implement from the perspective of practical application and
compliance enforcement.
Response: The SDT thanks you for your response. The SDT feels that the tables are an important component and should be part of the standard. The
supporting documentation for the derivation of the tables resides in the technical reference document. The revised standard does not use the concept
of the CCZ.
Tennessee Valley Authority
September 8, 2009
Disagree
TVA agrees with this concept however as stated in Comment Question 11 response, this should be an element
of the White Paper and should not be in the Standard Requirement.
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Question 12
Question 12 Comment
Response: The SDT thanks you for your response. The SDT feels that the tables are an important component and should be part of the standard. The
supporting documentation for the derivation of the tables resides in the technical reference document.
Exelon
Disagree
Comments: By using the Gallet equations, the draft standard appears to support reducing the clearance
requirements as compared to IEEE 516. Given what we believe would be the difficulties in applying the
clearances as developed using the Gallet equation method, we question if dropping the IEEE 516 guidance
could have the unintended consequence of reducing reliability.
Response: The SDT thanks you for your response. The reduction in the clearance distances is due to applying smaller transient over-voltage factors
and not due to using the Gallet equations. The SDT feels that using the reduced over-voltage factors is a more realistic approach than using the
maximum factors in version 1. The Gallet equations are only one of the factors in developing clearances. The utility must also consider sag, sway,
growth, environmental conditions and other factors when developing an effective TVMP.
Northern Indiana Public Service
Company
Disagree
If T.O.'s are serious about public safety and potential electrical hazards or are required to comply with
NESC/IEEE safety standards, then the greater, more conservative clearance distances must apply. On an
complex issue where the aerial distances between live conductors and trees are dynamic and changing, I would
prefer to be on the side of caution and on the side of safety. Given the history of cascading blackouts due to
preventable tree contacts, there is a need to be conservative with the standards. I don't see it being in the
public interest to argue that established minimum air insulation distances are inappropriately restrictive when
applied to UVM.
Response: The SDT thanks you for your response. The Gallet equations are only one of the factors in developing clearances. The utility must also
consider sag, sway, growth, environmental conditions and other factors when developing an effective TVMP.
Consumers Energy Company
Disagree
The Gallet distances severely lessen the reliability of the transmission system since there is not a define
imminent threat distance and the Clearance 1 distances have been removed from this draft. The IEEE 516
distances provided a safety margin to allow for vegetation to grow and not be a reliability risk. A transmission
owner/operator of a moderate size could not effectively inspect often enough during the growing season to
protect lines from outages when trees are permitted to approach the Gallet formula distance and not be a
violation. Such close distances would permit utility management to severely cut vegetation management
budgets and allow trees to grow for 1-2 years beyond their scheduled maintenance cycle and not be in violation.
But, 2-3 years after the budget cut, the field operation would be faced with an insurmountable amount of trees
needing addressed and limited timeframes to complete the work. This is basically how the blackout occurred
and this standard decreases the requirements to allow this to happen again.
Response: The SDT thanks you for your response. The Gallet equations are only one of the factors in developing clearances. The utility must also
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Question 12
Question 12 Comment
consider sag, sway, growth, environmental conditions and other factors when developing an effective TVMP.
Baltimore Gas & Electric
Company
Disagree
As noted in 11 above, the Gallet equation would appear to be a much closer approximation of the actual spark
gap/flashover distance. It seems as though the new std. is making the protective zone around the conductors
smaller by replacing the Clearance 2 requirement with the CCZ, while at the same time eliminating any other
type of consideration for how much clearance needs to be achieved while trimming. All things being equal, if
the only demarcation for when vegetation is a threat to the lines is the clearance 2 or CCZ areas, it would make
sense to have this area be larger rather than smaller. Accordingly, I would recommend that the Clearance 2
value continue to be used instead of the Gallet equation-created CCZ.
Response: The SDT thanks you for your response. The Gallet equations are only one of the factors in developing clearances. The utility must also
consider sag, sway, growth, environmental conditions and other factors when developing an effective TVMP. Note that the revised standard does not
use the concept of the CCZ.
SERC Vegetation Management
Subcommittee (VMS)
Agree
Developing minimum sparkover distances in this standard is a superior approach for the stated reason in
question 12. In addition, referring to tables and values in another standard is problematic if the referenced
standard is revised and the tables are re-numbered or deleted altogether. We suggest that the tables based on
the Gallet equations be removed from the standard and be kept in the technical white paper solely to assist in
developing a common understanding of the threshold for taking actions.
Response: The SDT thanks you for your response. The SDT feels that the tables are an important component and should be part of the standard. The
supporting documentation for the derivation of the tables resides in the technical reference document.
SERC OC Standards Review
Group
Agree
Developing minimum sparkover distances in this standard is a superior approach for the stated reason in
question 12. In addition, referring to tables and values in another standard is problematic if the referenced
standard is revised and the tables are re- numbered or deleted altogether. The SERC OOCSRG suggests that
the tables based on the Gallet equations be removed from the standard and be kept in the technical white paper
solely to assist in developing a common understanding of the threshold for taking actions.
Response: The SDT thanks you for your response. The SDT feels that the tables are an important component and should be part of the standard. The
supporting documentation for the derivation of the tables resides in the technical reference document.
Western Utility Arborists
Agree
The Western Utilities feel that changing this will not have a large impact on its vegetation management
operations, so we have no concerns.
Response: The SDT thanks you for your response.
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American Electric Power (AEP)
Question 12
Agree
Question 12 Comment
AEP agrees that the Gallet Equation method is a reasonable and appropriate replacement for the IEEE 516
method.
Response: The SDT thanks you for your comments.
Platte River Power Authority
Agree
Changing this will not have a large impact on vegetation management operations, so we have no concerns.
Response: the SDT thanks you for your comments.
USDA Forest Service,
Southwestern Region, Regional
Office for AZ and NM
Agree
See comment for Question 11.
Response: The SDT thanks you for your response. The Gallet equations are only one of the factors in developing clearances. The utility must also
consider sag, sway, growth, environmental conditions and other factors when developing an effective TVMP.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Agree
We feel that changing this will not have a large impact on its vegetation management operations, so we have no
concerns.
Response: The SDT thanks you for your comments.
Salt River Project
Agree
As commented in Comment #11 above, although we agree that using the Gallet equation is more definitive than
using IEEE 516, we still question from an engineering prespective as to how and why this method was chosen.
It is stated in the Technical Reference paper that the Gallet Equation is a well known method of computing the
required strike distance for proper insulation coordination. It is our understanding it's purpose is for designing
towers, to define the "tower window" or opening inside of a tower under normal conditions. Because this is not
a method design specifically for vegetation management, was there any physical testing involved in choosing
this approach, such as testing in both wet and dry conditions? We would recommend additional information to
clarify this method to use for vegetation management. See additional comments in Comment #18 below.
Response: The SDT thanks you for your response. The SDT searched for a method other than the laboratory condition based IEEE 516 method to
determine minimum spark-over distances. The Gallet equations were derived for both wet and dry conditions and have been successfully used in many
design applications. The SDT feels that using these equations to derive these minimum distances is a conservative approach. We also expect that the
TO must also consider sag, sway, growth, environmental conditions and other factors when developing clearances for an effective TVMP.
September 8, 2009
154
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Organization
Buckeye Power, Inc.
Question 12
Agree
Question 12 Comment
I understand the reasoning for the change, but I do not see how decreasing clearances will increase reliability.
Response: The SDT thanks you for your response. The Gallet equations are only one of the factors in developing clearances. The utility must also
consider sag, sway, growth, environmental conditions and other factors when developing an effective TVMP.
British Columbia Transmission
Corp
Agree
BCTC feels that changing this will not have a large impact on its vegetation management operations, so we
have no concerns.
Response: The SDT thanks you for your response.
Associated Electric Cooperative
Inc.
Agree
NPCC
Agree
WECC Reliability Coordination
Agree
Western Area Power
Administration, Upper Great
Plains Region
Agree
Progress Energy Florida
Agree
Kansas City Power & Light
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Progress Energy Carolinas
Agree
Southern California Edison
Company
Agree
September 8, 2009
Q12: No comments.
155
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Organization
Question 12
Florida Power & Light
Agree
Santee Cooper
Agree
Southern Company
Agree
E.ON U.S.
Agree
Bonneville Power Administration
Agree
FirstEnergy
Agree
MRO NERC Standards Review
Subcommittee
Agree
Midwest ISO Stakeholders
Standards Collaborators
Agree
ITC HOLDINGS
Agree
Central Maine Power Company
Agree
City of Tallahassee
Agree
Northern California Power
Agency (NCPA)
Agree
Tampa Electric Company
Agree
Orange and Rockland Utilities
Inc.
Agree
Ameren
Agree
September 8, 2009
Question 12 Comment
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Question 12
Nebraska Public Power District
Agree
Long Island power Authority
Agree
Manitoba Hydro
Agree
National Grid
Agree
Pacific Gas & Electric Co.
Agree
San Diego Gas & Electric
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
Consolidated Edison Company of
New York (CECONY)
Agree
WECC
Agree
Arizona Public Service Company
Agree
Duke Energy Corporation
Agree
CenterPoint Energy
Agree
Entergy Services
Agree
Pepco Holdings, Inc
Agree
JEA
Agree
Independent Electricity System
Agree
September 8, 2009
Question 12 Comment
157
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Question 12
Question 12 Comment
Operator
Northeast Utilities
Agree
Hydro-Quebec Transenergie
(HQT)
Agree
Great River Energy
Agree
Formatted: Indent: Left: 0"
September 8, 2009
158
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
13. The Standard Drafting Team applied a transient overvoltage factor (T) of 1.4 and 2.0 for ac voltage classes of 345kV
and above and sub-345kV facilities, respectively. Version 1, using the IEEE 516 method, assumes a maximum
transient overvoltage value. The Standard Drafting Team asserts that in this application of steady-state flashovers
and due to the design attributes of higher voltage systems, a lower T factor is applicable. Do you agree with this? If
not, please explain.
Summary Consideration: The majority of responders (93%) agreed with this change. Two responders commented that they
use a more conservative transient over-voltage factor in their design.
The SDT chose its transient over-voltage factors (“T”) as being the most appropriate values for the industry as a whole. The
majority of industry stakeholder comments supported this decision. It is permissible to use more conservative values if the
Transmission Owner so desires.
Organization
Agree ?
BCTC
Question 13 Comment
BCTC feels that changing this will not have a large impact on its vegetation management operations, so we
have no concerns.
Response: The SDT thanks you for your response.
Tennessee Valley Authority
Disagree
TVA agrees with this concept however as stated in Comment Question 11 response, this should be an
element of the White Paper and should not be in the Standard Requirement.
Response: The SDT thanks you and refers you to the response to Question 11.
Exelon
Disagree
We disagree with the T factors that are proposed as our design is more conservative.
Response: The SDT thanks you and also acknowledges that various utilities may employ various T factors in their line designs. However, the SDT chose
this value as the most appropriate value for the industry as a whole. Individual Transmission Owners are free to establish larger zones around the
conductor than that established by the new MVCD. MVCD as currently drafted establishes a minimum value, not the only value.
Manitoba Hydro
September 8, 2009
Disagree
Manitoba Hydro has historically designed the ROW clearance requirements based on an operating limitation
of not switching during extreme wind conditions, therefore, beyond a wind pressure of 230 Pa, our design
does not account for switching surge over voltages. We do however, agree with the use of overvoltage factors
159
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree ?
Question 13 Comment
as described above for wind conditions of less than 230 Pa.
Response: The SDT thanks you for your comments. Industry as a whole. Individual Transmisssion Owners are free to establish larger zones around the
conductor than that established by the new MVCD. MVCD as currently drafted establishes a minimum value, not the only value.
National Grid
Disagree
No opinion.
Response: The SDT thanks you for your comments. The SDT believes that it has chosen an approach that is the most appropriate method for the industry
as a whole.
SERC Vegetation Management
Subcommittee (VMS)
Agree
See comments in #12 above.
Response: The SDT thanks you for your comments. See response to #12.
SERC OC Standards Review Group
Agree
See comments in #12 above.
Response: The SDT thanks you for your comments. See response to #12.
Salt River Project
Agree
As commented in Comments #11 & #12 above, although we agree that using the Gallet equation is more
definitive than using IEEE 516, we still question from an engineering prespective as to how and why this
method was chosen. It is stated in the Technical Reference paper that the Gallet Equation is a well known
method of computing the required strike distance for proper insulation coordination. It is our understanding it's
purpose is for designing towers, to define the "tower window" or opening inside of a tower under normal
conditions. Because this is not a method design specifically for vegetation management, was there any
physical testing involved in choosing this approach, such as testing in both wet and dry conditions? We would
recommend additional information to clarify this method to use for vegetation management. See additional
comments in Comment #18 below.
Response: The SDT thanks you for your comments. No physical testing was utilized by the SDT; however, the Gallet Equation method and its explanation
in the White Paper do have their basis in physical testing in both laboratory and field conditions. The Gallet Equation method is not solely applicable to
tower structure design, but to any application requiring spark-over calculations. The SDT believes that the Gallet Equation method holds distinct
advantages over the IEEE 516 method for use in vegetation management applications.
Western Utility Arborists
September 8, 2009
Agree
The Western Utilities feel that changing this will not have a large impact on its vegetation management
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree ?
Question 13 Comment
operations, so we have no concerns.
Response: The SDT thanks you for your comments.
American Electric Power (AEP)
Agree
AEP agrees that the choice of transient overvoltage factors is sufficiently sound.
Response: The SDT thanks you for your comments.
Platte River Power Authority
Agree
Changing this will not have a large impact on vegetation management operations, we have not concerns.
Response: The SDT thanks you for your comments.
City of Tallahassee
Agree
As long as we do not have to have evidence of using the calculation! We should be able to use Table I as
provided.
Response: The SDT thanks you for your comments.
NV Energy (fka Sierra Pacific / Nevada Agree
Power Co.)
We feel that changing this will not have a large impact on its vegetation management operations, so we have
no concerns.
Response: The SDT thanks you for your comments.
Southern California Edison Company
Agree
Associated Electric Cooperative Inc.
Agree
NPCC
Agree
WECC Reliability Coordination
Agree
Western Area Power Administration,
Upper Great Plains Region
Agree
Progress Energy Florida
Agree
September 8, 2009
Q13: No comments.
161
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree ?
Kansas City Power & Light
Agree
Western Area Power Administration,
Rocky Mountain Region
Agree
Progress Energy Carolinas
Agree
Florida Power & Light
Agree
Santee Cooper
Agree
Southern Company
Agree
E.ON U.S.
Agree
Bonneville Power Administration
Agree
FirstEnergy
Agree
MRO NERC Standards Review
Subcommittee
Agree
Midwest ISO Stakeholders Standards
Collaborators
Agree
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
Central Maine Power Company
Agree
Northern California Power Agency
(NCPA)
Agree
September 8, 2009
Question 13 Comment
162
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree ?
Tampa Electric Company
Agree
Orange and Rockland Utilities Inc.
Agree
Ameren
Agree
Nebraska Public Power District
Agree
Long Island power Authority
Agree
Consumers Energy Company
Agree
Pacific Gas & Electric Co.
Agree
San Diego Gas & Electric
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
Consolidated Edison Company of New
York (CECONY)
Agree
WECC
Agree
Arizona Public Service Company
Agree
Duke Energy Corporation
Agree
CenterPoint Energy
Agree
Entergy Services
Agree
Pepco Holdings, Inc
Agree
September 8, 2009
Question 13 Comment
163
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree ?
JEA
Agree
Independent Electricity System
Operator
Agree
Northeast Utilities
Agree
Hydro-Quebec Transenergie (HQT)
Agree
Buckeye Power, Inc.
Agree
Great River Energy
Agree
Question 13 Comment
Baltimore Gas & Electric Company
I have no expertise to respond to this question.
Northern Indiana Public Service
Company
No comment.
USDA Forest Service, Southwestern
Region, Regional Office for AZ and NM
Don't know!
September 8, 2009
164
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
14. R3 has been added to clarify that conduction of inspections is a separate requirement from specifying the frequency
that inspections will occur. Do you agree with R3? If not please explain.
Summary Consideration: The majority of commenters (85%) were in favor of the standard as written. There were minority
comments that wanted a reformatting of the standard to put documentation and implementation side by side. Following the
directives in FERC order 693 and the SAR to bring the standard in line with the Sanction Guidelines, the SDT created a separate
requirement, R3 that explicitly requires inspections be conducted. This is to differentiate R3 from Requirement 1, Part 1.2.
Addressing inspections separately allows for appropriate assignment of VRFs and VSLs.
Organization
Agree?
BCTC
Question 14 Comment
BCTC understands that it’s possible to have a schedule and not implement it. However, we feel that the document
itself would be easier to follow if it was re-organized so that the requirement to have the schedule is kept together
with the requirement to implement it.
Response: The SDT thanks you for your comment. The SDT considered other sequence options and suggest a new sequence for the industry to comment
upon. See related question in the second Comment Form.
Western Utility Arborists
The Western Utilities understands that it’s possible to have a schedule and not implement it. However, we feel
that the document itself would be easier to follow if it was re-organized so that the requirement to have the
schedule is kept together with the requirement to implement it.
Response: The SDT thanks you for your comment. The SDT considered other sequence options and suggest a new sequence for the industry to comment
upon. See related question in the second Comment Form.
Progress Energy Florida
Disagree
The standard has established a threshold of compliance. For consistency, compliance should be measured at the
threshold not a Registered Entities program requirement.
Response: The SDT thanks you for your comments. R3 clarifies that the inspections in the TVMP are to be conducted. The TVMP defines a Transmission
Operator’s standards. The general application of NERC standards is that a Transmission Operator is to adhere to the standards it establishes.
Progress Energy Carolinas
Disagree
The standard has established a threshold of compliance. For consistency, compliance should be measured at the
threshold not a Registered Entities program requirement.
Response: The SDT thanks you for your comments. R3 clarifies that the inspections in the TVMP are to be conducted. The TVMP defines a Transmission
September 8, 2009
165
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 14 Comment
Operator’s standards. The general application of NERC standards is that a Transmission Operator is to adhere to the standards it establishes.
Southern California Edison
Company
Disagree
Q14: SCE does not agree with the inclusion of proposed R3 and believes it should be replaced with a modified
version of proposed R8.SCE respectfully suggests that proposed R8 be revised to read: "Each Transmission
Owner shall implement and follow its Vegetation Management Program to the extent allowed by existing
easement and/or legal rights."
Response: The SDT thanks you for your comments. Inspections are a key element of an effective TVMP. The SDT therefore decided to explicitly require
that inspections be conducted in accordance with the Transmission Owners’ requirements. In addition, addressing inspections separately allows for
appropriate assignment of VRFs and VSLs.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Disagree
We understand that it is possible to have a schedule and not implement it. However, we feel that the document
itself would be easier to follow if it was re-organized so that the requirement to have the schedule is kept together
with the requirement to implement it.
Response: The SDT thanks you for your comment. The SDT decided to explicitly require that inspections be conducted in accordance with the
Transmission Owners’ requirements. Addressing inspections separately allows for appropriate assignment of VRFs and VSLs.
San Diego Gas & Electric
Disagree
The information should not be separated. It will be much easier to follow if the requirement to have the schedule
is kept together with the requirement to implement it.
Response: The SDT thanks you for your comment. The SDT decided to explicitly require that inspections be conducted in accordance with the
Transmission Owners’ requirements. Addressing inspections separately allows for appropriate assignment of VRFs and VSLs.
Edison Electric Institute
Disagree
Consistent with previous comments, NERC should respond to FERC Order No. 693 Paragraph 721 regarding
compliance audit procedures to identify appropriate inspection cycles.
Response: The SDT thanks you for your comment. The SDT decided to explicitly require that inspections be conducted in accordance with the
Transmission Owners’ requirements. Your comment has been forwarded to NERC staff. The Reliability Standard Audit Worksheet is where the FERC
Order is addressed with respect to compliance audit procedures to identify appropriate inspection cycles.
Baltimore Gas & Electric
Company
September 8, 2009
Disagree
If frequency of inspections are required to be specified, it is implied that the inspections will follow. I suggest that
R3 be eliminated and R1.2 be reworded to say: "Vegetation inspections shall occur at least once per year, or
more frequently as dictated by local and environmental factors. Specify the frequency of when vegetation
inspections will occur."
166
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 14 Comment
Response: The SDT thanks you for your comment. The SDT decided to explicitly require that inspections be conducted in accordance with the
Transmission Owners’ requirements. Addressing inspections separately allows for appropriate assignment of VRFs and VSLs. The STD believes that the
phrase “Specify a vegetation inspection frequency…” adequately requires the Transmission Operator to “. . . .specify the frequency…”
JEA
Disagree
See comment from #3.
Response: The SDT thanks you for your comment. This was addressed in the response to question 3.
Salt River Project
Disagree
The document would be easier to follow if the two elements would be kept together in the same requirement
(similar to comments stated in Comments #4 & #6 above). It makes the standard longer than necessary and
creates redundancy.
Response: The SDT thanks you for your comment. The SDT decided to explicitly require that inspections be conducted in accordance with the
Transmission Owners’ requirements. Addressing inspections separately allows for appropriate assignment of VRF and VSLs.
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 14
Response: The SDT thanks you for your comment.
American Electric Power (AEP) Agree
AEP agrees with this change.
Response: The SDT thanks you for your comment.
Platte River Power Authority
Agree
The separation allows lower sanctions and penalties to be assessed for a weak schedule and higher sanctions
and penalties to be assessed for not implementing schedules. However, we feel that the standard itself would be
easier to follow if it was re-organized so that the requirement to have the schedule is kept together with the
requirement to implement it.
Response: The SDT thanks you for your comment. The SDT decided to explicitly require that inspections be conducted in accordance with the
Transmission Owners’ requirements. Addressing inspections separately allows for appropriate assignment of VRFs and VSLs.
Arizona Public Service
Company
September 8, 2009
Agree
APS understands that it’s possible to have a schedule and not implement it. However, we feel that the document
itself would be easier to follow if it was re-organized so that the requirement to have the schedule is kept together
with the requirement to implement it.
167
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 14 Comment
Response: The SDT thanks you for your comment. The SDT decided to explicitly require that inspections be conducted in accordance with the
Transmission Owners’ requirements. Addressing inspections separately allows for appropriate assignment of VRFs and VSLs.
Associated Electric
Cooperative Inc.
Agree
NPCC
Agree
WECC Reliability Coordination
Agree
Western Area Power
Administration, Upper Great
Plains Region
Agree
SERC Vegetation
Management Subcommittee
(VMS)
Agree
Kansas City Power & Light
Agree
Western Area Power
Administration, Rocky
Mountain Region
Agree
SERC OC Standards Review
Group
Agree
Florida Power & Light
Agree
Santee Cooper
Agree
Southern Company
Agree
E.ON U.S.
Agree
September 8, 2009
168
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Bonneville Power
Administration
Agree
FirstEnergy
Agree
Question 14 Comment
MRO NERC Standards Review Agree
Subcommittee
Midwest ISO Stakeholders
Standards Collaborators
Agree
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
Exelon
Agree
Central Maine Power
Company
Agree
City of Tallahassee
Agree
Northern California Power
Agency (NCPA)
Agree
Northern Indiana Public
Service Company
Agree
Tampa Electric Company
Agree
Orange and Rockland Utilities
Inc.
Agree
American Transmission
Agree
September 8, 2009
169
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 14 Comment
Company
Ameren
Agree
Nebraska Public Power District Agree
Long Island power Authority
Agree
USDA Forest Service,
Southwestern Region,
Regional Office for AZ and NM
Agree
Manitoba Hydro
Agree
Consumers Energy Company
Agree
National Grid
Agree
Pacific Gas & Electric Co.
Agree
Hydro One Networks Inc.
Agree
Consolidated Edison Company Agree
of New York (CECONY)
WECC
Agree
Duke Energy Corporation
Agree
CenterPoint Energy
Agree
Entergy Services
Agree
Pepco Holdings, Inc
Agree
September 8, 2009
170
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Agree?
Question 14 Comment
Independent Electricity System Agree
Operator
Northeast Utilities
Agree
Hydro-Quebec Transenergie
(HQT)
Agree
Buckeye Power, Inc.
Agree
Great River Energy
Agree
September 8, 2009
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
15. Several alternatives to R4 were considered by the drafting team. The drafting team explored these significantly
different alternatives at length. They are outlined below to provide background to industry during this comment
period. (Please refer to pages 22-32 in the Technical Reference Document on the Critical Clearance Zone for further
background for this question.) Do you agree that R4 is written in the most effective way to achieve the purpose of the
standard? If not, what do you propose as an alternative to R4 that would ensure a level of reliability equal to or better
than FAC-003-1?
As written, R4, a new requirement, stipulates that the Transmission Owner is in violation if an encroachment of the Critical
Clearance Zone occurs at any time. If vegetation enters the Critical Clearance Zone, a violation will have occurred, regardless
of the actual proximity of the vegetation to the conductor at the time. Evidence will be required to prove that no
encroachments of the Critical Clearance Zone have occurred anywhere at any time during the annual compliance period. This
will require the time and effort to postpone vegetation maintenance to perform field investigations and document all possible
encroachments.
One alternative to R4 required immediate removal of the vegetation or immediate implementation of the imminent threat
procedure upon discovery of a possible encroachment of the Critical Clearance Zone, thereby proactively preventing an outage.
A violation would have occurred only if the imminent threat process was not successfully implemented.
Another alternative was a tiered approach. This tiered approach involved a “per thousand mile” metric to determine when a
violation had occurred and the severity of the violation. This metric was an attempt to equitably account for varying exposures
that exist due to widely ranging system sizes.
Summary Consideration: Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The Critical Clearance Zone has been replaced with the “Minimum
Vegetation Clearance Distances”, and Transmission Owners are required to prevent encroachment of vegetation into “Minimum
Vegetation Clearance Distances” as observed in real time.
Ninety-four percent of the commenters disagreed with the proposed alternatives. The SDT classified the comments into 44
different concepts with many commenters weighing in on several concepts. For 37 commenters the dominant concept was
“Measure M4 requires proof of no encroachments, i.e., "prove a negative", compliance certification is difficult.” Below is a
redlined version of R4. reflecting the changes that were made by the SDT.
R4.
Each Transmission Owner shall prevent encroachment of vegetation into the Minimum Vegetation Clearance Distances
(“MVCD”) listed in Attachment 1 for its applicable lines as observed in real-time operating between no-load and their
Rating with the following exceptions: [Violation Risk Factor VRF= Medium][Time Horizon – Real Time]
September 8, 2009
172
Deleted: within
Deleted: Critical
Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Encroachment into the Minimum Vegetation Clearance Distances listed in Attachment 1 resulting from natural disasters.2
Encroachment into the Minimum Vegetation Clearance Distances listed in Attachment 1 resulting from human or animal
activity.3
Brief encroachment into the Minimum Vegetation Clearance Distances listed in Attachment 1 resulting from falling
vegetation.
Deleted: 1.
Formatted: Indent: Hanging: 0.25",
Pattern: Clear (Custom
Color(RGB(211,220,233))), Tabs: Not
at 0.5" + 1.03" + 1.8" + 2.25"
Deleted: 2.
Deleted: 3.
The SDT further weighed the NERC interpretation of the vegetation management standard during FERC’s consideration of
proposed FAC-003-1: A vegetation-related transmission line outage as a result of vegetation that has grown into the predefined clearance zone is a violation of the standard. The Commission adopted that interpretation when it approved NERC’s
proposed reliability standards. It stated, “FAC-003-1 requires sufficient clearances to prevent outages due to vegetation
management practices under all applicable conditions.”4
In reviewing the comments and the FERC opinion the SDT considered 4 options:
Re-word R4 and keep R4 the way it was originally intended (violation would only be if you had the outage)
of Question 15**) {implies that R5, R6, & R7 are retained}
Remove R2 and R4 from the standard. Keep the Critical Clearance Zone
Remove R4 from the standard and revise R2 to have a "trigger distance" for implementation of the imminent threat process.
Keep the Critical Clearance Zone concept in the white paper. Team would need to consider the true definition of an
imminent threat.
Return to the Clearance 2 concept. But define (somehow) that this is a "real time" violation only. Distance could be defined
as the Gallet distance or a multiple of the Gallet distance.
(Alternative B
concept in the white paper.
The SDT made the following changes in line with bullet 4.
R4.
Each Transmission Owner shall prevent encroachment of vegetation into the Minimum Vegetation Clearance Distances
(MVCD) listed in FAC-003-2 - Attachment 1 for its applicable lines as observed in real-time operating between no-load and
their Rating, with the following exceptions:
Deleted: within
Deleted: Critical
Deleted: Zone of
Deleted: 1.
4
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting from natural disasters.
Formatted: Font: 11 pt
Deleted: Encroachments of
Deleted: Critical
2
Examples include, but are not limited to, earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the
Transmission Owner or an applicable regulatory body, ice storms, and floods.
3
Examples include, but are not limited to, logging, animal severing tree, vehicle contact with tree, arboricultural activities or horticultural or agricultural
activities, or removal or digging of vegetation.
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting from human or animal activity.5
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting from falling vegetation.
Deleted: Encroachments of
Deleted: Critical
Formatted: Font: 11 pt
Organization
PJM Interconnection
Agree?
Formatted: No bullets or
numbering, Pattern: Clear (Custom
Color(RGB(211,220,233)))
Question 15 Comment
The current version of this standard, FAC-003-1, kept the subject of vegetation outside of the Rights of Way in the
standard. Why are outside of Rights of Way vegetation issues not mentioned in FAC-003-2, or some responsibility
for looking for outside of Rights of Way imminent threats or issues requiring corrective action plans not
addressed?
Response: The SDT thanks you for your comments. Trees outside of the right of way should be identified and removed as necessary as they are identified
as a threat to the reliability of the line. This function should be part of a vegetation management program as a follow up to the inspection process. Any
vegetation that could pose a threat to the reliability to the line found during the inspection process should be remedied. The purpose statement for FAC003-2 states that the standard is intended to improve the reliability of the electric transmission system by preventing vegetation related outages that could
lead to Cascading.
BCTC
The new requirement in R4 stipulates that the Transmission Owner is in violation if an encroachment of the CCZ
occurs at any time. However, the CCZ changes with each foot of the transmission line from the insulator to the
mid-span, depending on loading, actual operating temperature, wind loading, ice loading, maximum design rating,
maximum operating load, and so on. Further, Measure M4 requires that the Transmission Owner has evidence
demonstrating there were no vegetation encroachments into the CCZ. These requirements may result in having to
LIDAR the lines annually, to prove that trees have not encroached upon the CCZ. This would be an extremely
onerous and expensive requirement for utilities. BCTC strongly supports the alternative to R4 as recommended in
the Comment Form (#15), which is to require immediate removal of the vegetation or immediate implementation of
the imminent threat procedure upon discovery of a possible encroachment of the CCZ, thereby proactively
preventing an outage. This means a violation would occur only if the imminent threat process is not successfully
implemented. This alternative is essentially the same as R2. Therefore, BCTC recommends removing R4 from the
standard entirely.
4
Examples include, but are not limited to, earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the
Transmission Owner or an applicable regulatory body, ice storms, and floods.
5
Examples include, but are not limited to, logging, animal severing tree, vehicle contact with tree, arboricultural activities or horticultural or agricultural
activities, or removal or digging of vegetation.
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Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Associated Electric Cooperative
Inc.
Disagree
Associated Electric Cooperative Inc believes this requirement, as written, is unreasonable since it would prevent
(or at least result in noncompliance) the intrusion within the Critical Clearance Zone (CCZ) of anything or anyone,
including qualified line workers and their tools. It is suggested the words “of vegetation” be added between
encroachment and within. The requirement would then read, “Each Transmission Owner shall prevent
encroachment of vegetation within the Critical Clearance Zone of its applicable lines with the following exceptions:”
The complexity of determining an encroachment into the Critical Clearance Zone is overly burdensome, requiring
engineering calculations and possibly the need for precision measurements. The Transmission Owner (TO)
cannot demonstrate compliance with the Requirement and its companion Measure, M4, since a negative cannot
be proven. Therefore, since the TO must demonstrate compliance (guilty until proven innocent), it is automatically
in violation of the Standard.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time. The
SDT, for clarity, did add the phrase “of Vegetation” as requested.
NPCC
Disagree
September 8, 2009
The purpose of the standard is "To improve the reliability of the Bulk Electric System by preventing vegetation
related outages that could lead to Cascading". We believe that R4 is not the most effective way to achieve this
purpose because it does not provide incentive for Transmission Owners to take advantage of modern technology,
such as aerial laser survey (ALS) using Light Detection and Ranging technology (LIDAR), that is capable of
accurately identifying vegetation which is approaching the CCZ or has encroached into it. In fact R4 provides an
incentive not to utilize this technology because Transmission Owners who identify encroachments would be in
violation of R4 for each identified encroachment. On the other hand, Transmission Owners who choose to be less
proactive often would not identify such encroachments because the CCZ and encroachments of it are generally
not easy to determine without taking precise measurements. Unless the line is heavily loaded or the vegetation is
significantly overgrown, encroachments of the CCZ would not be readily noticed. In most cases these
Transmission Owners would simply remove or cut back incompatible vegetation without taking measurements.
The threat to the line would have been eliminated with no encroachment having been identified.R4 presents a
dilemma for Transmission Owners that are considering making the significant investment in ALS technology. While
the technology would allow them to identify any potential grow-in or fall-in conditions, it would also expose them to
the risk of identifying violations of R4, that would otherwise not have been identified. Violation Risk Factors
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(VRFs), Violation Severity Levels (VSLs), and Time Horizons are not included in this Draft, but after making a
significant investment in ALS, Transmission Owners could be faced with significant additional cost in terms of
NERC penalties. In addition, even if the penalties were relatively low they would be exposing themselves to
violations that less proactive Transmission Owners would not be exposed to. In our view R4 as written would, in
some cases, have the opposite effect of what is intended because the business case for using ALS is more
difficult to make. This will result in less use of ALS and other emerging technology that is likely to be developed.
This would result in fewer problems being identified, a small percentage of which will not be discovered until they
result in a line trip. Still we believe that the concept of the CCZ is a good one and recommend that R4 be changed
so that Transmission Owners are provided with an incentive to invest in the best technology available in order to
ensure the highest level of reliability. The opportunity exists to develop the standard in a manner that encourages
the industry to take advantage of new technology and manage vegetation in a very proactive way. We recommend
that R4 be changed as follows: Modify R4 to require Transmission Owners to immediately implement the imminent
threat process defined in R1.4 when they identify instances where the CCZ is approached or encroached upon.
Failure to do so would be a violation of R4. Eliminate encroachment of the CCZ as a violation of R4. This would
eliminate R2 and incorporate implementation of the imminent threat process into R4.Require Transmission
Owners to report to the Regional Entity on a quarterly basis any instances where the imminent threat process was
implemented due to an encroachment of the CCZ. This would add a reporting requirement for Transmission
Operators. Require Transmission Owners to report to the Regional Entity on a quarterly basis any instances where
either a momentary or sustained outage was caused by grow-ins, Active Transmission Line Right of Way blow-ins,
or Active Transmission Line Right-of-Way fall-ins. This would add three additional reporting requirements for
Transmission Operators. Require Regional Entities to perform additional audits of Transmission Owners that
exceed metrics for violations of the CCZ . The metrics would be established in this Standard based upon 100
circuit miles of applicable lines. This would add an additional requirement for Regional Entities. This concept would
result in a more rigorous standard than FAC-003-01 because of the additional reporting and auditing requirements.
It would drive proactive behavior throughout the industry and provide a significant incentive for Transmisison
Owners to invest in new technology such as ALS that is capable of accurately identifying vegetation that has
approached or encroached upon the CCZ. We believe that this change would result in the identification of more
incipient vegetation-related problems and fewer vegetation-related outages as soon as it was implemented and
would best support the purpose of the Standard.
Response: The SDT thanks you for your comments. The SDT concurs that the use of ALS – LiDar technology, while expensive, could enhance reliability.
However several team members have made the investment and concur that the technology including interpertation software are not sufficiently mature to
be put in a standard. In addition in some cases it would not be cost justifiable over traditional methods of inspection. During the course of our
deliberations the team questioned both FERC and RE staff’s response to a utility finding encrochments with ALS technology and concluded the auditor
would not forgive encrochment even though the Transmission Owner went to extraordinary means to find the encrochment.
Initially the team approached the FERC staff in a meeting in Washington with a proposal that an encrochment not be a violation if the Transmission Owner
implemented the imminent threat procedure successfully before an interruption occurred. The concept was rebuffed by the FERC Staff as a step
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backwards from version 1.
The SDT very carefully and thoroughly examined the merits, disadvantages, ease and difficulties of assessing momentary outages as a violation. The
result of that effort led to the more precise and field observable aspects of R4. It should be noted that by their very nature the exact causes of “momentary
outages” are very challenging to determine and will vary widely from utility to utility. The SDT did not find that such variability was appropriate for a
reliability standard, and chose to address this issue with the language in R4.
Due to the industry impact that arises from zero tolerance for vegetation-related sustained outages, the Drafting Team tried several approaches but could
not find a mechanism in the standard development process to establish a non-zero threshold for outages that was acceptable to FERC staff because
Standard revisions to already approved standards may not lead to less emphasis on reliability.
Western Area Power
Administration, Upper Great
Plains Region
Disagree
R4 as proposed would do nothing to improve the reliability of the BES. In fact, we believe that R4 (as currently
proposed) would impose significantly more stringent requirements than most Transmission Owners have
interpreted FAC-003-1 to require. We believe that if the proposed interpretation would have been offered under
FAC-003-1 that there would have be a great backlash against that Standard. It is our believe that current annual
certifications of compliance for FAC-003-1 by Transmission Owners don't use "any infringement of the CCZ by any
piece of vegetation at any time" as their measure for compliance. It could be argued that this proposal would
actually do more to curtail accurate reporting of potential violations. We believe that making an infringement into
the CCZ a violation and having that violation carry a six (or seven) figure fine would do more to discourage
accurate reporting than any other system under discussion. Making the Transmission Owner prove that an
incursion into the CCZ didn't happen would force an inventory of every inch of the R/W which is a gigantic waste of
resources. Being tasked with proving that something didn't happen could be compared with our justice system
declaring suspects will be considered guilty until they are proven innocent. This is a flawed and blatantly unfair
concept and not a productive way of attaining the Purpose stated in this document. Western (UGPR) is
disappointed by the "zero tolerance" nature of this document and its interpretation that "any infringement of the
CCZ by any piece of vegetation at any time" constitutes a violation. We are not aware of any other NERC
standard that is zero tolerance and question why vegetation is singled out to bear the brunt when several other
factors could contribute to a system cascading event (i.e. relay problems, system configuration, operator issues,
etc). In summation, we believe that a zero tolerance document being applied with "guilty until proven innocent"
principles would do much to create an increasingly adversarial relationship between regulators and the industry.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
SERC Vegetation Management
Subcommittee (VMS)
September 8, 2009
Disagree
The concept of the CCZ is useful as a mental model to visualize required vegetation management work. While
this is a good conceptual tool to drive consistent terminology and proper vegetation management practices, it
remains theoretical in nature and impractical to measure on a span by span basis. The complexity of determining
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an encroachment into the CCZ is overly burdensome due to the need for survey accuracy measurements and
engineering evaluations. In addition, this complexity leads to questions about the ability to audit this requirement.
These complexities introduce reliability and audit issues when encroachments into this conceptual area are
defined as violations. The SERC VMS believes the Sustained Outage, as defined by other measures in this
standard, should be the non-compliance measure. We suggest that the CCZ concept be kept in the technical white
paper and that all references to the CCZ be removed from the body of the standard.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Progress Energy Florida
Disagree
The definition of Critical Clearance Zone includes too many academic and theoretical elements. It is impossible to
provide evidence that vegetation did not encroach into the Critical Clearance Zone during TVMP cycles.
Furthermore, the operations staff performing periodic ground and aerial inspections would need to determine the
CCZ for each foot of transmission line to assure compliance with the standard as it is currently written. The CCZ
concept can neither be implemented or enforced as written. The CCZ refers to Ratings which is defined in the
Glossary of Terms as "The operational limits of a transmission system element under a set of specified
conditions." This definition is too broad to be a consistently enforceable term from one utility or region to the next.
As it is currently written, no exemption exists for vegetation falling from outside the Active Transmission Line Right
of Way into, or lodging in, the theoretical CCZ.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Kansas City Power & Light
September 8, 2009
Disagree
As proposed, Requirement R4 and corresponding Measure M4 will be highly subjective and impractical for the
industry to implement. The determination of a violation due to encroachments into the Critical Clearance Zone will
be subjective in nature due to field judgments, is random and not initiated by a known system event. It also will
not be feasible for utilities to fulfill R4 requirements to ensure and provide evidence that any encroachments into
Critical Clearance Zones have not occurred on their system throughout the year. Requirement R4 is not required
since in the remaining requirements of FAC-003-2 contain the principal elements for compliance in ensuring the
reliability of the bulk power system related to vegetation management of the transmission system. Specifically, the
remaining requirements provide that a transmission vegetation plan be maintained, implemented and regularly
reviewed whereby utilities must perform the requisite vegetation clearance work in order to prevent any sustained
outages on the bulk power system. A sustained outage due to vegetation is a known, measurable event to which
a penalty sanction will be invoked and therefore provides the required impetus for adherence to standard FAC003-2.Requirement R4 and the associated measure M4 should therefore be removed from the proposed standard
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language.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Western Area Power
Administration, Rocky Mountain
Region
September 8, 2009
Disagree
As discussed in the Technical Reference document and question #11 above, the CCZ is a complicated theoretical
envelope surrounding all rated operating positions of the conductor. Its dynamic shape is constantly changing and
is contingent upon location within the span. Calculation of the size and shape of CCZ is based, in part, upon the
design parameters of the transmission facility. However, as-built or long term maintenance conditions can often
diverge from the original design requirements over time. Ground elevations can also change as a result of man
made or natural causes from the original design elevations recorded on plan and profile engineering drawings.
Consequently, accurate field measurement of the as-built CCZ is extremely problematic and strategies that utilize
the calculation of allowable right-of-way tree heights can be hindered by unrecorded deviations from the original
design criteria. Allowable tree height strategies also become increasingly more difficult and impractical with
increasing extremes in terrain. While the CCZ is a very important concept for an effective vegetation
management program it is far to theoretical, dynamic, and impractical to field measure for use as a clear and
precise boundary for regulatory purposes. As such, R4 as written should be deleted from the Standards. Further,
the requirement to provide evidence of something that has not occurred (no vegetation encroachments of the
CCZ) is also impractical. General industry interpretation of R1.2.2 in version 1 of the Standards is that the
specific Clearance 2 distance is the precise boundary that is not to be encroached verses the broader area that is
ultimately mapped out as the conductor moves through "all rated electrical operating conditions". Only the
Clearance 2 distance value is a clear, precise number that can be accurately observed and measured in the field.
If there is a persistence to retain the CCZ concept as a requirement within the Standards, the second bullet option
above regarding the initiation of the imminent threat process upon discovery of a possible encroachment is the
preferred option. Since a potential encroachment into the CCZ is not a violation under this option, exact
determination of the CCZ boundary is no longer as essential. Rather, the focus is on triggering mitigation to
vegetation problems to prevent outages. However, as with question #11 above, there is still no practical way to
determine for regulatory purposes those "potential encroachment" situations that legitimately require initiation of
the imminent threat process from those "potential encroachment" situations that do not. Under this option the
utility is really motivated to initiate the imminent threat process to avoid an impending outage. As such, the
occurrence of an outage becomes the only clear, precise and observable means to determine a Standards
violation. A proposed alternative to ensure a level of reliability equal to or better than FAC-003-1 is to retain the
Clearance 2 requirement (without the imprecise "all rated electrical operating conditions" language) in combination
with the sustained outage requirements of R5, R6 and R7. If an additional margin of safety is determined to be
required, industry performance can be adjusted to become more proactive by increasing the minimum Clearance 2
distance to a value greater than the proposed version 2 Gallet equation (table 1) values. Thinking in terms of the
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CCZ concept, it is obvious that a larger Clearance 2 value translates into a larger CCZ envelope. A larger CCZ
envelope in turn triggers mitigation for possible CCZ encroachments sooner.
Response: The SDT thanks you for your comments and proposed alternatives. Significant changes to R4 have been made to the current draft of the
Standard based upon substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance
Distances”, and Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed
in real time.
Progress Energy Carolinas
Disagree
The definition of Critical Clearance Zone includes too many academic and theoretical elements. It is impossible to
provide evidence that vegetation did not encroach into the Critical Clearance Zone during TVMP cycles.
Furthermore, the operations staff performing periodic ground and aerial inspections would need to determine the
CCZ for each foot of transmission line to assure compliance with the standard as it is currently written. The CCZ
concept can neither be implemented or enforced as written. The CCZ refers to Ratings which is defined in the
Glossary of Terms as "The operational limits of a transmission system element under a set of specified
conditions." This definition is too broad to be a consistently enforceable term from one utility or region to the next.
As it is currently written, no exemption exists for vegetation falling from outside the Active Transmission Line Right
of Way into, or lodging in, the theoretical CCZ.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Southern California Edison
Company
September 8, 2009
Disagree
Q15: SCE does not agree that proposed R4 was written in the most effective way because it establishes a zero
tolerance enforcement policy. SCE agrees that a CCZ incursion should be addressed promptly, but we do not
agree that a CCZ incursion is equivalent to a vegetation-to-line contact, or that a CCZ incursion represents an
imminent threat of flash-over. As written, proposed R4 would require Transmission Owners to prove that a Critical
Clearance Zone incursion has not occurred. Short of a daily ground or aerial inspection of every applicable
transmission line, it is clearly impossible for a Transmission Owner to monitor their active Right of Way on a
24/7/365 basis to ensure a CCZ incursion will not or has not occurred. Bearing in mind that even the most robust
of Transmission VM programs may occasionally identify an anomalous condition (in or outside the active ROW)
that left untreated could lead to a flash-over or vegetation-to-line contact, the identification of such conditions
typically occur during scheduled aerial or ground patrols and addressed timely. Of the two alternatives offered,
SCE finds the first option (second bullet item) to be the most palatable. However, even that option leaves
significant doubt as to practical enforcement, because a Transmission Owner could still be found in violation of two
separate requirements (R4 and R5, R4 and R6 or R4 and R7) should a vegetation-to-line contact (resulting in a
sustained outage) occur. This situation amounts to regulatory double jeopardy. SCE believes that by any
reasonable legal or regulatory measure, requiring a Transmission Owner to prove that a CCZ incursion did not
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occur is impractical and virtually impossible to enforce in a fair and impartial manner. Further, SCE believes that
proposed R4 and corresponding M4 detracts from the purported goal of FAC-003-2 and should be removed.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
SERC OC Standards Review
Group
Disagree
The requirement, as written, compels the Transmission Operator to allocate precious resources to ensuring that a
vegetation encroachment NEVER will occur on any transmission line, regardless of that line's true importance to
maintaining electric transmission system reliability. All lines are not created equal; only those that are involved in
IROLs should be held to a zero tolerance standard. R4, if retained, should begin with "Subject to its legal rights,"
and insert the word "vegetation" between prevent and encroachment. Vegetation, which falls through the Critical
Clearance Zone or falls to lodge within the Critical Clearance Zone, should not be included as violations of the
Critical Clearance Zone. The concept of the Critical Clearance Zone is useful as a mental model to visualize
required vegetation management work. While this is a good conceptual tool to drive consistent terminology and
proper vegetation management practices, it remains theoretical in nature and impractical to measure on a span by
span basis. The complexity of determining an encroachment into the Critical Clearance Zone is overly
burdensome due to the need for survey accuracy measurements and engineering evaluations. In addition, this
complexity leads to questions about the ability to audit this requirement. These complexities introduce reliability
and audit issues when encroachments into this conceptual area are defined as violations. The SERC OCSRG
believes the Sustained Outage, as defined by other measures in this standard, should be the non-compliance
measure. We suggest that the Critical Clearance Zone concept be kept in the technical white paper and that all
references to the Critical Clearance Zone be removed from the body of the standard. R5, R6, and R7 ensure that
version 2 of the standard has reliability requirements equal to version 1; therefore R4 should be removed.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time. The
SDT, for clarity, did add the phrase “of Vegetation” as requested.
Western Utility Arborists
September 8, 2009
The new requirement in R4 stipulates that the Transmission Owner is in violation if an encroachment of the CCZ
occurs at any time. However, the CCZ changes with each foot of the transmission line from the insulator to the
mid-span, depending on loading, actual operating temperature, wind loading, ice loading, maximum design rating,
maximum operating load, and so on. Further, measure M4 requires that the Transmission Owner has evidence
demonstrating there were no vegetation encroachments into the CCZ. To provide evidence demonstrating there
were no vegetation encroachments into the CCZ would be an extremely onerous task and an expensive
requirement for the Utilities. The Western Utilities strongly supports the alternative to R4 as recommended in the
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Question 15 Comment
Comment Form (#15), which is to require immediate removal of the vegetation or immediate implementation of the
imminent threat procedure upon discovery of a possible encroachment of the CCZ, thereby proactively preventing
an outage. This means a violation would occur only if the imminent threat process is not successfully
implemented. This alternative is essentially the same as R2. Therefore, the Western Utilities recommend removing
R4 from the standard entirely.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Florida Power & Light
Disagree
NERC standards require the Transmission Owner certify annually that they are in compliance to the standard for
the entire year. Since there is no way that a Transmission Owner could monitor every span of line every minute of
every day, Requirement R4 cannot be certified. A Transmission owner can only certify that at the time inspected
the system met the specification in the standard and that implementation of its Transmission Vegetation
Management Plan maintains these specifications. As stated earlier, the Critical Clearance Zone is difficult to
accurately identify in the field and without an outage it would be difficult for an auditing body to find and validate.
Requirements R4-R7 are reactive in nature. They are violations after the event has occurred or when the tree wire relationships are so close that emergency action is the only recourse for the Transmission Owner. The
standard needs to drive the Transmission Owner to identify and remove trees threatening the system in a
proactive fashion. A Transmission Owner should never be in violation for timely action to remove a threat to the
system.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Santee Cooper
Disagree
Recommend replacing the word "prevent" in R4 to "monitor". The first alternative that requires immediate removal
of vegetation or immediate implementation of the imminent threat procedure would be a Requirement that could
be measured. In addition, if an encroachment is found it needs to be eliminated and the first alternative specifies
immediate removal. If R4 is left as written, how can you provide evidence that there has been no encroachments
within the Critical Clearance Zone.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
September 8, 2009
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Southern Company
Agree?
Disagree
Question 15 Comment
The Critical Clearance Zone is a concept that adequately describes the salient functionality a Transmission Owner
must consider when determining acceptable clearances. However, the practicality of a requirement that forbids
even one encroachment in the Critical Clearance Zone presents a problem for not only the field personnel doing
the vegetation work, but also the Regional Entity that must enforce the requirement. This zone changes not only
from one span to another, it also changes at each location along each span. The reality is that the difference in
encroaching into the zone and not encroaching into the zone is a matter of a fractional inch. In order to prove noncompliance or to defend compliance at a particular site, all vegetation work would have to be postponed for survey
accuracy equipment and appropriately trained personnel to be brought to the site, measurements and calculation
to be made and consequently a determination rendered. This hardly seems worthwhile when the vegetation could
simply be cut, the threat removed and the vegetation work could continue on down the transmission line. As
stated in a previous comment, there could be many examples given of encroachments into this theoretical zone
that would neither threaten the transmission line conductor nor cause a reduction in the capacity of the
transmission line. This concept would be better suited to be a “trigger point” that, if found, would be incentive for
the Transmission Owner to either take immediate action or ensure future activities are appropriately scheduled
and implemented. This action may be as urgent as implementation of the immediate threat procedure or as nonurgent as making sure that the upcoming maintenance on that line is scheduled appropriately. If a sustained
outage occurs due to an encroachment, the outage should be the compliance measure.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
E.ON U.S.
Disagree
The concept of the Critical Clearance Zone is useful as a mental model to visualize required vegetation
management work. While this is a good conceptual tool to drive consistent terminology and proper vegetation
management practices, it remains theoretical in nature and impractical to measure on a span by span basis. The
complexity of determining an encroachment into the Critical Clearance Zone is overly burdensome due to the need
for survey accuracy measurements and engineering evaluations. In addition, this complexity leads to questions
about the ability to audit this requirement. These complexities introduce reliability and audit issues when
encroachments into this conceptual area are defined as violations. We believe the Sustained Outage, as defined
by other measures in this standard, should be the non-compliance measure. We suggest that the Critical
Clearance Zone concept be kept in the technical white paper and that all references to the Critical Clearance Zone
be removed from the body of the standard.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
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Bonneville Power Administration
Agree?
Disagree
Question 15 Comment
R4 states that the Transmission Owner is in violation of the Standard if the Critical Clearance Zone is encroached
upon. The CCZ, as defined by the Standard, changes along the transmission line from the insulator to mid-span,
depending on loading, actual operating temperature, wind and ice loading, maximum design rating and operating
load, etc. Also, the tandem, Measure M4, requires that the Transmission Owner has evidence demonstrating that
there has been no vegetation encoachments in the CCZ along its transmission system. In order to meet the letter
of the Standard, that is to provide evidence that no encroachments in the CCZ have occurred under all manner of
these fluid environmental and operating conditions, the Transmission Owner would have to employ the highest
level of modeling technology available, which would seem to be LiDAR technology. The standard should not be
written in such a manner so that it requires, by all intent and purpose, a Transmission Owner to acquire a
particular technology. BPA recommends that the Alternative represented by "the second bullet" above, be used
rather than R4 in its present state, or that R.4. be simply dropped and R1.4 modified to state that the imminent
threat procedures include immediate removal of encroachments into the Critical Clearance Zone. Also, the term
"immediate" implies instantaneous response. The use of another term is recommended, such as "as immediate
as human health and safety considerations allow, in order to prevent the possibility of flashover".
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Public Service Electric and Gas
Company
Disagree
An additional clarifying exception in the footnotes to R4 consisting of a tree that is located off of the transmission
owner's right of way falling into the CCZ should be added to the encroachment exceptions. Transmission owners
should not be found in violation of the standard for falling vegetation located off of the TO's property.
Response: The SDT thanks you for your comments. The SDT has added the exception you requested. Note that the exception applies to any falling
vegetation regardless of its location.
3. Brief encroachment into the Minimum Vegetation Clearance Distances listed in Attachment 1 resulting from falling vegetation.
FirstEnergy
September 8, 2009
Disagree
Providing evidence to prove that there were no encroachments of the CCZ is difficult at best. An occurrence of an
encroachment does not necessarily translate to an outage. The CCZ is dynamic and difficult to measure exactly
from span to span and day to day and is dependent on environmental and line conditions. The costs to comply
with this requirement as written are difficult to justify considering that reliability may not be improved at all.
FirstEnergy believes that the first alternative above should be used and is a more logical approach from both a
reliability and compliance standpoint. Furthermore, since the first alternative is already covered by the currently
proposed wording of R2, the only changes needed to the standard are to remove the proposed R4 and M4 and renumber the requirements.
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Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
MRO NERC Standards Review
Subcommittee
Disagree
The MRO believes R4 should be eliminated as vegetation contacts are covered in R5 and R6. A violation should
only occur with a vegetation contact. Assessing a violation and fine for a potential reduction in system reliability is
not correct. Actual contacts that trip a transmission element have some measurable impact on system reliability
even if it is slight.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Midwest ISO Stakeholders
Standards Collaborators
Disagree
The second bulleted alternative above is the best approach, but it should be improved by changing the imminent
threat trigger from "encroachment of the CCZ" to "encroachment within some observed, field distance that is a
multiple of the Gallet distances referenced in Table I". We have recommended changes to accomplish this in
Requirement R2 (see our response to Question #11 above), and R4 should simply be deleted. While the CCZ is
valuable to understanding the movement of conductors, it cannot be readily applied in the field. This field
application challenge is noted in the Technical Reference Document (pages 29 & 30).The way R4 is currently
stated, the Transmission Owner would be in violation of R4 for any CCZ encroachment not due to natural
disasters or human or animal activity. This would include a tree falling from outside the right of way corridor that
passes through the theoretical CCZ. Furthermore, Transmission Owners would be required to self-certify
compliance with R4, and we don't think there's any way to do that. Clearly the approach of assessing violations
for CCZ encroachment is unworkable. Likewise, the third alternative listed above is untenable. The tiered
approach could have a mitigating effect on violations, but it would require the same inspection effort and
postponement of vegetation management that makes the first alternative unworkable. Both the first and third
alternatives would require very significant additional expenditures for surveys and documentation in an impossible
attempt to certify compliance - money that would be better spent controlling vegetation.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time. The
proposed standard revision specifies the MVCD as a starting point and TO’s may apply multiples at their own discretion in order to achieve their TVMP
objectives and adhere to applicable safety standards.
SERC Compliance Staff
September 8, 2009
Disagree
The concept of the Critical Clearance Zone is useful as a mental model to visualize required vegetation
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management work. While this is a good conceptual tool to drive consistent terminology and proper vegetation
management practices, it is impractical to measure on a span by span basis. The complexity of determining an
encroachment into the Critical Clearance Zone is overly burdensome due to the need for survey accuracy
measurements and engineering evaluations. While it may be a technically sound approach to designate the
clearance zone to be tied to the conductor movement envelope as found in the NESC, this results in a bananashaped zone that is difficult to substantiate in the field by entity and compliance personnel. We suggest that the
Critical Clearance Zone concept be kept in the technical white paper and that all references to the Critical
Clearance Zone be removed from the body of the standard.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
ITC HOLDINGS
Disagree
First, it’s impossible to determine that no encroachments into the CCZ have occurred at any time and
determination of the CCZ from the field perspective is problematic. The standard is ambiguous and it seems like
clear cutting is the underlining message that is wanted. Determining an encroachment into the CCZ is problematic
due to the need for survey accuracy measurements and engineering evaluations. This will also lead to questions
about the ability to audit this requirement. The CCZ changes in size and shapes continuously in each and every
span and will be difficult to monitor. This would require field personnel to spend numerous hours estimating and
attempting to measure potential encroachments of the CCZ. The way R4 is currently written the Transmission
Owners would be required to self-certify compliance with R4, and which we don’t think this is possible. This will
lead to audit issues with more scrutinizing and potentially more penalties or fines. It is important to recognize that
the ultimate goal of the standard is to ensure that vegetation management is conducted in order to maintain an
adequate level of reliability, and not to precisely measure clearance zones. Alternative 2 would be the most logical
choice, depending on easement/legal rights, with changes that would eliminate any reference to a trigger point into
the encroachment zone of the CCZ to; measuring encroachment to a fix distance (Gallet tables) observed by field
personnel
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Tennessee Valley Authority
September 8, 2009
Disagree
TVA recommends that R4 be removed from this standard. Since this is a "zero tolerance" standard with substantial
penalties for controllable vegetation related outages there is an overwhelming incentive for the Transmission
Owner to proactively perform inspections, preventative maintenance, inpections and corrective maintenance to
prevent potential outages. As such, R4 does not add any value to improving reliability while causing numerous
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unresolvable problems.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Exelon
Disagree
The first bullet is unworkable in the real world. It will be virtually impossible to prove that "no encroachments of the
CCZ have occurred anywhere at any time during the compliance period". The effort to do this will not enhance
reliability. In fact, in may harm reliability by requiring unnecessary investments and O&M expenditures that could
be better spent on real reliability enhancements. Exelon agrees, subject to the development of a workable
definition of the CCZ, that the second bullet is the preferred approach.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Central Maine Power Company
Disagree
Central Maine Power Company suggests the second alternative to R4 as recommended above, which is to
require immediate removal of the vegetation or immediate implementation of the imminent threat procedure upon
discovery of a possible encroachment of the critical clearance zone, thus preventing an outage. This alternative is
similar to R2, therefore R4 may not be required.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
American Electric Power (AEP)
September 8, 2009
Disagree
AEP disagrees with the proposed requirement that violations be automatically declared if the CCZ is encroached.
Instead, AEP would support a standard utilizing the first alternative proffered in these comment questions. While
the CCZ is an interesting theoretical concept, it is not realistically feasible in the field to implement a concept that
depends on accurate measurements and calculations. Further, the proposed requirement offends common notions
of reliable maintenance methods, because it demands that forestry crews stop work if they see a potential
encroachment and that surveyors and engineers be brought in to take detailed measurements and perform
complex calculations to determine whether an encroachment has in fact occurred. The need for a reliable
transmission grid would be much better served by a standard utilizing the first alternative, in which no violation
occurs in the event of an encroachment as long as the TO implements its imminent threat procedure and removes
the vegetation. While seemingly technically appealing, the CCZ concept is fraught with implementation difficulties.
It should not be used as a Pass/Fail zero-tolerance decision point to determine whether a violation has occurred.
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After all, a zero-defect condition has not been achieved in many other aspects of electric utility operation. For
instance, the utility industry attempts every year to conduct its business without any workplace deaths, yet deaths
occur every year. Many millions of dollars are spent by North American utilities to promote safety programs and
safe work procedures, but some work-related vehicle accidents and personal injuries still occur. Also, utilities
aggressively investigate electric switching errors and have instituted rigorous dispatcher-training programs, but a
few switching errors still occur. For an industry in which billions of stems of vegetation must be managed, even a
high six-sigma level of quality would still result in a few cases annually of imperfectly managed vegetation. It is
unreasonable to expect zero-tolerance perfection with the CCZ concept. Also, with the way R4 is worded, a tree
falling from outside the right of way would result in a violation if it passed through the CCZ, whether it resulted in
an outage or not. It is not appropriate to place a burden on the TO for such circumstances outside the TO's
control. As R4 is written, it appears that there is no way that a TO could certify at the end of the year that it has
maintained a CCZ free of encroachments, even if no outages occurred. AEP believes a more effective and
reliability-centered approach would be one where TOs are expected to implement their imminent threat procedure
if vegetation is encroaching upon the Gallet equation distance. If TOs act accordingly and remove the vegetation
without incurring an outage, then they would not be in violation. However, if the TOs knew of vegetation
encroaching upon the Gallet equation distance but failed to implement their imminent threat process, they would
be in violation and be obliged to report the event.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Platte River Power Authority
Disagree
This requirement should be removed completely. It is too stringent and it is impossible to prove compliance
through documentation. Encroachemnt of Clearance 2 (or CCZ) should be addressed in the imminent threat
procedure.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
City of Tallahassee
September 8, 2009
Disagree
VEHEMENTLY DISAGREE! The purpose of the standard is to prevent vegetation related outages. A violation
should occur if an outage occurs. As written, R4 and M4 would be impossible to prove or disprove. It is not like
we can get up there with a tape measure and measure it. R2 requires action if the CCZ is "approached". This is
undefined and subject to a myriad of interpretations. Evidence is hard enough to obtain to the satisfaction of the
Compliance Monitor. To require sufficient evidence to prove that something didn't occur is a tremendous burden
and is not a wise expenditure of vegetation management dollars. Let us spend the money on trimming and not on
paperwork. As an alternative replace "encroachment within the Critical Clearance Zone" with "vegetation caused
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outages". This would allow the same exceptions and is much easier to prove or disprove with a breaker operation.
Although this would result in the cause of every breaker operation being tracked, it is a tangible evidence
requirement and leaves very little room for interpretation. The levels of fines have already shown that vegetation
management is a serious standard and we had better comply.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Northern Indiana Public Service
Company
Disagree
It will be impossible for a T.O. to provide "evidence" that no encroachments of the C.C.Z. occurred at any time
during the year. This approach will be a compliance nightmare and is unworkable. How does one prove this never
happens? You can't monitor every span of every line at all times. Obviously, whenever a T.O. has a preventable
outage, that should be a violation. To address the issue of preventing outages before they occur and penalizing
T.O.'s who don't take proper steps to prevent them, I prefer the approach of immediate removal of threatening
vegetation that encroaches within a "threat trigger/action threshold" clearance distance per the T.O.'s formal
imminent threat procedure. This "threat trigger/action threshold" clearance would be established by the T.O. and
be a specific requirement under a revised FAC-003.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Tampa Electric Company
Disagree
This is a good start. The Critical Clearance Zone (CCZ) is a very real and practical concept; however, it is not
transferable to field conditions. This could result in a "fill in the blank" standard relative to what the Critical
Clearance Zone will be in terms of distance. As I read this, it will be a sliding scale from insulator to mid span and
back for each designated line voltage. The max wind speed to be used and other assumptions behind the
determination of this zone may be as involved a Gallet's formula. This will lead to complications during operational
inspection and verification of these clearances.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Orange and Rockland Utilities
Inc.
September 8, 2009
Disagree
We believe that R4 is not the most effective way to achieve the purpose of the Standard. As previously stated the
CCZ and encroachments of it are generally not possible to identify in the field without taking precise
measurements. The CCZ changes in size and shape continuously throughout each and every span. In many
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cases the CCZ can be very large, and the position of the conductor with respect to encroaching vegetation within
the CCZ can be relatively far apart. Such cases would typically not be identified as encroachments of the CCZ by
visual inspections. Only those instances where the vegetation is significantly overgrown would be readily
identifiable. R4, as written presents a problem in terms of compliance, certification of compliance, and auditing
because precise measurements of every span are impractical and costly to perform. Certification of compliance
would require field personnel to spend valuable time estimating and attempting to measure potential
encroachments of the CCZ. R4 does not provide incentive for Transmission Owners to deploy modern technology
that is better able to identify encroachments of the CCZ with a reasonable amount of accuracy, such as ALS and
LIDAR which are described in the response to Question 11. In fact R4 might provide an incentive not to utilize this
technology because Transmission Owners who identify encroachments using ALS which would otherwise not
have been identified would be in violation of R4. Transmission Owners that choose to be less proactive often
would not identify such encroachments and would be at less risk of violating R4. The effect could be less frequent
use of ALS and other technology that may emerge. This would result in fewer problems being identified, a small
percentage of which may not be discovered until they result in a line trip. We believe that the best way to achieve
the purpose of this Standard is to encourage proactive behavior which prevents vegetation-related outages
throughout the entire industry. R4 does not achieve this in the most effective way. We recommend the following:
Eliminate encroachment of the CCZ as a violation of R4. Require Transmission Owners to immediately implement
the imminent threat process defined in R1.4 when they identify instances where vegetation has grown within a
specific distance as described in the response to Question 11 regarding R2. This would essentially combine R2
and R4.Require Transmission Owners to report to the Regional Entity any instances where the imminent threat
process was implemented due to a vegetation-related clearance encroachment. This would add a reporting
requirement for Transmission Owners. Require Regional Entities to perform additional audits of Transmission
Owners that exceed metrics for vegetation-related clearance encroachments. The metrics should be established in
the Standard based upon 1000 circuit miles of applicable lines. This would add an additional requirement for
Regional Entities. Modify R5, R6, and R7 to include preventing momentary outages as well as Sustained Outages.
We believe that this concept would result in a more rigorous standard because of the additional requirements, but
would focus the industry's attention in a more effective fashion. We believe it would result in fewer vegetationrelated interruptions and a higher level of reliability soon after implementation, and would therefore best support
the purpose of the Standard.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
The SDT very carefully and thoroughly examined the merits, disadvantages, ease and difficulties of assessing momentary outages as a violation, and
chose to address this issue with the language in R4.
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American Transmission
Company
Agree?
Disagree
Question 15 Comment
While the CCZ is valuable to understanding the movement of conductors, it cannot be readily applied in the field.
This field application challenge is noted in the Technical Reference Document (pages 29 & 30).The way R4 is
currently stated, the Transmission Owner would be in violation of R4 for any CCZ encroachment not due to natural
disasters or human or animal activity. This would include a tree falling from outside the right of way corridor that
passes through the theoretical CCZ. Furthermore, Transmission Owners would be required to self-certify
compliance with R4, and ATC does not think there is a practical way to do that. Clearly, the approach of
assessing violations for CCZ encroachment is unworkable. ATC believes that R4 should be deleted.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Xcel Energy
Disagree
The way this requirement is written may require a utility to prove a negative. In other words, prove that we did not
have trees encroaching into the CCZ at any time. This is impossible to prove. We propose the following
language: ?The TO shall not have a encroachment within the CCZ which was not dealt with by utilizing the
imminent threat procedure before experiencing a Sustained Outage, with the following exceptions 1)
Encroachment of the CCZ that result for natural disasters 2) Encroachment of the CCZ that result from human or
animal activity."
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Ameren
Disagree
September 8, 2009
The second bulleted alternative above is the best approach, but it should be improved by changing the imminent
threat trigger from "encroachment of the CCZ" to "encroachment within some observed, field distance that is
defined in the Plan. This would allow Transmission Owners to define for field personnel a CCZ that accomplishes
some multiple of the Gallet distances referenced in Table I" but is easy to determine and apply. We have
recommended changes to accomplish this in Requirement R2 (see our response to Question #11 above), and R4
should simply be deleted. While the CCZ is valuable to understanding the movement of conductors, it cannot be
readily applied in the field. This field application challenge is noted in the Technical Reference Document (pages
29 & 30).The way R4 is currently stated, the Transmission Owner would be in violation of R4 for any CCZ
encroachment not due to natural disasters or human or animal activity. This would include a tree falling from
outside the right of way corridor that passes through the theoretical CCZ. Furthermore, Transmission Owners
would be required to self-certify compliance with R4, and we don't think there's any way to do that. Clearly the
approach of assessing violations for CCZ encroachment is unworkable. Likewise, the third alternative listed above
is untenable. The tiered approach could have a mitigating effect on violations, but it would require the same
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inspection effort and postponement of vegetation management that makes the first alternative unworkable. Both
the first and third alternatives would require very significant additional expenditures for surveys and documentation
in an impossible attempt to certify compliance - money that would be better spent controlling vegetation.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Nebraska Public Power District
Disagree
NPPD disagree with an encroachment being a violation. A lot of time would need to be spent to determine if an
encroachment occurred and in a self regulating environment, reporting would be minimal if any. The Transmission
Owner would be in violation for any non natural event. Even a tree falling into the ROW passing through CCZ
would be in violation of R4. Difficult at best to enforce. We need to spend time keeping the ROW cleared and less
time inspecting for possible encroachments.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Long Island power Authority
Disagree
The Standard is about preventing outages and having an effective program. An effective program should allow for
the identification of a threat and the removal of the threat prior to a vegetation caused outage. I prefer alternative
2. If a vegetation caused outage should occur or if the Regional Entity determines a violation occurred based on a
compliance investigation then the entity is in violation of this requirement.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
USDA Forest Service,
Southwestern Region, Regional
Office for AZ and NM
Disagree
The wording appears too strong. Who can predict the unforeseen circumstances that inevitably arise. If the
standards require the reporting of encroachments, the ensuing report can help determine if the Transmission
Owner did everything reasonable to avoid the problem. It seems like the standard should be written to require the
Transmission Owner to do everything reasonable to avoid the problem. A judgment call would still be needed to
evaluate the performance.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
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Manitoba Hydro
Agree?
Disagree
Question 15 Comment
Manitoba Hydro asserts that the reliability of the system is measured by outage, not by the possibility of an outage,
and therefore if the overall vegetation management system (plan-patrol-discover-mitigate) is effective in preventing
an outage, then the reliability of the system has been maintained, and the intent of the reliability standard
achieved. Therefore, we propose that the second bullet above is the preferred alternative, and that R2 and R4 be
combined as the violation of R4 would then imply a violation of R2.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Consumers Energy Company
Disagree
The CCZ does not provide adequate clearance and the imminent threat procedure if successfully implemented
only works IF YOU KNOW ABOUT THE VEGETATION THAT THREATENS THE CCZ which cannot be ensured
with yearly inspections. Consumers Energy believes that the Clearance 2 distances in FAC-003-1 provide more
reliability than the CCZ proposed in this draft or any of the alternatives disused above.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Pacific Gas & Electric Co.
Disagree
PG&E believes a "minimum clearance distance" or "do not encroach zone" is a critical element of this standard
and necessary to achieve the stated purpose of preventing vegetation caused outages. Preventing vegetation
encroachments will prevent outages. However, PG&E disagrees with using the CCZ as a minimum clearance
requirement because it is ambiguous and subject to wide variations and interpretation. CCZ is a good concept to
aid in understanding movement of conductors but is a theoretical calculation and would be very difficult if not
impossible to enforce. PG&E suggests using a clearly defined distance such as Gallet equation plus a safety
margin to assure there is no chance of spark over. Two times Gallet would be a reasonable clearance
requirement to assure a spark over does not occur and eliminate the ambiguity of the CCZ as the "do not
encroach zone".
Response: The SDT thanks you for your comments. The SDT discussed the Gallet plus alternative suggested by PG&E. Due to the tremendous variation
of design standards, the team decided that the decision as to how much a margin for error to use belonged to the individual TO. The essential changes
are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and Transmission Owners are required to prevent encroachment of
vegetation into “Minimum Vegetation Clearance Distances” as observed in real time. The threat of a violation is believed sufficient to motivate a
Transmission Owner to maintain a larger clearance.
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NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Agree?
Disagree
Question 15 Comment
The new requirement in R4 stipulates that the Transmission Owner is in violation if an encroachment of the CCZ
occurs at any time. However, the CCZ changes with each foot of the transmission line from the insulator to the
mid-span, depending on loading, actual operating temperature, wind loading, ice loading, maximum design rating,
maximum operating load, and so on. Further, Measure M4 requires that the Transmission Owner has evidence
demonstrating there were no vegetation encroachments into the CCZ. These requirements may result in having to
LIDAR the lines annually, to prove that trees have not encroached upon the CCZ. This would be an extremely
onerous and expensive requirement for utilities. NV Energy strongly supports the alternative to R4 as
recommended in the Comment Form (#15), which is to require immediate removal of the vegetation or immediate
implementation of the imminent threat procedure upon discovery of a possible encroachment of the CCZ, thereby
proactively preventing an outage. This means a violation would occur only if the imminent threat process is not
successfully implemented. This alternative is essentially the same as R2. Therefore, we recommend removing R4
from the standard entirely.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
San Diego Gas & Electric
Disagree
The new requirement in R4 stipulates that the Transmission Owner is in violation if an encroachment of the Critical
Clearance Zone (CCZ) occurs at any time. However, the CCZ changes with each foot of the transmission line
from the insulator to the mid-span, depending on loading, actual operating temperature, wind loading, ice loading,
maximum design rating, maximum operating load, and so on. Further, Measure M4 requires that the
Transmission Owner have evidence demonstrating there were no vegetation encroachments into the CCZ. These
requirements may result in having to LIDAR the lines annually to prove that trees have not encroached upon the
CCZ. This would be an extremely oerous and expensive requirement for utilities. We strongly support the
alternative to R4 as recommended in the Comment Form, which is wto require immediate removal of the
vegetation or immediate implementation of the imminent threat procedure upon discovery of a possible
encroachment of the CCZ, thereby proactively preventing an outage. This means a violation would occur only if
the imminent threat process is not successfully implemented. This alternative is essentially the same as R2.
Therefore, we recommend removing R4 from the standard entirely.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Hydro One Networks Inc.
September 8, 2009
Disagree
A statement is needed that this requirement applies to the active right of way. Outside of the active right of way
there is no guarantee that this can be achieved. As noted in the question above, it may be very difficult with the
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Question 15 Comment
first alternative to provide adequate evidence that no encroachment had occurred over the compliance period, as
the situation is very difficult to assess along each span to the accuracies (1/100 of a foot) spelled out for the CCZ.
It may be more meaningful that the Transmission Owners be able to demonstrate processes, methodologies and
actions that can support that vegetation has not entered the CCZ. Another alternative for R4 could then be: Each
Transmission Owner shall demonstrate that adequate actions and processes are in place to prevent vegetation
from entering the CCZ. The effectiveness of the process can then be evaluated based on methods used for field
assessment and performance, i.e., outages and imminent threat reporting. It appears that the second alternative
noted above can be combined with R2. It is not clear why there needs to be a separate requirement. Hydro One
is not in favour of alternative 3, as this would create added administration with a situation that will be difficult to
prove to the accuracy required. LIDAR may be the only means available to provide evidence of a quality needed
to produce meaningful statistics, and in many cases this may not be the most efficient use of the limited funding
that is available.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Edison Electric Institute
Disagree
Encroachment without a Sustained Outage should not be construed as a violation. The proposed R4 requirement
should be removed. EEI strongly believes that this requirement, if approved, is unenforceable. The alternative, to
require implementation of the imminent threat procedure, should be considered as a practical approach. In
particular, this concern applies to a requirement to prove that no encroachments have existed. This will require
extensive work by field personnel, who will be required to make subjective judgments. In addition, determining
actual clearance zones in the field would require a span-by-span analysis to be conducted with the rigor of survey
level measurements. Calculations made to determine the clearance zones are based on undefined terms and
subject to wide variation. Enforcement authorities will be required to make interpretations. EEI believes that the
costs of conducting such work will not deliver sufficient benefit to warrant the requirement. Ultimately, there is no
basis for determining whether the theoretical clearance zones included in the proposed standard will increase, or
even maintain, an adequate level of reliability as provided by the existing standard.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Consolidated Edison Company
of New York (CECONY)
September 8, 2009
Disagree
CECONY disagrees with R4 as currently written. As mentioned in the response to Question 15, performing a field
measurement of the CCZ and a field measurement of the vegetation encroaching into the CCZ are complicated,
time-consuming efforts. As the CCZ changes along the conductor, so too may the Active ROW dimensions, the
vegetation clearances at multiple points, and elevation levels to name a few. Certifying compliance that no
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encroachments have occurred would be very difficult for auditors and field inspectors. Modern laser technology
would have to be deployed to take these measurements and CECONY is concerned that, if an encroachment of
the CCZ constitutes a violation, utilities would not consider investing in this technology knowing that multiple
violations could potentially be found within a single span. Enhanced reliability is achieved when utilities invest in
the best available technology and perform proactive inspections on their systems but, as written, R4 would not
effectively motivate a utility to follow through with these initiatives.
We recommend that the term 'momentary outage' or the phrase 'all outages' be used in R5, R6, and R7 instead of
'Sustained Outages' to avoid confusion throughout the industry. Momentary outages identify a potential failure of
the utility's vegetation management program and stating it directly in the Standard clearly sends the message to
utilities that all vegetation outages are unacceptable. In summary, we do not agree that encroachments are
violations but we do recommend that when a utility identifies vegetation-related imminent threats and takes
immediate action, they report this to their Reliability Coordinator. The Reliability Coordinator (RC) could then
identify the utilities that have had multiple issues or have exceeded acceptable pre-established reporting limits
which, in turn, would help the RC prioritize auditing efforts. This, in our opinion, would enhance reliability more
effectively.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
The SDT very carefully and thoroughly examined the merits, disadvantages, ease and difficulties of assessing momentary outages as a violation. The
result of that effort led to the more precise and field observable aspects of R4. It should be noted that by their very nature the exact causes of “momentary
outages” are very challenging to determine and will vary widely from utility to utility. The SDT did not find that such variability was appropriate for a
reliability standard, and chose to address this issue with the language in R4.
Arizona Public Service Company Disagree
September 8, 2009
APS agrees with alternative one. The new requirement in R4 stipulates that the Transmission Owner is in violation
if an encroachment of the CCZ occurs at any time. However, the CCZ changes with each foot of the transmission
line from the insulator to the mid-span, depending on loading, actual operating temperature, wind loading, ice
loading, maximum design rating, maximum operating load, and so on. Further, Measure M4 requires that the
Transmission Owner has evidence demonstrating there were no vegetation encroachments into the CCZ. These
requirements may result in having to LIDAR the lines annually, to prove that trees have not encroached upon the
CCZ. This would be an extremely onerous and expensive requirement for utilities. APS strongly supports the
alternative to R4 as recommended in the Comment Form (#15), which is to require immediate removal of the
vegetation or immediate implementation of the imminent threat procedure upon discovery of a possible
encroachment of the CCZ, thereby proactively preventing an outage. This means a violation would occur only if
the imminent threat process is not successfully implemented. This alternative is essentially the same as R2.
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Question 15 Comment
Therefore, APS recommends removing R4 from the standard entirely.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Baltimore Gas & Electric
Company
Disagree
One concern with the proposed wording is that the verbiage seems to provide a loophole that will count any fallen
tree, or tree with the potential to fall from inside or outside of the R/W (that doesn't meet the criteria in footnotes 4
& 5) that passes or could pass through the CCZ, and that may or may not cause an outage, would qualify as a
violation in the std. There is no other language that I can detect in the std. that counters this point. Determination
of whether or not a fallen tree, or tree with the potential to fall would qualify would be predicated upon height
measurements of the fallen or standing tree(s) relative to the CCZ at max. engineered sag. An alternative wording
suggestion is: "Each Transmission Owner shall prevent encroachment within the Critical Clearance Zone of it's
applicable lines associated with trees that meet the criteria for grow-ins from on or off the Active right-of-way. Fallins from inside or outside of the active right-of-way are not applicable to this sub-requirement." If the occurrence is
a violation, reporting of the incident will be an ethical issue and rely on the honesty of the inspector or whomever
finds the problem. If it's not a violation, it will be more likely that the incident will be reported and can be treated as
"Near Miss' reports are with respect to safety incidents - they provide valuable input to help forestall future more
serious incidents. Consequently, I recommend that no violation occur as long as the 'Imminent Threat Procedure'
is implemented. Further, if there is no violation associated with Imminent Threat Procedure implementation, I
would suggest that falling or standing trees originating from within the active right-of-way that encroached or could
encroach in the CCZ be added to the requirement to enhance the 'Near Miss' data pool.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Duke Energy Corporation
September 8, 2009
Disagree
The second bulleted alternative above is the best approach, but Duke believes it should be improved by changing
the imminent threat trigger from "encroachment of the CCZ" to "encroachment within some observed, field
distance that is a multiple of the Gallet distances referenced in Table I". We have recommended changes to
accomplish this in Requirement R2 (see our response to Question #11 above), and R4 should simply be deleted.
While the CCZ is valuable to understanding the movement of conductors, it cannot be readily applied in the field.
This field application challenge is noted in the Technical Reference Document (pages 29 & 30).The way R4 is
currently stated, the Transmission Owner would be in violation of R4 for any CCZ encroachment not due to natural
disasters or human or animal activity. This would include a tree falling from outside the right of way corridor that
passes through the theoretical CCZ. Furthermore, Transmission Owners would be required to self-certify
compliance with R4. The technological requirements for accurately certifying compliance would be impossible to
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Question 15 Comment
administer. Clearly the approach of assessing violations for CCZ encroachment is unworkable. Likewise, the third
alternative listed above is untenable. The tiered approach could have a mitigating effect on violations, but it would
require the same inspection effort and postponement of vegetation management that makes the first alternative
unworkable. Both the first and third alternatives would require very significant additional expenditures for surveys
and documentation in an impossible attempt to certify compliance - money that would be better spent controlling
vegetation.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
CenterPoint Energy
Disagree
It is not reasonable to expect Transmission Owners to devote resources, both human and financial, to prove that
vegetation never encroached into the Critical Clearance Zone, anytime-anywhere. R4 and M4 should be
deleted.R2 and M2 are sufficient in ensuring a level of reliability equal to or better than FAC-003-1 with some
minor wording changes to adopt similar wording of the alternative to R4 that was considered by the drafting team
that includes "immediate implementation of the imminent threat procedure" for imminent threats of a vegetation
related Sustained Outage in lieu of a nebulous "encroachment of the Critical Clearance Zone". According to the
Technical Reference, it is "nearly impossible to field correlate and accurately 'superimpose' the Critical Clearance
Zone around the conductor". It not likely that the Transmission Owner will know when the Critical Clearance Zone
is approached through field observation. The previous Clearance 2 provided for a specific radial clearance from
the conductor that was much easier to observe. (See comments to Q3 above.)
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Entergy Services
Disagree
1. Entergy believes that outages caused by vegetation are the most reasonable and objective measures for a
violation which is not consistent with the proposed R4. See additional comments in section 16 related to R5, 6,
and 7.
2. If R4 remains, Entergy proposes that the most reasonable approach to this requirement is a variation of the
second bulleted option. This variation would include wording clarifying that only known encroachments of the
Critical Clearance Zone would be considered violations. Entergy is willing to include failures to enact the imminent
threat process (which is really a violation of R2) and also known vegetation inside the Critical Clearance Zone.
This variation should continue to include the exceptions for natural disaster and human activities.
3. Determining objective, quantifiable encroachments into the Critical Clearance Zone is very challenging in field
operations because such determination may require a degree of accuracy only obtainable using survey equipment
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or other sophisticated, costly measuring devices.
4. Entergy is concerned about the challenges of uniform audit ability due to noted uncertainties and the statement
of absolute criteria that have to be shown in the negative. If the first bullet option is approved for R4, Entergy
suggests the sentence “Evidence will be required to prove that no encroachments of the Critical Clearance Zone
have occurred anywhere at the any time during the annual compliance period” be deleted. It is very difficult in
regulatory terms to attest that no vegetation has ever crossed the Critical Clearance Zone during the time period
being reviewed given the wide range of potential conditions that may not have been detected or even been
detectable unless the conditions afforded direct observation. Too many assumptions would have to be made for
an entity to self certify to this requirement. If R4 is implemented as stated, those assumptions need to be stated
and clarified.
5. If any version of R4 is approved, Entergy suggests that the standard include an exception for trees falling from
off the right of way and encroaching the Critical Clearance Zone. For example, a tree that falls from off the right of
way. During the fall towards the conductor, the tree could possibly break the Critical Clearance Zone without
causing an outage or even a threat of an outage yet still be a violation of the proposed standard.
6. If the second bulleted item is approved, it should be altered to read “a violation would have occurred only if no
vegetation imminent threat process was initiated.”
7. Entergy does not feel the third bulleted item is adequately defined to use as a requirement in the standard at
this time.
8. Conditions for blow-out, in the development of the Critical Clearance Zone, need to be defined in the standard.
Their inclusions, in the white paper only, are not appropriate, as well.
Response: The SDT thanks you for your comments and suggested alternatives. Significant changes to R4 have been made to the current draft of the
Standard based upon substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance
Distances”, and Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed
in real time. The SDT addressed your item 5 in subpart 3 in R4. This exception would apply to any falling vegetation outside the right of way or inside the
right of way.
Pepco Holdings, Inc
Disagree
As discussed in our response to Q11, the concept of encroachment into the Critical Clearance Zone is flawed. It is
enforceable almost exclusively through self reports. R5, R6 and R7 provide all incentives for the TO to follow its
inspection and maintenance plans, and R2, if properly written to remove references to the Critical Clearance Zone
provides additional incentives. R4 is not needed and should be deleted. PHI is puzzled where this concept came
from. Nowhere in Order 693 is this concept discussed.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
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substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time. The
concept of the CCZ was originally intended to provide an area that could be used to produce a metric for less than “zero tolerance” however that did not
materialize.
JEA
Disagree
As written, demonstration of compliance may not be feasible and would certainly be prohibitively expensive,
consuming resources better spent managing vegetation. In general, putting entities in the position of proving
something didn't occur is exptremely difficult and burdensome, without really aiding reliability. If the incident was
significant, the region would know about it, and investigations can be pursued, if warranted. The first alternative
requiring implementation of the imminent threat procedure is a better choice.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Salt River Project
Disagree
Disagree with R4 as it is written. The new requirement in R4 stipulates that the Transmission Owner is in violation
if an encroachment of the Critical Clearance Zone occurs at any time. However, the Critical Clearance Zone
changes with each foot of the transmission line from the insulator to the mid-span, depending on loading, actual
operating temperature, wind loading, ice loading, maximum design rating, maximum operating load, and so on.
See additional comments in Comment #18 below. Furthermore, Measure M4 requires that the Transmission
Owner has evidence demonstrating there were no vegetation encroachments into the Critical Clearance Zone. To
provide evidence demonstrating there were no vegetation encroachments into the Critical Clearance Zone would
be an extremely onerous task and an expensive requirement for the utilities. We strongly support changing this to
the 1st alternative written in Comment #15 "One alternative to R4 required immediate removal of the vegetation or
immediate implementation of the immenent threat procedure upon discovery of a possible encroachment of the
Critical Clearance Zone, thereby proactively preventing an outage. A violation would have occurred only if the
immenent threat process was not successfully implemented." This alternative is essentially the same as R2,
therefore, we recommend removing R4 from the standard entirely.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Northeast Utilities
September 8, 2009
Disagree
First - the determination of the CCZ is highly problematic in the field. Second - it is impossible for any utility to
certify that no encroachments have occurred at any time unless a utility has completely removed all potentially
interferring vegetation on all areas of their transmission system. If the standard is to clear-cut and maintain a tree
free right of way, the standard should say so. To determine if vegetation may have violated the CCZ the inspector
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must know at the time of the inspection the ambient temperature, the wind speed, the loading of the line and the
actual distances between the vegetation and conductors. Then, the information must be compared to possible
extreme operating levels of the line under all conditions to know if the vegetation may violate the CCZ. As stated it is improbable that this could accurately be performed in the field as the data changes within each segment of a
span's length. The first alternative provides the most effective means of addressing encroachment of the CCZ having an encroachment is not a violation - knowing there is an encroachment and not correcting the problem
would be a violation. Implementing the imminent threat procedure and correcting the problem is a more effective
approach. Having a zero tolerance for encroachments of the CCZ under all situations and operating conditions
would sub-optimize the use of resources. No actual event may have occurred on the system, yet the utilities will
be in violation just for a possible or potential problem that even under extreme operating conditions may not
actually occur. It would be best if the violations were limited to "known encroachments" (not "possible
encroachments") such as would occur if a line were to trip due to vegetation contact, or if there is evidence of any
burns. If no action was taken on known encroachments to correct the problem (such as implementation of the
imminent threat procedure) then a violation will have occurred. It is doubtful that any utility will be able to certify
that at no time has vegetation encroached into the CCZ. Utilities will have to spend an untold amount of resources
to verify that there have not been any encroachments during a compliance period - instead of using these
resources more effectively in taking proactive measures to manage and control encroaching vegetation. As
written, any encroachment into the CCZ is considered a violation of FAC-003-2 (R4). There are exceptions
provided for encroachments due to natural disasters and human or animal activity. There is no exception for
encroachments due to the failure of a tree(s) outside of the active transmission line ROW. Based on R4, a trip and
reclose of a transmission line (no outage) is a violation even if the tree is outside of the active right-of-way;
whereas per R6 and R7, a line outage would not be a violation if the tree was outside of the active right-of-way.
As written - this is not clear - there should be exceptions to allow for trees falling into the CCZ (and into the active
transmission line right-of-way) from outside the limits of the active transmission line right-of-way. Also - how are
violations of the CCZ requirement to be reported - there is no provision for the reporting process and requirements
(specifics on the type of violation). Will this be addressed in the Compliance Section yet to be added?
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Hydro-Quebec Transenergie
(HQT)
September 8, 2009
Disagree
The purpose of the standard is "To improve the reliability of the Bulk Electric System by preventing vegetation
related outages that could lead to Cascading". We believe that R4 is not the most effective way to achieve this
purpose because it does not provide incentive for Transmission Owners to take advantage of modern technology,
such as aerial laser survey (ALS) using Light Detection and Ranging technology (LIDAR), that is capable of
accurately identifying vegetation which is approaching the CCZ or has encroached into it. In fact R4 provides an
incentive not to utilize this technology because Transmission Owners who identify encroachments would be in
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violation of R4 for each identified encroachment. On the other hand, Transmission Owners who choose to be less
proactive often would not identify such encroachments because the CCZ and encroachments of it are generally
not easy to determine without taking precise measurements. Unless the line is heavily loaded or the vegetation is
significantly overgrown, encroachments of the CCZ would not be readily noticed. In most cases these
Transmission Owners would simply remove or cut back incompatible vegetation without taking measurements.
The threat to the line would have been eliminated with no encroachment having been identified.R4 presents a
dilemma for Transmission Owners that are considering making the significant investment in ALS technology. While
the technology would allow them to identify any potential grow-in or fall-in conditions, it would also expose them to
the risk of identifying violations of R4, that would otherwise not have been identified. Violation Risk Factors
(VRFs), Violation Severity Levels (VSLs), and Time Horizons are not included in this Draft, but after making a
significant investment in ALS, Transmission Owners could be faced with significant additional cost in terms of
NERC penalties. In addition, even if the penalties were relatively low they would be exposing themselves to
violations that less proactive Transmission Owners would not be exposed to. In our view R4 as written would, in
some cases, have the opposite effect of what is intended because the business case for using ALS is more
difficult to make. This will result in less use of ALS and other emerging technology that is likely to be developed.
This would result in fewer problems being identified, a small percentage of which will not be discovered until they
result in a line trip. Still we believe that the concept of the CCZ is a good one and recommend that R4 be changed
so that Transmission Owners are provided with an incentive to invest in the best technology available in order to
ensure the highest level of reliability. The opportunity exists to develop the standard in a manner that encourages
the industry to take advantage of new technology and manage vegetation in a very proactive way. We recommend
that R4 be changed as follows: Modify R4 to require Transmission Owners to immediately implement the imminent
threat process defined in R1.4 when they identify instances where the CCZ is approached or encroached upon.
Failure to do so would be a violation of R4. Eliminate encroachment of the CCZ as a violation of R4. This would
eliminate R2 and incorporate implementation of the imminent threat process into R4.Require Transmission
Owners to report to the Regional Entity on a quarterly basis any instances where the imminent threat process was
implemented due to an encroachment of the CCZ. This would add a reporting requirement for Transmission
Operators. Require Transmission Owners to report to the Regional Entity on a quarterly basis any instances where
either a momentary or sustained outage was caused by grow-ins, Active Transmission Line Right of Way blow-ins,
or Active Transmission Line Right-of-Way fall-ins. This would add three additional reporting requirements for
Transmission Operators. Require Regional Entities to perform additional audits of Transmission Owners that
exceed metrics for violations of the CCZ. The metrics would be established in this Standard based upon 100
circuit miles of applicable lines. This would add an additional requirement for Regional Entities. This concept would
result in a more rigorous standard than FAC-003-01 because of the additional reporting and auditing requirements.
It would drive proactive behavior throughout the industry and provide a significant incentive for Transmisison
Owners to invest in new technology such as ALS that is capable of accurately identifying vegetation that has
approached or encroached upon the CCZ. We believe that this change would result in the identification of more
incipient vegetation-related problems and fewer vegetation-related outages as soon as it was implemented and
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would best support the purpose of the Standard.
Response: The SDT thanks you for your comments and suggestions. The reporting and documenting concept that you suggest has been incorporated in
part in R2. Significant changes to R4 have been made to the current draft of the Standard based upon substantive industry comment. The essential
changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and Transmission Owners are required to prevent
encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Buckeye Power, Inc.
Disagree
Proving vegetation is not in a clearance zone will be difficult without having third-party verification.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Great River Energy
Disagree
GRE supports the elimination of R4, as vegetation contacts are covered in R5 and R6. A violation should only
occur with a vegetation contact. Assessing a violation and fine for a potential reduction in system reliability is not
correct. Actual contacts that trip a transmission element have some measurable impact on system reliability even
if it is slight. In the event that the SDT chooses not to eliminate R4, GRE would also support the alternative
language that is shown under the second bullet.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
WECC
Agree
Yes, R4 as written provides clear guidance to TOs on the minimum radial distance, dependant on line voltage that
vegetation is allowed to approach energized conductors. These industry standardized distances will ensure a level
of reliability equal to or better than FAC-003-1.
Response: The SDT thanks for your comments. Please see the summary consideration for this question – based on other comments, the SDT made
significant revisions to Requirement R4. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
National Grid
Agree
National Grid agrees that there should be no encroachments into the CCZ. However, encroachments in the CCZ
should NOT be considered a violation. Violations should only be for sustained transmission outages.
Response: The SDT thanks you for your comments. Significant changes to R4 have been made to the current draft of the Standard based upon
substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance Distances”, and
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Agree?
Question 15 Comment
Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed in real time.
Northern California Power
Agency (NCPA)
Agree
WECC Reliability Coordination
Agree
Response: The SDT thanks you for your positive feedback. Most commenters disagreed with R4. Changes to R4 have been made to the current draft of
the Standard based upon substantive industry comment. The essential changes are: The CCZ has been replaced with the “Minimum Vegetation Clearance
Distances”, and Transmission Owners are required to prevent encroachment of vegetation into “Minimum Vegetation Clearance Distances” as observed
in real time.
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16. Requirements R5, R6, and R7 define that Sustained Outages due to vegetation growing into, blowing together with,
and falling into transmission lines are violations (subject to certain exemptions). Therefore, all such outages must be
reported as violations of the standard. Do you agree with this change? If not, please explain.
Summary Consideration: Seventy two percent of the respondents agreed with the changes. Multiple commenters made the
following points: Questionable cost benefit, not all lines are equal, complicated and burdensome to know precisely where edge
of ROW is, the standard should read minimize outages and not prevent them. The majority of the team did not agree there
was sufficient argument to support making changes to the requirements based on the comments.
Several commenters pointed out that debris that has been detached from the tree and blown into the conductor and trees from
outside the ROW should be exempt. The team adjusted the standard to accommodate debris and falling from outside the
ROW.
Organization
Western Utility Arborists
Agree?
Question 16 Comment
The Western Utilities strongly recommend that the requirement under R7 be changed from “shall prevent
sustained outages” to “shall minimize sustained outages due to vegetation falling into a conductor.” We note
that the word “minimize” was present in earlier drafts of the document. We are concerned about the
requirement for utilities to prevent sustained outages from vegetation falling into the conductor from within the
active transmission ROW. It is operationally almost impossible to know precisely where the edge of the ROW
is in all situations under all conditions. This could lead to an incident where utilities are charged unreasonably?
for example, for an outage from a tree that was one foot within the active ROW line. We should not be held
liable when reasonable due diligence is practiced. Further, it is not economically feasible for utilities to survey
every ROW in the U.S. and Canada to determine precise clearance zones.
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT. The SDT believes that the Transmission Owner holds responsibility for knowing the location of the edges of its active rights of
way and whether a rooted tree is within or outside the active right of way.
BCTC
BCTC strongly recommends that the requirement under R7 be changed from “shall prevent sustained
outages” to “shall minimize sustained outages due to vegetation falling into a conductor.” We note that the
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Question 16 Comment
word “minimize” was present in earlier drafts of the document.
BCTC is concerned about the requirement for utilities to prevent sustained outages from vegetation falling into
the conductor from within the active transmission ROW BCTC’s operating area covers rugged and remote
terrain, and many areas have accessibility issues. It is operationally almost impossible to know precisely
where the edge of the ROW is in all situations under all conditions. Further, it is not economically feasible to
accurately survey and marked on the ground the absolute width of all ROW in the province. Therefore, we are
concerned about the requirement for utilities to prevent sustained outages from vegetation falling into the
conductor from within the active transmission ROW. This could lead to an incident where BCTC is charged
unreasonably – for example, for an outage from a tree that was one foot within the active ROW line. We
should not be held liable when reasonable due diligence is practiced.
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT. The SDT believes that the Transmission Owner holds responsibility for knowing the location of the edges of its active rights of
way and whether a rooted tree is within or outside the active right of way.
Kansas City Power & Light
Disagree
Exceptions should include flying debris including vegetation.
Response: Thank you for your comment. Your suggestion has been incorporated.
Associated Electric Cooperative
Inc.
Disagree
Requirements 5, 6 and 7, as written, compel the Transmission Owner to allocate precious resources to
ensuring a vegetation related outage will NEVER occur on any applicable transmission line, regardless of the
line's true importance to maintaining electric transmission system reliability. All lines are not created equal;
only those which are an IROL or contribute to IROLs should be held to a zero tolerance standard.
Response: Thank you for your comments. FERC Order 693 affirmed that the Standard shall apply to all transmission lines operating above 200kV as
well as to designated sub-200kV lines. The Standard was prepared in accordance with FERC Order 693.
NPCC
Disagree
NPCC participating members request clarification if violations of R5, R6, and R7 result in outages that must be
reported.
Response: The SDT appreciates your response. Under NERC’s Compliance Guidelines, any violation of a reliability standard requirement must be selfreported; thus, a violation of Requirement R5, R6 or R7 must result in a report from the Transmission Owner.
SERC OC Standards Review
September 8, 2009
Disagree
R5, R6 and R7 should begin with "Subject to its legal rights,”. The requirements, as written, compel the
Transmission Operator to allocate precious resources to ensuring that a vegetation outage NEVER will occur
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Group
Question 16 Comment
on any transmission line, regardless of that line's true importance to maintaining electric transmission system
reliability. All lines are not created equal; only those that are involved in IROLs should be held to a zero
tolerance standard. R5, R6, and R7 ensure that version 2 of the standard has reliability requirements equal to
version 1; therefore R4 should be removed.
Response: Thank you for your comments.
The SDT certainly agrees that all actions taken by a Transmission Owner must be within its legal rights, but believes that inclusion of “Subject to its legal
rights” will tend to unnecessarily limit legitimate actions that a Transmission Owner must take to maintain reliability.
FERC Order 693 affirmed that the Standard shall apply to all transmission lines operating above 200kV as well as to designated sub-200kV lines. The
Standard was prepared in consideration of the directives and recommendations contained in FERC Order 693.
Florida Power & Light
Disagree
As currently written, Requirements R5, R6 and R7 demand perfection. The only acceptable number for all
150K miles of affected transmission line in the US is 0. The standard should be achievable and enable
proactively addressing potential threats to facilities from vegetation. Even using a Six Sigma level of quality
and control, processes can achieve a level of 3.4 defects per million opportunities for defect. Each tree on the
ROW represents one of those opportunities. FPL has outlined an alternative proposal in response to Question
18.
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT.
Santee Cooper
Disagree
Recommend removing R7 because current and proposed standards do not require the entire right-of-way or
Active Transmission Line Right of Way to be clear of vegetation. In this case, a utility should not be penalized
if a tree falls from within the right-of-way or Active Transmission Right-of-Way as long they are meeting all the
other standards (e.g., minimum vegetation clearance distances). Since fall-ins from just outside of the right-ofway is currently not a compliance issue, it makes sense that a fall-in from within the right-of-way be treated the
same. This is especially true for a utility who has elected to acquire a wider right-of-way than another utility.
That utility may have a tree(s) growing just inside the right-of-way but still maintains a better clearance
distance between trees and conductors than a utility with a narrower right-of-way and no tree encroachment.
Response: Thank you for your comments. While it is true that there is a negligible difference in risk to the electric system for trees just within or just
outside the active right of way, the major difference is that the Transmission Owner generally has the right to manage vegetation within the active right
of way. Also, while Transmission Owners employ differing active right-of-way widths, this is essentially uncontrollable by the SDT or by regulators.
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Exelon
Agree?
Disagree
Question 16 Comment
It appears to Exelon that the requirements of the standard have been written and modified at different times
and as a result the document lacks a degree of consistency and coherence. While the Standard mentions
encroachment of the CCZ and Sustained Outages as potential violations, it is completely silent on how
momentary outages should be addressed. Exelon views the following events as a risk continuum that should
be addressed in the Standard and handled as a part of the VRFs and VSLs - encroachment of the air gap
distance, momentary outages and Sustained Outages.
Response: Thank you for your comments. The Minimum Vegetation Clearance Distance is the calculated spark-over distance derived from the Gallet
equations. Therefore a momentary caused by a tree under the circumstances defined in R4 would by definition be a violation of R4.
Platte River Power Authority
Disagree
The requirement under R7 should be changed from "shall prevent sustained outages" to "shall minimize
sustained outages due to vegetation falling into a conductor." We note the word "minimize" was present in
earlier drafts of the document. We are concerned about the requirement for utilities to prevent sustained
outages from vegetation falling into the conductor from within the active transmission ROW. It is operationally
almost impossible to know precisely where the edge of the ROW is in all situations under all conditions. This
could lead to an incident where utilities are charged unreasonably - for example, for an outage from a tree that
was one foot within the active ROW line. We should not be held liable when reasonable due diligence is
practiced.
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT. The SDT believes that the Transmission Owner holds responsibility for knowing the location of the edges of its active rights of
way and whether a rooted tree is within or outside the active right of way.
USDA Forest Service,
Southwestern Region, Regional
Office for AZ and NM
Disagree
I believe that the text for each element should be re-written with the general philosophy that the Transmission
Owner shall do everything reasonable to prevent such problems in line with the comment for section
15.Problems should be reported and investigated and a judgment call should be made about whether the
Transmission Owner did everything reasonable to avoid the problem.
Response: Thank you for your comments. The purpose of this standard is to improve reliability of the electric transmission system by preventing
vegetation-related outages that can lead to cascading by establishing clear and measureable requirements. While the SDT appreciates the value of
judgment in the field FERC has indicated that requirements in proposed Standards be equivalent to or more stringent than the same or similar
requirements in already approved Standards.
Consumers Energy Company
September 8, 2009
Disagree
R5, R6 and R7 should be rewritten as a single requirement for vegetation within the "Active Transmission Line
Right of Way" and the exceptions listed. Additionally, a requirement for hazardous trees outside of the "Active
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Question 16 Comment
Transmission Line Right of Way" should be incorporated into this draft and similar exceptions listed for natural
disasters, third-party, and animal causes.
Response: Thank you for your comments. Requirements R5, R6 and R7 deal with three distinct types of outages which may pose different risks or
severity in terms of impact to the electric system. The SDT chose to break the three requirements apart to allow application of different Violation Risk
Factors because blow-in and fall-in interruptions do pose a significantly lower risk of causing a cascading blackout event.
Regarding incorporating a requirement to address hazardous trees outside the Active Right-of-Way, Transmission Owners generally have the right to
manage vegetation within the Active Transmission Right-of- Way. These rights will not always exist beyond the Active Transmission Right-of-Way.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Disagree
We strongly recommend that the requirement under R7 be changed from “shall prevent sustained outages” to
“shall minimize sustained outages due to vegetation falling into a conductor.” We note that the word “minimize”
was present in earlier drafts of the document. We are concerned about the requirement for utilities to prevent
sustained outages from vegetation falling into the conductor from within the active transmission ROW. It is
operationally almost impossible to know precisely where the edge of the ROW is in all situations under all
conditions. This could lead to an incident where utilities are charged unreasonably ? for example, for an
outage from a tree that was one foot within the active ROW line. We should not be held liable when
reasonable due diligence is practiced. Further, it is not economically feasible for utilities to survey every ROW
in the U.S. and Canada to determine and document precise clearance zones. Such costly effort would not
produce any benefit to the reliability of the bulk electric system.
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT. The SDT believes that the Transmission Owner holds responsibility for knowing the location of the edges of its active rights of
way and whether a rooted tree is within or outside the active right of way.
San Diego Gas & Electric
Disagree
We recommend that the requirement under R7 be changed from "shall prevent sustained outages" to "shall
minimize sustained outages due to vegetation falling into a conductor." The word minimize was present in
earlier drafts of the document. We are concerned with the requirement for utilities to prevent sustained
outages from vegetation falling into the conductor from within the active transmission Right of Way. It is
operationally almost impossible to know precisely where the edge of the ROW is in all situations under all
conditions. This could lead to an incident where utilities are charged unreasonably.
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT. The SDT believes that the Transmission Owner holds responsibility for knowing the location of the edges of its active rights of
way and whether a rooted tree is within or outside the active right of way.
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Hydro One Networks Inc.
Agree?
Disagree
Question 16 Comment
A further exception would be a sustained outage where the conductor has moved outside of the critical
clearance zone. This could occur under conditions of heavy icing, operating outside the line rating or
excessive wind. These would not necessarily be the result of a natural disaster. Also, it is recommended that
the requirement for R7 be revised to “Each Transmission Owner shall minimize (“minimize” replacing
“prevent”) Sustained Outages of applicable lines due to vegetation falling into a conductor”.. A fall in is a
random occurrence and the likelihood that this would be the cause or contribute to a cascading event is very
remote. These types of outages are rare and can be considered similar in nature to an insulator flashover or a
hardware failure, which have not been given any association with cascading events. The purpose of the
standard is to prevent cascading events and it is suggested that this remain the focus and not introduce other
types of outages on a selective basis.
Response: Thank you for your comment. The Critical Clearance Zone (CCZ) has been removed from the standard.
The SDT concurs that fall in events present a lower risk to the system than grow in events. Requirements R5, R6 and R7 have been drafted to address
three distinct types of outages which may pose different risks or severity in terms of impact to the electric system. The SDT chose to break the three
requirements apart to allow application of different Violation Risk Factors and Violation Severity Levels.
Arizona Public Service
Company
Disagree
APS strongly recommends that the requirement under R7 be changed from “shall prevent sustained outages”
to “shall minimize sustained outages due to vegetation falling into a conductor.” We note that the word
“minimize” was present in earlier drafts of the document. We are concerned about the requirement for utilities
to prevent sustained outages from vegetation falling into the conductor from within the active transmission
ROW. It is operationally almost impossible to know precisely where the edge of the ROW is in all situations
under all conditions. This could lead to an incident where utilities are charged unreasonably ? for example, for
an outage from a tree that was one foot within the active ROW line. We should not be held liable when
reasonable due diligence is practiced. Further, it is not economically feasible for utilities to survey every ROW
in the U.S. and Canada to determine precise clearance zones.
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT. The SDT believes that the Transmission Owner holds responsibility for knowing the location of the edges of its active rights of
way and whether a rooted tree is within or outside the active right of way.
Entergy Services
September 8, 2009
Disagree
1. If a version of R4 that states an encroachment to the Critical Clearance Zone is a violation, Entergy
disagrees with the need for R5, R6, and R7 because it is redundant to R4. An outage cause by vegetation: a)
growing into the line b) blowing into the line and c) falling into the conductor would require the vegetation to
break the Critical Clearance Zone. If these requirements stay in the standard, an outage of the above nature
would mean the entity violated two requirements, R4 and R5, R6, or R7. 2. Entergy is amenable to keeping
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Question 16 Comment
R5, 6, and 7 if R4 is removed from the standard. 3. If approved, we suggest that R5, 6, and 7 not apply to
trees from off the right of way.
Response: Thank you for your comments. Requirements R5, R6 and R7 have been drafted to address three distinct types of outages which may pose
different risks or severity in terms of impact to the electric system. The SDT chose to break the requirements apart to allow application of different
Violation Risk Factors and Violation Severity Levels. R4 has been drafted to clarify that clearance encroachments are violations of the Standard. Matters
of being assessed two violations for a single event are addressed in the NERC compliance sanctions guideline.
Salt River Project
Disagree
Recommend that the requirement under R7 be changed from "shall prevent sustained outages" to "shall
minimize sustained outages due to vegetation falling into a conductor". We understand that the word
"minimize" was present in earlier drafts of the document. We are concerned about the requirement to prevent
sustained outages from vegetation falling into the conductor from within the active transmission ROW. It is
operationally almost impossible to know precisely where the edge of the ROW is in all situations under all
conditions. This could lead to an incident where a utility is charged unreasonably - for example, for an outage
from a tree that was one foot within the active ROW line. We should not be held liable when reasonable due
diligence is practiced. Furthermore, it is not economically feasible for utilities to survey every ROW to
determine precise clearance zones.
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT. The SDT believes that the Transmission Owner holds responsibility for knowing the location of the edges of its active rights of
way and whether a rooted tree is within or outside the active right of way.
Hydro-Quebec Transenergie
(HQT)
Disagree
HQT request clarification if violations of R5, R6, and R7 result in outages that must be reported. A further
exception would be a sustained outage where the conductor has moved outside the critical clearance zone.
This could occur under conditions of heavy icing, operating outside the line rating or excessive wind.
Response: Thank you for your comments. Regarding your question on reporting of violations, under NERC’s Compliance Guidelines, any violation of a
reliability standard requirement must be self-reported; thus, a violation of Requirement R5, R6 or R7 must result in a report from the Transmission
Owner. In addition, the revised standard includes compliance elements, including the need to provide periodic reports of specific vegetation-related
outages.
The Critical Clearance Zone (CCZ) is defined by the movement of the conductor between no load and its rating. The Standard does not apply to events
which occur outside of the CCZ.
Southern California Edison
September 8, 2009
Agree
Q16: SCE agrees in part with the establishment of R5, R6 and R7, however, we note that the opening of each
requirement repeats a slightly altered version of the FAC-002-2 purpose statement. We find such
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Question 16 Comment
repetitiveness unnecessary and note that as written, Requirements 5-7 presents a near identical compliance
conundrum for Transmission Owners as Requirement 4. Again, Transmission Owners would be required to
prove that they did not incur a sustained outage due to a vegetation caused flash-over or vegetation-to-line
contact whether it be a grow-in, blow-in or fall-in. Although proving a sustained outage (for cause) did not
occur will be difficult and unwieldy, it is not impossible. The simple difference between a Transmission Owner
disproving the occurrence of a CCZ incursion and their disproving vegetation caused sustained outages, is
that Transmission Owners do in fact keep records of “outages”. Because a Transmission Owner’s record
keeping prowess is the only viable option for proving a vegetation caused outage did not occur, SCE
respectfully suggests R5, R6 and R7 be revised to read:R5 - "Each Transmission Owner shall document
Sustained Outages of applicable lines due to vegetation growing into a conductor operating within its Rating
with the following exceptions:"R6 - "Each Transmission Owner shall document Sustained Outages of
applicable lines due to vegetation blowing into a conductor operating within its Rating and located within an
Active Transmission Line Right of Way with the following exceptions:"R7 - "Each Transmission Owner shall
document Sustained Outages of applicable lines due to vegetation falling into a conductor operating within its
Rating and located within an Active Transmission Line Right of Way with the following exceptions: "We also
note that Footnote 6 is misplaced in the draft and should follow the word “Outages” in each of these
requirements.
Response: Thank you for your comments. Requirements R5, R6 and R7 deal with three distinct types of outages which may pose different risks or
severity in terms of impact to the electric system. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable)
vegetation-related outages. Additionally, the Transmission Owner must document and report outages under NERC’s Compliance Guidelines. However,
the SDT chose to break the three requirements apart to allow application of different Violation Risk Factors and Violation Severity Levels.
As to the matter of proving the lack of CCZ incursions, please refer to the SDT’s response to your Question # 15 comments.
Your suggestion regarding Footnote 6 has been incorporated.
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 16.
Response: Thank you for your comments.
American Electric Power (AEP)
Agree
AEP is in agreement with these changes.
Response: Thank you for your supportive comment.
City of Tallahassee
September 8, 2009
Agree
Why have we gone backwards with only "Sustained Outages" being a violation? Even a momentary outage
indicates that a violation has occurred if the cause was vegetation related (with the same exceptions). This
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Question 16 Comment
would seem to contradict the proposed R4. If it wasn't a Sustained Outage it wasn't a violation? If you have a
sustained outage due to vegetation, you must have violated the CCZ.
Response: Thank you for your comments. The SDT very carefully and thoroughly examined the merits, disadvantages, ease and difficulties of
assessing momentary outages as a violation. The result of that effort led to the more precise and field observable aspects of R4. It should be noted that
by their very nature the exact causes of “momentary outages” are very challenging to determine and will vary widely from utility to utility. The SDT did
not find that such variability was appropriate for a reliability standard, and chose to address this issue with the language in R4.
Northern Indiana Public Service
Company
Agree
While being more specific & explicit, I don't interpret the overall requirement as being any different from the
current standard.
Response: Thank you for your comment. Please note that while the current standard did not specifically define an interruption as a violation, the
proposed standard explicitly defines outages as violations.
Orange and Rockland Utilities
Inc.
Agree
We agree, but recommend that momentary outages be included as violations of all three requirements as well.
Also, the Standard does not directly require reporting of vegetation-related outages although implicitly,
outages which are violations of the Standard must be reported. This has lead to some confusion during this
comment phase and we suggest that the reporting requirements be directly stated in the Standard.
Response: Thank you for your comments. Under the Compliance section of the new standard section 2 the Transmission Owner is required to report
outages.
Xcel Energy
Agree
We agree, however please add a reference to ?wind gusts 45 miles per hour or greater? to the exception note
for this requirement. The exception would read ?1) Sustained Outages of transmission lines that result from
sustained winds (45 miles per hour or greater) or gusts due to natural disasters.?
Response: Thank you for your comments. The SDT believes that a fresh gale (see footnote 4) represents an appropriate threshold for exemptions.
Manitoba Hydro
Agree
Agree with splitting the various events. We note that there is no specific requirement to actually report an
outage. The Requirements say that we should Prevent Sustained Outages, but not actually report sustained
outages should they occur. In version 1, R3 clearly stated that the Transmission Owner shall report.
Response: Thank you for your comments. Under NERC’s Compliance Guidelines, any violation of a reliability standard requirement must be selfreported; thus, a violation of Requirement R5, R6 or R7 must result in a report from the Transmission Owner.
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National Grid
Agree?
Agree
Question 16 Comment
National Grid agrees with the proposed change, however, Standard FAC-003-2 does not provide outage
reporting requirements in R5, R6, R7, or anywhere else in the Standard.
Response: Thank you for your comments. Under NERC’s Compliance Guidelines, any violation of a reliability standard requirement must be selfreported; thus, a violation of Requirement R5, R6 or R7 must result in a report from the Transmission Owner. The revised standard includes
compliance elements, including the need to provide periodic reports of specific vegetation-related outages.
Pacific Gas & Electric Co.
Agree
M5, M6 and M7 do not explicitly exclude the exceptions in R5, R6 and R7 and should do so.
Response: Thank you for your comments. The SDT believes that the requirements and measures are properly aligned. The exceptions language is
appropriately located in the technical requirement.
Consolidated Edison Company
of New York (CECONY)
Agree
CECONY agrees that outages caused by the factors mentioned are violations of R5, R6, and R7 but we
recommend that either the phrase 'momentary outage' be included in the wording or the phrase 'All Outages'
replace 'Sustained Outages' to make the requirements clearer.
Response: Thank you for your comments. The SDT very carefully and thoroughly examined the merits, disadvantages, ease and difficulties of
assessing momentary outages as a violation. The result of that effort led to the more precise and field observable aspects of R4. It should be noted that
by their very nature the exact causes of “momentary outages” are very challenging to determine and will vary widely from utility to utility. The SDT did
not find that such variability was appropriate for a reliability standard, and chose to address this issue with the language in R4.
WECC
Agree
However reporting requirements are not identified in the standard. WECC believes that sustained outages
caused by vegetation should be reported to the Regional Entity using the existing reporting requirements in
FAC-003-1
Response: Thank you for your comments. Under NERC’s Compliance Guidelines, any violation of a reliability standard requirement must be selfreported; thus, a violation of Requirement R5, R6 or R7 must result in a report from the Transmission Owner. The revised standard includes compliance
elements, including the need to provide periodic reports of specific vegetation-related outages.
CenterPoint Energy
Agree
We agree with the exemptions; however, R6 and R7 refer to an "Active Transmission Line Right-of-way" which
is not defined as to its limits, so M6 and M7 cannot be determined by definition. See comments to Q3 above
relating to the definitions and the examples in the Technical Reference.
Response: Thank you for your comments. The SDT asserts that the Transmission Owner is responsible for defining the Active Transmission Line Right
of Way. Additionally please refer to the response to Question 3. Note that the SDT made significant changes to clarify R5, R6 and R7 and the associated
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Organization
Agree?
Question 16 Comment
measures.
Pepco Holdings, Inc
Agree
There is no need for three separate requirements if the incident is a Sustained Outage, but there is nothing
inherently wrong with the three requirements.
Response: Thank you for your comments. Requirements R5, R6 and R7 have been drafted to address three distinct types of outages which may pose
different risks or severity in terms of impact to the electric system. The SDT chose to break the requirements apart to allow application of different
Violation Risk Factors and Violation Severity Levels.
Northeast Utilities
Agree
Agree that contacts resulting in sustained outages due to vegetation from within the active transmission line
right-of-way should constitute a violation of the Standard. However, this Standard is written for a zero
tolerance of any vegetation caused outages or encroachment into the CCZ. One vegetation-caused outage or
one CCZ encroachment may not result in a potential Cascading effect. Agree with the use of different violation
risk factors (VRF's) and violation severity levels (VSL's) for each of the three outage classes. Also - how are
outage violations to be reported - there is no provision in the revision for the reporting process and
requirements (specifics on the type of violation). Will this be addressed in the Compliance Section yet to be
added? Suggest in both R6 and R7, move the phrase "within an Active Transmission Line Right of Way" to
immediately follow "vegetation".
Response: Thank you for your comments. The SDT believes it appropriate to require that the Transmission Owner incur no (applicable) vegetationrelated outages. Further, industry regulators generally expect Version 2 to be at least as stringent as Version 1 unless a valid technical rationale is
presented by the SDT.
Requirements R5, R6 and R7 have been drafted to address three distinct types of outages which may pose different risks or severity in terms of impact
to the electric system. The SDT chose to break the requirements apart to allow application of different Violation Risk Factors and Violation Severity
Levels.
Regarding your question on reporting of violations, under NERC’s Compliance Guidelines, any violation of a reliability standard requirement must be
self-reported; thus, a violation of Requirement R5, R6 or R7 must result in a report from the Transmission Owner. In addition, the revised standard
includes compliance elements, including the need to provide periodic reports of specific vegetation-related outages.
Your suggested wording change to requirements R6 and R7 was evaluated by the SDT. The SDT asserts that the original wording is appropriate.
SERC Compliance Staff
Agree
ITC HOLDINGS
Agree
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Agree?
Northern California Power
Agency (NCPA)
Agree
Central Maine Power Company
Agree
Tampa Electric Company
Agree
WECC Reliability Coordination
Agree
Western Area Power
Administration, Upper Great
Plains Region
Agree
SERC Vegetation Management
Subcommittee (VMS)
Agree
Progress Energy Florida
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Progress Energy Carolinas
Agree
Southern Company
Agree
E.ON U.S.
Agree
Question 16 Comment
Bonneville Power Administration Agree
FirstEnergy
Agree
MRO NERC Standards Review
Subcommittee
Agree
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Agree?
Midwest ISO Stakeholders
Standards Collaborators
Agree
Ameren
Agree
American Transmission
Company
Agree
Nebraska Public Power District
Agree
Long Island power Authority
Agree
Edison Electric Institute
Agree
Baltimore Gas & Electric
Company
Agree
Duke Energy Corporation
Agree
JEA
Agree
Independent Electricity System
Operator
Agree
Buckeye Power, Inc.
Agree
Great River Energy
Agree
September 8, 2009
Question 16 Comment
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17. R8 is a new requirement which separates the implementation of the annual plan from the requirement to have an
annual plan. Do you agree with R8? If not please explain.
Summary Consideration: The SDT modified the Requirement for implementation of the work plan (now R9 in the revised
standard) after reviewing these comments. Commenters focused on two main areas. First, there was a suggestion that the
work plan wording be amended to include a note that it was only required on the Active Right of Way. Requirement R1 clearly
limits the scope of the TVMP to work on the entity's Active Transmission Line Rights of Way - and the "annual work plan" is one
element of the overall TVMP. The second overriding theme was that the standard be re-ordered to better tie the requirement
to have a plan and the requirement to implement a plan. Some commenters suggested that the requirement to implement the
annual work plan be embedded as part of Requirement R1, and the SDT did not make this change. The requirement to “have”
a TVMP is administrative and the requirement to “implement” the annual work plan is a real-time requirement – by keeping
these requirements separate, each requirement can be assigned an appropriate VRF. The SDT is offering for comment a
proposed re-ordering of the Standard that provides a more logical sequence to the Standard which, if supported by
stakeholders, can be applied to Draft 3 of the standard.
For Draft 2, the SDT also removed the wording “within the extent of its easements and/or legal rights.” The justification for
removing these words was to remove the possibility that the TO would be held to the maximum criteria or be limited to the
minimum criteria outlined in their easements.
Deleted: R8
R9. Each Transmission Owner shall implement its annual work plan for vegetation management to accomplish the purpose of this
standard.
Organization
Central Maine Power Company
Agree?
Deleted: within the extent of its
easement and/or legal rights
Question 17 Comment
Central Maine Power Company suggests that R9 read as A Transmission Owner shall implement its annual
work plan within the Active Right of Way to the the extent of its easements or legal rights.
Response: The SDT thanks you for your response. In response to overwhelming industry comments The SDT has removed the words “within the
extent of its easements and/or legal rights”. The SDT also feels that the Active Right of Way concept is supported adequately in Requirement R1 which
limits the scope of the TVMP (and the annual work plan) to the entity’s Active Rights of Way.
British Columbia Transmission
Corp
BCTC understands that it’s possible to have an annual plan and not implement it. However, we feel that the
document itself would be easier to follow if it was re-organized so that the requirement to have the plan is kept
together with the requirement to implement it.
Response: The SDT thanks you for your response. The SDT proposes a new sequence for the technical Requirements R1-R11 and seeks industry
feedback as requested in Question 4 of the Second Comment Form.
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Agree?
Western Utility Arborists
Question 17 Comment
The Western Utilities understands that it’s possible to have an annual plan and not implement it. However, we
feel that the document itself would be easier to follow if it was re-organized so that the requirement to have the
plan is kept together with the requirement to implement it.
Response: The SDT thanks you for your response. The SDT proposes a new sequence for the technical Requirements R1-R11 and seeks industry
feedback as requested in Question 4 of the Second Comment Form.
SERC Vegetation Management
Subcommittee (VMS)
Disagree
While the SERC VMS agrees in principle, we believe that the Requirement, as written, is “open ended” and
could be interpreted to be in conflict with the "Active Rights of Way" concept. Clarifying the intent for the annual
plan to focus on the Active Rights of Way will prevent incorrect interpretations. The SERC VMS suggest that
the Requirement be reworded to read: ?Each Transmission Owner shall implement its annual work plan for
vegetation management within the Active Right of Way to accomplish the purpose of this standard within the
extent of its easements and or legal rights.?
Response: The SDT thanks you for your response. The SDT considered your request at length but feels that the Active Right of Way concept is
supported adequately in Requirement R1 which limits the scope of the TVMP (and the annual work plan) to the entity’s Active Rights of Way.
JEA
Disagree
See comment from #3.
Response: Thank you for your comment. Please see the response to comments on #3. .
Salt River Project
Disagree
The document would be easier to follow if the two elements would be kept together in the same requirement
(similar to comments in #4, #6, & #14 above). It makes the standard longer than necessary and creates
redundancy.
Response: The SDT thanks you for your response. The reason that the development of the annual plan and the implementation of the plan were
separated was to apply the appropriate VRF’s and VSL’s to each. The SDT feels that the current organization is appropriate because development of
the annual work plan is a sub-part of the development of the Transmission Vegetation Management Program and should be separate from the
implementation requirement for the annual plan.
SERC OC Standards Review
Group
Disagree
The SERC OCSRG suggests that the Requirement be reworded to read: “Each Transmission Owner shall
implement its annual work plan for vegetation management within the Active Rights of Way." Any further
verbiage is confusing, ambiguous or unnecessary.
Response: The SDT thanks you for your response. The SDT considered your request at length but feels that the Active Right of Way concept is
supported adequately in the definition and elsewhere in the standard. The SDT did, however, remove the last phrase of the sentence, “within the extent
September 8, 2009
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Organization
Agree?
Question 17 Comment
of its easement and/or legal rights.”
Florida Power & Light
Disagree
The standard goes to great length to specify the Active Transmission Right-of-Way but omits its reference in
requirement R9. The inclusion of this term in Requirement R9 adds consistency to the application of the
standard. FPL suggests the following change: "Each Transmission Owner shall implement its annual work plan
for vegetation management to accomplish the purpose of this standard within the extent of its easement and/or
legal rights in the Active Transmission Line Right-of-Way."
Response: The SDT thanks you for your response. Due to industry comments the SDT revised the wording on this requirement to delete the words
“within the extent of its easements and/or legal rights”. The SDT also feels that the Active Right of Way concept is supported adequately in the
Requirement R1 which limits the scope of the TVMP (and the annual work plan) to the entity’s Active Rights of Way.
Southern Company
Disagree
While we agree in principle, we feel Requirement R9 as written is “open ended” and could be interpreted to be
in conflict with the “Active Rights of Way” concept. Clarifying the intent for the annual plan to focus on the
Active Rights of Way will prevent incorrect interpretations. We suggest that the Requirement be reworded to
read: Each Transmission Owner shall implement its annual work plan for vegetation management within the
Active Right of Way to accomplish the purpose of this standard within the extent of its easements and or legal
rights.
Response: The SDT thanks you for your response. Due to industry comments the SDT revised the wording on this requirement to delete the words
“within the extent of its easements and/or legal rights”. The SDT also feels that the Active Right of Way concept is supported adequately in
Requirement R1 which limits the scope of the TVMP (and the annual work plan) to the entity’s Active Rights of Way.
E.ON U.S.
Disagree
E.ON U.S. believes that the Requirement, as written, is “open ended” and could be interpreted to be in conflict
with the "Active Rights of Way" concept. Clarifying the intent for the annual plan to focus on the Active Rights
of Way will prevent incorrect interpretations. We suggest that the Requirement be reworded to read: “Each
Transmission Owner shall implement its annual work plan for vegetation management within the Active Right of
Way to accomplish the purpose of this standard within the extent of its easements and or legal rights.”
Response: The SDT thanks you for your response. The SDT agrees with your comments and has removed the words “within the extent of its
easements and/or legal rights”. The SDT also feels that the Active Right of Way concept is supported adequately in Requirement R1 which limits the
scope of the TVMP (and the annual work plan) to the entity’s Active Rights of Way.
Exelon
Disagree
September 8, 2009
Strike "within the extent of it's easement and / or legal rights." This is unnecessary and will cause confusion.
The annual work plan as required to be developed per R1.3 requires consideration of permitting, scheduling
and regulatory limitations.
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Agree?
Question 17 Comment
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support for your suggestion and the
requirement has been revised to reflect your suggestion.
NV Energy (fka Sierra Pacific /
Nevada Power Co.)
Disagree
We understand that it is possible to have an annual plan and not implement it. However, we feel that the
document itself would be easier to follow if it was re-organized so that the requirement to have the plan is kept
together with the requirement to implement it.
Response: The SDT thanks you for your response. The SDT feels that the current organization is appropriate because development of the annual
work plan is a sub-part of the development of the Transmission Vegetation Management Program and should be separate from the implementation
requirement for the annual plan. The SDT proposes a new sequence for the technical Requirements R1-R11 and seeks industry feedback as requested
in Question 4 of the Second Comment Form.
San Diego Gas & Electric
Disagree
We feel that the document itself would be easier to follow if it was re-organized so that the requirement to have
the plan is kept together with the requirement to implement the plan.
Response: The SDT thanks you for your response. The SDT feels that the current organization is appropriate because development of the annual
work plan is a sub-part of the development of the Transmission Vegetation Management Program and should be separate from the implementation
requirement for the annual plan. The SDT proposes a new sequence for the technical Requirements R1-R11 and seeks industry feedback as requested
in Question 4 of the Second Comment Form.
Baltimore Gas & Electric
Company
Disagree
As in question no. 14 above for R1.2, it would seem to make more sense to combine R1.3 & R9 as follows:
"Require development and implementation of an annual plan that?."
Response: The SDT thanks you for your response. The reason that the development of the annual plan and the implementation of the plan were
separated was to apply the appropriate VRF’s and VSL’s to each. The SDT feels that the current organization is appropriate because development of
the annual work plan is a sub-part of the development of the Transmission Vegetation Management Program and should be separate from the
implementation requirement for the annual plan.
Pepco Holdings, Inc
Disagree
THE SDT has introduced the term Active Transmission Line Right of Way. R9 should use this term to avoid
any misinterpretation.
Response: The SDT thanks you for your response. In response to industry comments The SDT has removed the words “within the extent of its
easements and/or legal rights”. The SDT also feels that the Active Right of Way concept is supported adequately in Requirement R1 which limits the
scope of the TVMP (and the annual work plan) to the entity’s Active Rights of Way.
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Great River Energy
Agree?
Disagree
Question 17 Comment
GRE both Agrees and Disagrees. GRE agrees with the separation between having an annual plan and
implementing it. However, GRE suggests removing all the words after vegetation management.
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support for your suggestion and the
requirement has been revised to reflect your suggestion.
City of Tallahassee
Disagree
Combined with Question 6. R9 needs to have the same flexibility that R1.3 has. As written, it could be argued
that you have to do everything in your annual plan, AND anything in addition due to the changing conditions.
This contradicts what is put forth in the white paper. I would add "as modified per R1.3" after "implement it's
annual work plan for vegetation management"
Response: The SDT thanks you for your response. The SDT feels that the “flexibility” of the annual plan is built into the development of the plan and
that same flexibility carries through to the implementation.
Tampa Electric Company
Disagree
Good start. R9 must also address the flexibility which is addressed in R1.3. As written, R9 does not do this. In
addition, R9 states "within the extent of its easement and/or legal right..". This could create another set of
conflicting criteria, where the utility has a long term "interim corrective action plan".
Response: The SDT thanks you for your response. The SDT feels that the “flexibility” of the annual plan is built into the development of the plan and
that same flexibility carries through to the implementation. The SDT does agree with the possible confusion the words “within the extent of its
easement and/or legal rights” could cause and has consequently removed these words from the requirement.
USDA Forest Service,
Southwestern Region, Regional
Office for AZ and NM
Disagree
This standard needs to be broadened to include evaluation of the good faith efforts by the Transmission Owner
to coordinate with the USFS on development of the work plan. A mechanism should be developed to allow the
Transmission Owner to evaluate the good faith efforts of the USFS.
Response: The SDT thanks you for your response. The Standard is a continental reliability standard. While the SDT agrees with you that every
Transmission Owner should strive for mutually beneficial relationships with the various landowners and other entities involved in vegetation
management, it would be outside the purvey of this effort to outline specific relationships.
Arizona Public Service Company
Disagree
APS understands that it’s possible to have an annual plan and not implement it. However, we feel that the
document itself would be easier to follow if it was re-organized so that the requirement to have the plan is kept
together with the requirement to implement it.
Response: The SDT thanks you for your response. The SDT feels that the current organization is appropriate because development of the annual
work plan is a sub-part of the development of the Transmission Vegetation Management Program and should be separate from the implementation
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Organization
Agree?
Question 17 Comment
requirement for the annual plan. The SDT proposes a new sequence for the technical Requirements R1-R11 and seeks industry feedback as requested
in Question 4 of the Second Comment Form.
SERC Compliance Staff
Agree
Vegetation management practices should be extended areas outside of the active rights-of-way (ROW) to the
extent necessary to prevent vegetation-related outages. This should include the identification and removal of
trees that could impact transmission line operation similar to the practice of identifying danger trees off of the
ROW. The requirement as written could serve to reward those entities that, for whatever reason, have
insufficient right-of-way widths. From a practical perspective, it should not be necessary to perform clear cutting
of non-active ROW, but Entities should be held responsible for any outages that occur due to contact with
vegetation within their legal rights to control.
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support to remove any wording referring to
the easement rights. The SDT agreed with this view and has revised the requirement.
ITC HOLDINGS
Agree
Clarifying the intent for the annual plan is to focus on the Active Rights of Way will prevent interpretation
conflicts
Response: The SDT thanks you for your response. The SDT agrees with your observation, but also points out that the requirement for an annual work
plan (sub-part 1.3) is part of Requirement R1, which specifically states its applicability to Active Transmission Line Rights of Way. Therefore, the SDT
respectfully feels that your concern is addressed without additionally placing such verbiage in R8 (now R9).
American Electric Power (AEP)
Agree
AEP agrees with this change.
Response: The SDT thanks you for your comments. The SDT modified the requirement, based on stakeholder comments, to remove the last phrase,
“within the extent of its easement and/or legal rights.”
Tennessee Valley Authority
Agree
TVA agrees with Comment Question 17
Response: The SDT thanks you for your comment. The SDT modified the requirement, based on stakeholder comments, to remove the last phrase,
“within the extent of its easement and/or legal rights.”
Platte River Power Authority
September 8, 2009
Agree
The separation allows lower sanctions and penalties to be assessed for a weak plan and higher sanctions and
penalties to be assessed for not implementing an annual plan. However, we feel that the standard itself would
be easier to follow if it was re-organized so that the requirement to have a plan is kept together with the
requirement to implement it.
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Organization
Agree?
Question 17 Comment
Response: The SDT thanks you for your response. The reason that the development of the annual plan and the implementation of the plan were
separated was to apply the appropriate VRF’s and VSL’s to each. The SDT feels that the current organization is appropriate because development of
the annual work plan is a sub-part of the development of the Transmission Vegetation Management Program and should be separate from the
implementation requirement for the annual plan. The SDT proposes a new sequence for the technical Requirements R1-R11 and seeks industry
feedback as requested in Question 4 of the Second Comment Form.
American Transmission
Company
Agree
ATC agrees with the requirement to implement the annual work plan, but recommends striking the words
"within the extent of its easement and/or legal rights". The emphasis for this requirement is to execute the
annual work plan. The white paper already speaks to the point that it is a best practice for utilities to exercise
their legal rights. If we agree that the goal is to prevent outages, then we can simply end this requirement with
"implement its annual work plan for vegetation management." Propose Changes to R9: Each Transmission
Owner shall implement its annual work plan for vegetation management.
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support for your suggestion and the
requirement has been revised to reflect your suggestion.
Ameren
Agree
We recommend striking, or modifying, the words "within the extent of its easement and/or legal rights" as they
may be introducing an unintended compliance quagmire. For example, if the easement is extraordinarily wide
but reliability and the work plan do not dictate that the work plan apply to the entire easement, how will
compliance be measured? The work plan should recognize easement or legal rights issue. Therefore, the
emphasis for this requirement should be to execute the annual work plan. The white paper already speaks to
the point that it is a best practice for utilities to exercise their legal rights. By tagging the words on to the
requirement, we are adding unnecessary compliance validation to this requirement for both industry and the
regulators. If a clarifying sentence is required, we would suggest that R9 stop with the word standard and a new
sentence be added, "The work plan should address easement or legal/rights"
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support for your suggestion and the
requirement has been revised to reflect your suggestion.
MRO NERC Standards Review
Subcommittee
Agree
The MRO both Agrees and Disagrees. The MRO agrees with the separation between having an annual plan
and implementing it. However, the MRO suggests removing all the words after vegetation management.
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support for your suggestion and the
requirement has been revised to reflect your suggestion.
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Midwest ISO Stakeholders
Standards Collaborators
Agree?
Agree
Question 17 Comment
We recommend striking the words "within the extent of its easement and/or legal rights". The emphasis for this
requirement is to execute the annual work plan. The white paper already speaks to the point that it is a best
practice for utilities to exercise their legal rights. By tagging the words on to the requirement, we are adding
unnecessary compliance validation to this requirement for both industry and the regulators. By the way this is
written, it could be interpreted different ways. If we agree that the goal is to prevent outages, then we can
simply end this requirement with "accomplish the purpose of the standard". Each Transmission Owner would
be accountable to manage compliance with this standard and public relations in their service area.
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support for your suggestion and the
requirement has been revised to reflect your suggestion.
Duke Energy Corporation
Agree
Duke agrees with the requirement to implement the annual work plan, but recommends striking the words
"within the extent of its easement and/or legal rights". The emphasis for this requirement is to execute the
annual work plan. The white paper already speaks to the point that it is a best practice for utilities to exercise
their legal rights. If we agree that the goal is to prevent outages, then we can simply end this requirement with
"accomplish the purpose of the standard". Each Transmission Owner will be accountable to manage
compliance with this standard.
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support for your suggestion and the
requirement has been revised to reflect your suggestion.
CenterPoint Energy
Agree
R9 requires implementation of the annual work plan "within the extent of its [the Transmission Owner's]
easement and/or legal rights." All measures and compliance should be determined on this basis as well. This
concept should also be carried through the definitions for "Active Transmission Line Right-of-way" and "Critical
Clearance Zone", or for any definition of clearances should the Standard continue to utilize such terms.
Response: The SDT thanks you for your response. In response to industry comments The SDT has removed the words “within the extent of its
easements and/or legal rights”. The SDT also feels that the Active Right of Way concept is supported adequately in the definition and in Requirement
R1 which limits the scope of the TVMP (and the annual work plan) to the entity’s Active Rights of Way.
Progress Energy Florida
Agree
While Progress Energy agrees with the change, the term “annual plan” should be a defined term including
threshold elements.
Response: The SDT thanks you for your response. The SDT feels that the annual plan is adequately defined between the descriptions in the Standard
(sub section 1.3) and in the technical reference document.
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Southern California Edison
Company
Agree?
Agree
Question 17 Comment
Q17: SCE agrees in part with the inclusion of R9, however, we believe R9 should be revised and renumbered
to replace proposed R3. In SCE’s view, the act of implementing a Transmission VM program encompasses
both inspection and maintenance activities. SCE respectfully suggests that proposed R9 be revised to read:
"Each Transmission Owner shall implement and follow its Vegetation Management Program to the extent
allowed by existing easement and/or legal rights."
Response: The SDT thanks you for your response. The SDT separates the vegetation inspections from the annual work plan because of partly due to
the fundamental importance of the inspection process, and partly because a key purpose of an inspection is to provide input to the formation of the
annual work plan. The SDT also points out that the TVMP is comprises the overarching processes and standards for program management, while the
annual plan is the specific annual activities to accomplish the goals set forth in the program. In addition, the SDT modified the requirement, based on
many other stakeholder comments, to remove the last phrase, “within the extent of its easement and/or legal rights.”
FirstEnergy
Agree
FirstEnergy agrees with the intent of R9, but the standard should be clarified by removal of the word
"easement". As written the standard is open to interpretation between "easement" and active right of way. It is
important to have the term "legal rights" remain in the standard. The Transmission Owner should be held
accountable to fully enforce the legal rights outlined in maintaining the active right of way. This will lead to a
more reliable transmission system.
Response: The SDT thanks you for your response. Due to industry comments the SDT revised the wording on this requirement to delete the words
“within the extent of its easements and/or legal rights”. While we agree and state in the technical reference document that clearing to the maximum
extent is in most cases the best practice, there are particular situations where a clear cut policy would not be in the best interest of the Transmission
Owner or the landowner. The SDT also feels that the Active Right of Way concept is supported adequately in Requirement R1 which limits the scope of
the TVMP (and the annual work plan) to the entity’s Active Rights of Way.
Pacific Gas & Electric Co.
Agree
PG&E agrees with the requirement to implement the annual work plan, but recommends removing the
language "within the extent of its easement and/or legal rights".
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad support for your suggestion and the
requirement has been revised to reflect your suggestion.
Entergy Services
Agree
Entergy would like to note that requirements R1.3 and R9 are administrative requirements that add marginal
value to the reliability of the Transmission System. Since entities are required to have flexible annual plans,
deviations from the annual plan only need to be documented and these requirements will be met. Entergy
utilizes annual plans as a good practice but sees limited value with the inclusion in this standard.
Response: The SDT thanks you for your response. After reviewing the industry comments there was broad concern that the current wording could
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Agree?
Question 17 Comment
cause confusion with the wording “within the extent of its easements and/or legal rights”. Consequently the SDT agreed with this view and has revised
the requirement to address these concerns. The SDT respectfully disagrees that sub section 1.3 and R9 are administrative requirements and only add
marginal value to the reliability of the system. Requirement R8 (now R9) is a real-time requirement, not an administrative requirement.
Nebraska Public Power District
Agree
Long Island power Authority
Agree
Northern California Power
Agency (NCPA)
Agree
Northern Indiana Public Service
Company
Agree
Bonneville Power Administration
Agree
Orange and Rockland Utilities
Inc.
Agree
Manitoba Hydro
Agree
Consumers Energy Company
Agree
National Grid
Agree
Hydro One Networks Inc.
Agree
Edison Electric Institute
Agree
Consolidated Edison Company
of New York (CECONY)
Agree
WECC
Agree
Independent Electricity System
Agree
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Question 17 Comment
Operator
Northeast Utilities
Agree
Hydro-Quebec Transenergie
(HQT)
Agree
Buckeye Power, Inc.
Agree
Santee Cooper
Agree
Associated Electric Cooperative
Inc.
Agree
NPCC
Agree
WECC Reliability Coordination
Agree
Western Area Power
Administration, Upper Great
Plains Region
Agree
Kansas City Power & Light
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Progress Energy Carolinas
Agree
Response: Thank you for your positive response. The SDT modified the requirement, based on many other stakeholder comments, to remove the last
phrase, “within the extent of its easement and/or legal rights.”
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18. If you have further suggestions for improving this standard or the technical reference document, please offer them.
Summary Consideration: The overall industry feedback provided to this question reiterated concerns expressed in previous
comments above. Most were related to the Critical Clearance Zone and associated issues of measurability, enforceability and
practicality.
Organization
Associated Electric
Cooperative Inc.
Question 18 Comment
R10 and R11: Associated Electric Cooperative Inc does not believe the Reliability Coordinator (RC) is the appropriate entity to
determine whether or not selected sub-200 kv transmission lines should be subject to this standard. The planning horizon for the RC is
typically much shorter than the time needed to incorporate a sub-200 kv transmission line into a vegetation management program.
Associated recommends Planning Coordinator be designated as the applicable functional entity and be substituted wherever Reliability
Coordinator appears in the Standard.
M1.4: The language in M1.4, requiring immediate communication of an imminent threat to the Transmission Operator, is inconsistent
with the Applicability in Section A.4.1.1 which designates the Transmission Owner as the responsible entity.
M4: The preparation and retention of inspection reports, imminent threat reports, quality assurance reports, etc. is appropriate. These
reports would not, however, absolutely demonstrate the Transmission Owner had experienced no vegetation encroachments into the
Critical Clearance Zone. A negative cannot be proven.
M6 and M7: The Transmission Owner is again expected to demonstrate a negative to prove compliance.
Section C: Associated Electric Cooperative Inc recognizes the Standard, as posted, is a first draft for comments and will likely be
revised before submittal for ballot. However, the Compliance section should be posted for an adequate comment period prior to
balloting.
Response: The SDT thanks you for your comments.
The drafting team has made significant changes to the draft standard in response to industry comments, including the replacement of RC with PC.
R1.4 and M1.4 are changed and the inconsistency has been resolved.
R4 and M4 are changed such that real time observations during inspections and patrols replace the previous condition of proving a negative. In
addition, the revised standard does not use the concept of the Critical Clearance Zone.
M6 and M7 have been changed so that the proof of a negative is not required.
The SDT had developed compliance elements for the industry to review in the second comment period.
NPCC
NPCC requests that the Standard Drafting Team review the compliance and reporting requirements for consistency and adequacy.
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Response: The SDT thanks you for your comments. The drafting team has made significant changes to the draft standard in response to industry
comments. Compliance elements have been added to the second draft of the standard.
WECC Reliability
Coordination
R10 Should a dispute arise, how are those disputes resolved. Who keeps the list.
R10 What is acceptable methodology given the lack of interpretation of unacceptable risk of instability(R 10.2) or cascading failures.
There is no definition of the consequences if a sub 200kv line is left off the list for vegetation management, and caused a cascading
outage or placed the grid at an unacceptable risk of instability.
Response: The SDT thanks you for your comments The drafting team has made significant changes to the draft standard in response to industry
comments.
The RC has been replaced with the PC in R9 and R10.
This standard requires the PC to prepare and keep the list. Requiring the list to be developed in consultation with the TO ensures that the list will be
available to the TO for the purposes in this Standard. The revised language should eliminate any disputes as the PC is ultimately the responsible entity
for developing the list.
R10 was revised and now uses terminology that replicates terms within the IROL definition in the NERC Glossary of Terms for reliability standards. The
intent is for the PC to use the same methods that determine those lines which are elements of an IROL be used to determine sub 200kV lines which are
applicable to this standard.
While the planning study or similar analysis as cited in M10 could contain errors, it is not the intent of this standard to determine the competency of the
PC or the results of PC any PC’s analysis.
Western Area Power
Administration, Upper
Great Plains Region
1) Proactive utilities are implementing policies that call for the removal of all vegetation that could grow into the Critical Clearance Zone
. Such policies are not without resistance from landowners, environmental groups, etc. One of the arguments used by such groups is
that NERC/FERC do not require removal of the trees. It would very helpful if this document included the practice of removing vegetation
capable of encroaching within the Critical Clearance Zone as a reasonable or acceptable practice under this Standard.
2) We can foresee a possible public backlash if this Standard is adopted as written. We see many utilities needing rate increases to
cover the additional costs of implementing and monitoring the more stringent requirements of this proposal. We also believe that the
more stringent requirements will have no noticeable impact on reliability. So you'll have the public paying more and seeing no change in
reliability and questioning why.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The essential changes are: The CCZ concept has been replaced with the concept of minimum vegetation clearance distances, and
Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time. The
Standard Drafting team has found that this Standard can not establish any legal basis to require Transmission Owners to exercise rights that do no
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Question 18 Comment
exist within their transmission line easements or permits.
Progress Energy Florida To avoid interpretation errors and provide clarity, the Applicability section for Facilities (4.2) of FAC-003 should include a statement that
the standard only applies to vegetation within the Active Transmission Line Right of Way. For example, a fall-in from outside of the
Active Transmission Line Right of Way that causes a sustained outage is not a violation of this standard. Any encroachment/outage
initiated by vegetation falling from outside of the Active Transmission Line Right of Way should be excluded from violations. The Critical
Clearance Zone concept is academically elegant, but when applied in the field, it presents significant implementation, interpretation and
enforcement issues: the complexity of determining compliance could have the unintended negative consequences to reliability; removal
of vegetation will likely be delayed because of the complexity and accuracy required to determine compliance prior to tree removal;
certification that no violations have occurred will require lengthy and costly calculations and survey measurements; the standard refers to
Ratings in the determination of line sags and Ratings is not a tightly defined term, PRC-023 requires relays to hold lines in beyond the
line Ratings; how will PRC-023 requirements be factored into the Critical Clearance Zone concept. The Critical Clearance Zone
concept introduces more complexity and ambiguity into the standard than it resolves. The drafting team needs to develop an alternative
to the Critical Clearance Zone concept that is simple, easy to apply and clearly defines at what point a violation occurs. There are over
158,000 line miles of AC Transmission above 200kV in the United States, covering a Right of Way area potentially as large as 3,000 to
4,000 square miles (an area roughly equivalent to Rhode Island and Delaware combined). With billions of stems of managed vegetation,
in and along the right of way, even six-sigma performance would result in a number of outages on a system this large. With countless
VM processes and assessments that take place daily, it is unrealistic/unreasonable to expect zero-tolerance for random vegetation
events (the transmission system is planned/operated to handle at least any single contingency).
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The essential changes are: The CCZ concept has been replaced with the concept of minimum clearance distances, and
Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time.
The exclusion you request for vegetation falling through the MVCD, regardless of its being form inside or outside the right-of-way, has been added.
Due to the industry impact that arises from zero tolerance for vegetation-related sustained outages, the Drafting Team tried several approaches but
could not find a mechanism in the standard development process to establish a non-zero threshold for outages that was acceptable to FERC staff,
because Standard revisions may not lead to less emphasis on reliability.
The PRC-023 Standard seeks to ensure that transmission protective relays are properly set such that they do not trip a transmission element
unnecessarily. This FAC-003 Standard seeks to prevent vegetation related Sustained Outages by requiring Transmission Owners to maintain their
Active Transmission Line Rights of Way to be sufficiently clear. These two Standards are not mutually exclusive nor conflict with each other.
Kansas City Power &
Light
The title and explanation for Table 1 in Attachment 1 is not clear as to it’s usage and applicability. It is being confused with the correlation
with a minimum clearance and not as a component or building block of the Critical Clearance Zone.
Under R10, there may be other methods for consideration of assessing reliability significance of the sub-200 kV lines other than what is
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listed. Suggest the Drafting Team consider other criteria that an RC should consider in its processes.
R10.2 is redundant with R10.1. IROL by definition are those operating limits that represent instability, uncontrolled separation or
cascading. Suggest removing R10.2.
Under M1.3 the measure requires the annual plan to cover a calendar year. An annual plan may cover a cycle growing season to
growing season using the inspection to verify the next seasons work.
Suggest removing the language for calendar year.M5, M6, M7 The measures should be requesting the evidence that it has violated the
requirements. Good standing programs should not have to defend good practice by providing useless reports. The FAC-003-1 existing
requirement R4 for reporting sustained outages is a reasonable and sustainable method that should be retained.R10 should include a
periodic review period of annually. Any requirement to maintain current documentation should have a review period.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The essential changes are: The CCZ concept has been replaced with the concept of minimum clearance distances, and
Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time.
Under M10 (now M11) the language now allows the criteria used in planning studies and analysis to be acceptable measures for R10 (now R11).
The redundancy in 10.1 and 10.2 you found has been removed.
The reference to the calendar year that was in M1.3 has been removed.
M5, M6, M7 language has been changed. These measures now rely on the certification reports to the RE reporting will occur for both full compliance
and any violations. The revised standard includes data retention periods as well as more detailed compliance information.
Western Area Power
Administration, Rocky
Mountain Region
1. Further clarification of the definition of the active right-of-way appears to be required. For example, if a tree falls from an area
controlled by the utility which is outside of the normal width of the actively managed right-of-way, but this area is not reserved or
"intended for other facilities", could this be a violation of a Standards requirement? The narrative discussion within the white paper
seems to imply that it is not, but the "intended for other facilities" requirement within Standards definition implies that it would be.
2. As currently presented, FAC-003-2 requires an impractical and unrealistic level of performance from the industry. This level of
performance is unwarranted for the overwhelming number and expanse of transmission facilities to which the Standards are applicable.
Many of these facilities, such as radial load lines, are not critical Transmission OwnerT or IROL facilities and have a minimal impact on
overall grid reliability. The rigorous zero tolerance level of performance is only warranted for those lines that are critical Transmission
OwnerT or IROL facilities.
3. The Standards should clearly identify any and all reporting requirements.
Response: The SDT thanks you for your comments.
1. The definition of the Active Transmission Line Right of Way states it is “A strip of land that is occupied by active transmission facilities. This corridor
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does not include the inactive Right of Way or unused part of the Right of Way intended for other facilities.” This definition is not limited only to those
parts of the Right of Way intended for other facilities. The SDT has also further clarified the concept in the white paper.
2. Due to the directive given by FERC Order 693 your suggestion for removing some lines above 200 kV from the Standard’s Applicability was not
considered. (Excerpt from order 693 paragraph 706 “we did not intend to make this Reliability Standard applicable to fewer facilities than it currently is
with the 200 kV bright line applicability, but to extend the applicability to lower-voltage facilities that have an impact on reliability”).
3. Reporting requirements are included in standard in the second posting.
Progress Energy
Carolinas
To avoid interpretation errors and provide clarity, the Applicability section for Facilities (4.2) of FAC-003 should include a statement that
the standard only applies to vegetation within the Active Transmission Line Right of Way. For example, a fall-in from outside of the
Active Transmission Line Right of Way that causes a sustained outage is not a violation of this standard. Any encroachment/outage
initiated by vegetation falling from outside of the Active Transmission Line Right of Way should be excluded from violations. The Critical
Clearance Zone concept is academically elegant, but when applied in the field, it presents significant implementation, interpretation and
enforcement issues: the complexity of determining compliance could have the unintended negative consequences to reliability; removal
of vegetation will likely be delayed because of the complexity and accuracy required to determine compliance prior to tree removal;
certification that no violations have occurred will require lengthy and costly calculations and survey measurements; the standard refers to
Ratings in the determination of line sags and Ratings is not a tightly defined term, PRC-023 requires relays to hold lines in beyond the
line Ratings; how will PRC-023 requirements be factored into the Critical Clearance Zone concept. The Critical Clearance Zone
concept introduces more complexity and ambiguity into the standard than it resolves. The drafting team needs to develop an alternative
to the Critical Clearance Zone concept that is simple, easy to apply and clearly defines at what point a violation occurs. There are over
158,000 line miles of AC Transmission above 200kV in the United States, covering a Right of Way area potentially as large as 3,000 to
4,000 square miles (an area roughly equivalent to Rhode Island and Delaware combined). With billions of stems of managed vegetation,
in and along the right of way, even six-sigma performance would result in a number of outages on a system this large. With countless
VM processes and assessments that take place daily, it is unrealistic/unreasonable to expect zero-tolerance for random vegetation
events (the transmission system is planned/operated to handle at least any single contingency).
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The essential changes are: The CCZ concept has been replaced with the concept of minimum clearance distances, and
Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time.
The exclusion you request for vegetation falling through the MVCD, regardless of its being form inside or outside the right-of-way, has been added.
Due to the industry impact that arises from zero tolerance for vegetation-related sustained outages, the Drafting Team tried several approaches but
could not find a mechanism in the standard development process to establish a non-zero threshold for outages that was acceptable to FERC staff,
because Standard revisions may not lead to less emphasis on reliability.
The PRC-023 Standard seeks to ensure that transmission protective relays are properly set such that they do not trip a transmission element
unnecessarily. This FAC-003 Standard seeks to prevent vegetation related Sustained Outages by requiring Transmission Owners to maintain their
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Active Transmission Line Rights of Way to be sufficiently clear. These two Standards are not mutually exclusive nor conflict with each other.
Southern California
Edison Company
SCE notes that Section C (Compliance) is incomplete and that the associated levels of Non-Compliance listed in FAC-003-1 may be
different from those proposed for FAC-003-2. SCE reserves the right to revise its initial comments and submit additional comments
regarding the requirements, measures and compliance portions of FAC-003-2.
Response: The SDT thanks you for your comments. Draft 2 will be a complete Standard for you to review.
SERC OC Standards
Review Group
The SERC OCSRG recommends that the definition of "Active Rights of Way" be revised as follows: "A strip of land, designated by the
Transmission Owner, that is occupied by active transmission facilities. This corridor does not include the inactive or unused part of the
Right of Way set aside by the Transmission Owner for other facilities or uses." The SERC SOSRG recommends that this standard
should exclude radial to load facilities and, for consistency, all 200 kV and above lines should not be included in the standard unless they
meet the same requirements as sub 200 kV lines.
Response: The SDT thanks you for your comments. The SDT opted to retain the “bright line” of 200kV without further qualifications such as radial to
load transmission facilities, due to the directive given by FERC Order 693 (paragraph 706 “we did not intend to make this Reliability Standard applicable
to fewer facilities than it currently is with the 200 kV bright line applicability, but to extend the applicability to lower-voltage facilities that have an impact
on reliability”.
Western Utility Arborists
Any standard that is developed should not contain advisory-type language? it should be declarative in tone. For example, in R1.4, the
ending clause that begins “and may include actions” should be removed because it is advisory in nature. The suggested actions are not
even the responsibility of the vegetation management program.
ADDITIONAL COMMENTS We have prepared, and will submit via email, additional comments regarding our online submission. If the
ability to submit them electronically is not available on this website, we will send the complete document via email to Harry Tom and
would ask that it be reviewed and considered by the drafting team.
Response: The SDT thanks you for your comments. The phrase in R1.4, “and may include actions” has been removed from the revised standard in
support of your suggestion.
Please refer to the various responses to your comments provided in the individual questions. The changes to the standard in this reposting and the
responses to your comments on questions 1-17 are intended to serve as a reply to your various comments.
Florida Power & Light
FPL believes the Vegetation Management standard should concentrate on grow-in tree issues that contribute to cascading or blackout
events as stated in the purpose statement. Fall-in trees from either on or off ROW do not in-and-of themselves cause cascading or
blackout events. Transmission systems are appropriately designed to handle incidental outages under N-1 conditions which are the
case in fall-in type outages. Requirements relating to fall-in and blow-in outages (R6 and R7), which deal with incidents resulting from
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force majeure or acts of God, should be removed to allow resources to be allocated to addressing events related to grow in interruptions.
Because of an utter lack of control or such situations, no Standard or regulation places a duty on one to control force majeure or acts of
God, yet that is precisely what R6 and R7 intend to do. If R6 and R7 stay in its current form, this will be yet another reason why this
Standard as written will be unenforceable. FPL recommends the following approach. The entire US Transmission system was built
under the National Electric Safety Code (C2). That code uses the Reference Component as the initial building block for establishing the
lowest height of a conductor for all operating and designed environmental conditions. Over most open land this distance is 14 feet. FPL
recommends creating a new requirement to clearly define a trimming standard. New Requirement At time of trimming, trees under
conductors should be trimmed or removed so that the average growth would remain below the Reference Component of Rule 232 in the
National Electric Safety Code C2. The wire zone should extend to the blowout distance calculated at 39 miles per hour (Fresh Gale) not
to exceed the Active Transmission Right-of-Way. Where the Transmission Owner can not achieve that clearance, they shall have a
permanent (ex. raised conductor) or interim (ex. short trim cycles) corrective action plan in place to prevent tree wire conflicts.
Permanent corrective action plans should reside in the Transmission Owner's vegetation program record keeping system (database) for
application when that line is maintained or inspected. Trees to the side of the ROW should be maintained at the edge of the Active
Transmission Right-of-Way. The value in this approach is in its application by arborists and tree trimmers in field conditions. This
approach is clear and measurable without a surveyor or an engineer present. The line design calculations were made to the NESC
Standard at the time the line was built and incorporate all potential conductor locations within its flight path. As it stands now if there is a
violation to R4, R5, R6, or R7 it is already too late. The standard should seek to identify and correct poor performers before they create
a reliability threat to the system. In the field, a poor performer has many trees close to the line and will have to do many emergency cuts.
It will also have more momentary interruptions before it has a single Sustained interruption. Sustained Interruptions have a history of
contributing to cascading and blackout events. The standard should measure performance and penalize poor performance. The changes
below reflect performance measurements with a graduated penalty applied to the metric.
Change R2 to read
Each Transmission Owner shall implement its Imminent Threat procedure when the Transmission Owner has knowledge, obtained
through normal operating practices or notification from others, that the tree / conductor distance is less than the minimum clearance
distance as specified in Table 2 of ANSI Z133.1-2006 (the minimum approach distance for qualified line-clearance arborists or qualified
line-clearance trainees). Transmission Owners are to document and report activation of the Imminent Threat Procedure for violation of
Table 2. Activation of the Imminent Threat Procedure for other causes shall not be reportable.
The Violation Severity level should read: Activation of the Imminent Threat Procedure for encroachment of Table 2 of ANSI Z133.1-2006
(the minimum approach distance for qualified line-clearance arborists or qualified line-clearance trainees) has the following severity level:
Lower ? Greater than 5 per 1000 miles of line and less than 7
Moderate ? Greater than 7 per 1000 miles of line and less than 9
High - Greater than 9 per 1000 miles of line and less than 13
Severe - Greater than 13 per 1000 miles of line
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Trees inside of Table 2 can only safely be trimmed under a clearance from the system operator, using special techniques under a line
right of way from the system operator, or by a lineman with a live line permit from the system operator. No utility wants to let a tree get so
close to energized lines such that it has to take the line out of service for a tree trim. It should be noted that Table 2 represents an
established industry standard which is normally found placarded on the side of every tree trimming easement truck and bucket truck. It is
minimum knowledge for every qualified line-clearance tree person under OSHA regulations. This is a distance that field personnel
understand.
New R5 to read: Each Transmission Owner shall minimize Momentary Outages of applicable lines due to vegetation growing into a
conductor with the following exceptions:? Sustained Outages of applicable lines that result from natural disasters.? Sustained Outages of
applicable lines that result from human or animal Activity. The Violation Severity level should read:
Lower ? Having Momentary Outages Greater than 3 per 1000 miles of line and less than 6
Moderate ? Having Momentary Outages Greater than 6 per 1000 miles of line and less than 8
High - Having Momentary Outages Greater than 8 per 1000 miles of line and less than 12
Severe - Having Momentary Outages Greater than 12 per 1000 miles of line
New R6 to read:
Each Transmission Owner shall minimize Sustained Outages of applicable lines due to vegetation growing into a conductor with the
following exceptions:? Sustained Outages of applicable lines that result from natural disasters.? Sustained Outages of applicable lines
that result from human or animal Activity.
The Violation Severity level should read:
Lower ?
Moderate ?
High - Having Sustained Outages Greater than 1 per 1000 miles of line
Severe - Having Sustained Outages of 2 or greater per 1000 miles of line
These VSL's listed above constitute a strawman for discussion. The drafting team could request historical performance data from
Transmission Owners to statistically evaluate where the VSL should be set. As time progresses, future performance data could be reevaluated to reset the limits. These changes bring the standard back in line with measurable and auditable requirements which provide
practical field measurements to the personnel who can make the difference. These parameters provide measurements to indicate the
tree health of the system. On a separate note, FPL believes that clarifying information captured in footnotes within the standard should
specifically be referenced and made part of the standard. These notes add clarity and better define the standard requirements.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
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industry comment. The essential changes are: The CCZ concept has been replaced with the concept of minimum clearance distances, and
Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time.
The Drafting Team reviewed the exclusion in R6 and R7 and reached consensus that the stated exclusions are adequate to exclude force majeure or
acts of God.
This posting includes under R1 the new section 1.6. That would make the proposal you offer related to maintaining the height of trees above ground
level to be a method for the TO to select. The language also allows TOs to select a separation distance between the conductor and the vegetation.
When lines traverse terrain with significant changes in elevation within spans the latter method may be more practical.
Changes made to utilize the MVCD as observed in real time will provide the clarity and measurability you requested.
R2 has been revised to ensure that the process is used only for conditions that require immediate actions to prevent a sustained outage. Other factors
which under some conditions would not pose an imminent threat of a sustained outage were purposely omitted to provide clarity and consistency of
application.
Since R2 is binary requirement its VSL cannot be gradated as you suggest.
R5 has been left as a binary requirement with a zero tolerance in lieu of a gradated metric in the requirement as you suggest. Due to the industry
impact that arises from zero tolerance for vegetation-related sustained outages, the Drafting Team tried several approaches but could not find a
mechanism in the standard development process to establish a non-zero threshold for outages.
Momentary outages are purposely not included because of the challenges they pose during investigation. These problems often lead to unreliable,
inconsistent, false, or missing reports. Furthermore momentary outages caused by vegetation have not been a historical cause of cascading or
widespread outages.
Santee Cooper
The SDT should clarify that Transmission lines operated at 200 kV and above is for lines that are network facilities. Radial load
transmission facilities operated at 200 kV and above should not be subject to this standard as they would not lead to SOLs or IROLs.
M2 requires evidence that a Transmission Owner implemented its imminent threat procedure upon knowledge of a Critical Clearance
Zone breach. M4 requires evidence that there were NO encroachments into the Critical Clearance Zone. These two measures are in
conflict with one another. If a utility provides evidence for M2 then they are in violation based upon M4.M4 and M5 requires a utility to
provide "proof to the negative". These measures should be removed from the standard.
R10, R11, M10, and M11 should be removed from this standard as critical facilities are identified through the PRC standards.
Response: The SDT thanks you for your comments.
Regarding your request to line applicability to only network lines above 200 kV FERC in order 693 paragraph 706 stated “we did not intend to make this
Reliability Standard applicable to fewer facilities than it currently is with the 200 kV bright line applicability, but to extend the applicability to lowervoltage facilities that have an impact on reliability”. The standard drafting team therefore does not see that honoring your request as one that would be
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permissible.
Regarding the conflicts you cite between M2 and M4, please note the revisions in this posting for R2, R4 and the associated measures. The conflict you
reference should now be resolved since the distance in R4 is not the exclusive basis for implementing R2 and the concept of the “CCZ” has been
removed from the revised standard.
In M4, the language is now changed to remove the “proving a negative” dilemma.
There is a 200 kV bright line for applicability in this standard; therefore it is appropriate for the applicability for sub 200 kV lines to be determined within
this standard in lieu of the PRC standards.
Significant changes have been made to the current draft of the Standard based upon substantive industry comment. The essential changes are: The
CCZ concept has been replaced with the concept of minimum clearance distances, and Transmission Owners are required to prevent encroachment of
vegetation into minimum vegetation clearances distances as observed in real time.
Southern Company
We would like to re-emphasize our concern over the zero tolerance philosophy of FAC-003-1 which is continued in this proposed
revision. FAC-003 has been singled out as the only zero tolerance NERC standard. Compliance should not be based on the
encroachment of vegetation into a theoretical, pre-defined zone, but on the occurrence of a sustained outage, as stated in the
document's Purpose Statement. We agree with the philosophy utilized in other NERC standards where a clearly discernible compliance
event signals a review of the Transmission Owner's plans, policies, and procedures to determine the effectiveness of the entity's
programs and spirt toward compliance.
Applicability Section 4.2 describes the Facilities pertinent to this Standard. Recommendation is to restructure the sentence by relocating
the parenthetical phrase: Transmission lines operated at 200kV or higher, and transmission lines operated below 200kV designated by
the Reliability Coordinator as being subject to this standard (“applicable lines”) including but not limited to those that cross lands owned
by federal, state, provincial, public, private, or tribal entities.
Requirement R3Recommend rephrasing to say: Each Transmission Owner shall conduct vegetation inspections of all applicable lines in
accordance with the frequency specified in its transmission vegetation management program.
Requirement 10The standard does not mention whether or not the results of this specific assessment methodology are supposed to be
compiled and maintained. The resulting information could be labeled as sensitive and possibly critical since the loss would place the grid
at an unacceptable risk of instability, separation, or cascading failures. If the resulting information becomes auditable (subject to
discovery and posting) then precautions must be taken that are comparable to those designed to preserve the integrity of critical assets
or critical cyber assets. We would like to express our sincere appreciation and thanks the drafting team for their efforts.
Response: The SDT thanks you for your comments.
Due to the industry impact that arises from zero tolerance for vegetation-related sustained outages, the Drafting Team tried several approaches but
could not find a mechanism in the standard development process to establish a non-zero threshold for outages that was acceptable FERC staff
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because revisions to a Standard may not lead to less emphasis on reliability.
The standard has been revised to remove the violation for encroachment into a theoretical zone and is now based on an observed encroachment in real
time inside a distance where flashover becomes a possibility.
The Drafting Team considered the applicability wording with the (“applicable lines”) to be acceptable as written.
R3 has been revised as you recommended.
The Drafting Team agrees that documentation regarding the methodology used to determine applicability of lines below 200 kV should have similar
precautions for confidentiality as other critical assets or critical cyber assets.
The issue of transmission line applicability is addressed in FERC Order 693.
Bonneville Power
Administration
There is a typographical error / omission in the Technical Reference on Page 36, which states, "R6. Each Transmission Owner shall
prevent Sustained Outages of applicable lines due to the blowing together of vegetation and a conductor with (sic) Active Transmission
Line Right of Way) operating within design blow-out conditions) with the following exception: . . . " I believe the intent is for the statement
to read "due to the blowing together of vegetation and a conductor WITHIN Active Transmission Line Right of WAY". This change is
needed to make the technical reference consistent with R6. as it appears in the Standard, the definition of Active Transmission Line
Right of Way on Page 5 of the Technical Reference, as well as the terminology used on Page 37 in describing Fall-into outages. This
needs correction.
Response: The SDT thanks you for your comments. The technical reference error is noted and has been corrected by the SDT.
Public Service Electric
and Gas Company
These comments were prepared by Richard Wolowicz, Manager Vegetation Management, on behalf of Public Service Electric and Gas
Company ("PSE&G"). PSE&G also joins with and supports the comments filed by the Edison Electric Institute (EEI) in this matter.
Response: The SDT thanks you for your comments. Please see our response to EEI.
FirstEnergy
FE provides these additional comments for consideration:
1. Regarding the Applicable Facilities - Section 4.2.2 would be more appropriately placed under Sec. 5 "Effective Dates" since it deals
with the timeframe the Transmission Owner has to implement its Transmission Vegetation Management Program on sub-200 kV lines.Section 4.2.3 - We suggest removing this section. First energy does not agree that this standard should dictate the amount of time a
Transmission Owner has to obtain compliance with this standard for newly acquired transmission lines. It should be the responsibility of
every organization to "self-report" its compliance issues and planned mitigation plans for all standards when they acquire new lines or
facilities. If the SDT believes this should be explicitly stated, then it should recommend to NERC that explicit language be placed in the
NERC Rules of Procedure. No other standards set timetables for newly acquired facilities and this standard should be no exception.
2. Regarding R1.1, this subrequirement requires the Transmission Owner to specify the methodologies it uses to control vegetation. It
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should be clear that not all of these methodologies are required to be deployed in every situation (as explained in the white paper pg.12).
We suggest rewording the requirement as follows: "R1.1. Specify the methodologies that the Transmission Owner may use to control
vegetation."
3. R1.5 requires a process for "interim corrective action" be specified in the Transmission Vegetation Management Program. However,
the standard does not explicitly specify that this corrective action be implemented when the Transmission Owner is constrained from
performing vegetation maintenance as planned.
4. As written, in addition to the responsible RC, R10 may imply that this requirement is also the responsibility of the Transmission
Owner(s) and neighboring RC(s) due to the use of the term "jointly". Also, R10 should require the RC submit the list of designated lines
below 200 kV to the Transmission Owner(s) and neighboring RC(s) within a reasonable time-frame after its completion. We suggest
rewording and addition of subrequirements to R10 as follows:
R10. Each Reliability Coordinator, in consultation with its Transmission Owner(s) and neighboring Reliability Coordinator(s), shall
prepare and keep current a list of designated applicable lines that are operated below 200kV, if any, which are subject to this standard.
R10.1. The RC shall submit the list to the impacted Transmission Owner(s) within 30 calendar days of completion and/or revision.
R10.2. The RC shall submit the list to its neighboring RC(s) within 30 calendar days of completion and/or revision. Lastly, measure M9
will need to add sub-measures for the proposed additions above.
5. Requirement R10 should require that the RC ONLY uses the assumptions detailed in R10.1 and R10.2 to designate a line as
significant. Also, R10.1. should reference the IROL methodology standard FAC-011 since it directly ties into this requirement. Also, in
R10.2, "grid" should be replaced with "BES" and the term "failures" is not necessary. We suggest re-wording R10, R10.1 and R10.2 as
follows:
R10. Each Reliability Coordinator shall document its method for assessing the reliability significance of sub-200kV lines and shall be
based only on the following:
R10.1 Transmission lines whose loss would result in the exceedance of an Interconnection Reliability Operating Limit (IROL) as
determined by standard FAC-011.
R10.2 Transmission lines whose loss would place the BES at an unacceptable risk of instability, separation, or cascading.
Response: The SDT thanks you for your comments.
The placement of Section 4.2.2 was chosen to allow the TO time to bring those lines into compliance which are identified by future studies well after the
effective dates in Section 5.
The SDT chose to leave Section 4.2.3 as it does provide a reasonable time allowance (limitation) to bring the subject lines into compliance. {note for a
newly acquired line to have not previously been subject to the standard it may have been 1) owned and operated by a private entity such as a mining
company that was not connected to the grid, 2) was a de-energized line not in operation until it was acquired by the TO, 3) was previously operated at
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less than 200kV but was insulated for an operated at 200kv or higher, or 4) some similar situation to 1-3 above} The SDT sees this Section as following
the Rules of Procedure Standard Applicability Section as noted on page 9 to “identify any limitations on the applicability of the standard based on
electric facility characteristics”.
The SDT modified Requirement R1, Part 1.1 as suggested. The standard does not explicitly state that the interim corrective action process in 1.5 must
be implemented. The SDT suggests that the other requirements in the standard related to outages and imminent threats and encroachment provide
necessary and sufficient incentives for TOs to utilize the process when and if required.
R9 and R10 (now R10 and R11) have been revised to replace the RC with the PC as the applicable functional entity. The verbiage “in consultation with”
has been replaced by “shall consult with its Transmission Owner(s) and neighboring Planning Coordinators to obtain input to develop the list”. Since
this list is prepared by the PC for the TO to know of any sub 200 kV line(s) that the TO must maintain, the SDT does not see a benefit to adding a
requirement that the PC will provide the list to the TO.
The SDT chose to keep the word “grid” in lieu of BES to avoid confusion related to the fact that the BES generally includes all lines above 100 kV as
defined by the Regional Reliability Organization and this standard does not.
Other changes were made in the language of R9 and R10 to which incorporate parts of recommendations from other commenters and FE. Requirement
R10, Parts 10.1 and 10.2 were redundant, and Part 10.1 was deleted and Part 10.2 was translated into a separate requirement, R11.
Midwest ISO
Stakeholders Standards
Collaborators
FAC-003-1 lacks clarity that is essential for understanding what is necessary for compliance. The proposed FAC-003-2 needs to be
simplified to aid with field implementation and compliance interpretation. Currently, it does not provide the clarity and simplification
needed by Transmission Owners and regulatory bodies to enhance reliability.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The essential changes are: The CCZ concept has been replaced with the concept of minimum clearance distances, and
Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time.
These changes should add the clarity and simplification that your and other commenters suggested was needed for field implementation.
SERC Compliance Staff
SERC staff continues to find the Applicability section of the standard to be confusing and contentious. While we recognize it is the intent
this section to make the standard applicable t all entities that own transmission lines that operate at greater than 200 kV, this section
should not be written to be applicable to transmission lines. Only registered entities can be held accountable for compliance with the
standards. SERC staff believes the applicability should be rewritten to include Transmission Owners, Distribution Providers, and
Generation Owners that own transmission lines with the characteristics defined in Section 4.2. This would eliminate the need to make
register, for example, a Distribution Provider that own a 230 kV line that serves load as a Transmission Owner and make them subject to
the requirements of FAC-001 and FAC-002. SERC Staff also suggest the applicability could be handled as it is in PRC-005-1 where the
applicability is qualified as 'distribution provider that owns..' and 'generator owner that owns..' or in a similar manner that captures the
appropriate subgroup but does not include unintended entities.
SERC Staff believes a flashover between vegetation and overhead ungrounded supply conductors that occurs, whether or not the
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flashover results in a Sustained Outage, is clear evidence of an unallowable encroachment of vegetation into the space that should be
avoided and thus should be identified as evidence of a violation of the standard. SERC staff has also found that excluding outages
resulting from "earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the
Transmission Owner?" results in inconsistencies in reporting because of the inconsistency of the Transmission Owners' definitions of
same. If such exceptions are to be allowed, a consistent method of determining the acceptability of those exemptions should be
pursued.
Response: The SDT thanks you for your comments.
The intent of the Facilities section under Applicability which you suggest is confusing and contentious, was chosen to follow the Reliability Standards
direction under Applicably, specifically “if not applicable to the entire North American bulk power system, then a clear identification of the portions to
which the standard applies…”
The issue you raise with respect to Distribution Owners and Generation Owners does not appear to be supported when one reviews the definition of a
Transmission Owner in the NERC Glossary “The entity that owns and maintains transmission facilities.” The SDT is concerned that your suggestion
will add confusion to the standard.” PRC-005-1 properly addresses the coordination needed between transmission protection and the interface with
distribution protection at the point of transformation. There is no comparable expectation for vegetation maintenance on the low voltage side of a
transmission to distribution transformer to be subject to this standard. Simply put, either someone owns transmission or does not. It is of no matter
whether they may also be a DP or GO. Until the functional model includes provisions to state that “all transmission is not equal”, the applicability
should remain.
Your concern about flashovers that do not result in Sustained Outages needing to be stated as violations of this standard has been discussed at length
by this SDT. The interest is to have a Standard that is not subject the levels of uncertainty associated with any automatic operation which is returned to
service by either manual or automatic means. These events are very often not possible to identify, many times misidentified often occur during
conditions that have several possible explanations (such as high winds blowing conductors together, wind-blown debris, lightning, contamination
flashovers during the onset of wind and rain storms) and do not have a historical basis for ever creating a cascading event. Inclusion of these events
as violations in the standard could also cause significant additional costs for extensive investigations by TOs to prove their “innocence” for events that
any properly designed and operated transmission system should withstand with no more challenge that the far greater number of lightning, and
equipment failure events (cross-arms, insulators, conductor splices, poles) nor ever been the subject of momentary opera being.
Members of the SDT attempted to get the TADS reporting requirements to clearly identify those faults on transmission lines that required maintenance
to return the line to service. If such a definition was entertained, then a great deal of the uncertainty is cleared. However there are still conditions
where trees and poles are found down after apparent high wind conditions in locations remote to the nearest weather reporting station that depend on
assumptions as to which fell first the pole or the trees. The zero tolerance nature of this standard and the Penalty Matrix values should not be tied to
anything with a high degree of assumption and uncertainty. Therefore the standard has been revised and worded to have the violation of MVCD as
observed in real time.
As an added note there is unnecessary confusion caused by simply labeling the automatic operation line operations as momentary, sustained, and/or
locked-out. If a line is not reclosed within moments of the automatic interruption, but is later “test closed” was the line truly unavailable? Was the
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reclosing signal/command properly performed initially? Did the TOP ever truly lose control of this line if all that was required was another close
attempt? The true nature of the loss of a line is manifested when it is known that a clearance must be issued such that the line is removed from the
TOP’s control.
The SDT has reviewed the data on vegetation related reported outages on the NERC website. There are 223 reports of outages in that data covering the
period January 2004 to March 2009. The associated documentation with these events indicate that TOs are supplying supportive information to
indicate that the level of any disaster exclusion is sufficient to identify that design criteria was exceeded. Further specifics on the threshold for each
disaster would not ensure that weather data would be adequate to support each location/situation.
ITC HOLDINGS
V1 was a better written standard and had clear requirements on reporting and who was to report violations etc. When and how are
violation to be reported is not mentioned in the V2. The standard should clearly identify all reporting requirements. Standard
development should focus on practicality for the field personnel in terms of implementing the standard and enforceability. Version 2 is not
as user friendly for field personnel and ambiguous at best which requires an impractical and unrealistic level of performance from the
industry. This standard needs to stress that it applies to vegetation within the Active Transmission Right of Way. Vegetation from outside
the active ROW, falling through the Critical Clearance Zone should not be a violation. V2 needs further clarification of the definition of
the active ROW.
Response: The SDT thanks you for your comments. The issue of reporting has been addressed in the compliance section of the revised standard.
The changes made to R4 focus on the practicality for field implementation that you suggest. The exclusion you request for vegetation falling through
the MVCD, regardless of its being form inside or outside the right-of-way, has been added.
The definition of the active right of way was debated at length and determined to be best stated in its current form.
Exelon
Applicability. 4.2.2 is unclear. If 4.2.2 is intended to cover Generator Owner interconnections, say so uniquivocally. Do not rely on future
changes to the NERC Registry Criteria or other "global" solutions if the intent is to make the standard applicable to Generation Owners
who own generator leads.
Exelon would like to reemphasize our concern with implementing the requirements if the Gallet equation derived Critical Clearance Zone
is used. ANSI A300 part 1 and part 7 should be part of the standard as they provide independently recognized valid methods and
guidance to conduct maintenance on the ROW corridor.
Response: The SDT thanks you for your comments.
The issue you raise with respect to Generation Owners does not appear to be supported when one reviews the definition of a Transmission Owner in
the NERC Glossary “The entity that owns and maintains transmission facilities.” The SDT is concerned that this suggestion to add the Generation
Owner will add confusion to the standard.” The SDT does not agree there is ambiguity. Either an entity is a TO or not.
The Gallet Equations distances were chosen in lieu of ANSI A300 for clearances because the Gallet is a distance that is necessary to prevent flashover.
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The ANSI values are related to worker and public safety not flashover between the conductor and the vegetation.
Central Maine Power
Company
The White paper is an important support document and should remain as an attached reference to FAC 003. The white paper should
clarify that capable tree species should always be removed from the border zone, except in selected areas where topography includes
deep ravines.
Response: The SDT thanks you for your comments. The standard was designed to allow the Transmission Owner the flexibility to design its TVMP.
Further, ANSI A300 is also footnoted in the standard as a “best practice”. The White Paper will remain a reference for this Standard and text has been
added to try to provide additional guidance as you suggest.
American Electric
Power (AEP)
The definition for Critical Clearance Zone (Critical Clearance Zone ) on page 2 of the proposed draft Standard does not specify the
Rating (summer, winter, normal, emergency, etc.). This suggests that different Critical Clearance Zone s apply at different times of the
year and thus that vegetation in the area might be outside the Critical Clearance Zone at certain times of the year and inside the Critical
Clearance Zone at other times. AEP suggests that this may not have been the intent of the drafting team.
Also, the term "design blowout" is not defined; thus, it appears that it will be up to the Transmission Owner and the auditor to determine
the bounds of the Critical Clearance Zone . AEP again suggests that this may not have been the intent of the drafting team.
Requirement R9 contains the clause "within the extent of its easement and/or legal rights". This intent of this clause is unclear and its
rationale is not obvious. AEP suggests that this clause be removed or at least reworded for clarity.
Response: The SDT thanks you for your comments. The CCZ concept has been replaced with the concept of minimum clearance distances, and
Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time. The
verbiage you suggested removing form R8 (now R9) was removed. Finally, the new Requirement R1 should address the concern about sag and blowout
in that it talks about planning to keep vegetation out of all positions the conductor may be for all design conditions.
Platte River Power
Authority
The white paper ensures consistent interpretation of the standard. Perhaps the lack of such a paper in the first version of the standard
contributed to the varying interpretations.
Response: The SDT thanks you for your comments. The White Paper will accompany this Version as a Reference document.
City of Tallahassee
Attachment I. Titles are different between page 8 and 9. Page 8 should have (D) after Distances. Page 9 should have indication that it
is "continued" since the table spans multiple pages.
Response: The SDT thanks you for your comments. The SDT has reformatted the table in Attachment 1 of the Standard.
Northern California
Section A. 5. Effective Dates: This is extremely vague and I would not know the actual effective date. Whose regulatory approval is
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Power Agency (NCPA)
needed? If this is meant to leave flexibility between FERC and the Canadian entities, please write it that way. Most effective dates are
clear and concise, i.e., "the first month following approval by FERC". Let's clear this up and avoid a subsequent interpretation request.
Response: The SDT thanks you for your comments. The wording of this portion of the standard (the Standard’s effective date) is governed by NERC
policy. The process for approval is different in different jurisdictions – some Canadian Provinces approve a standard when it is approved by the NERC
Board of Trustees, other Provinces have other mechanisms for approving standards. For entities that operate in the United States, the FERC is the
regulator that must approve the standard. As written, the standard will become effective in the United States the first calendar day of the first calendar
quarter one year after FERC approval.
Northern Indiana Public
Service Company
While I very much respect the industry commitment and expertise of the drafting team members, the resulting revised standard reflects
an effort to "revolutionize" the standard, when an "evolution" of the current standard would better serve the interests of system reliability.
The kinds of wholesale changes proposed in this revision evoke real concerns about governmental regulations being a moving target
and in many aspects, backs away from requirements that have led to real progress in UVM made since the 2003 blackout. For example,
our company has invested tens of thousands of dollars and countless man-hours to comply with provisions of the existing standard only
to see them simply done away with under the proposed revised standard. These investments were made based on an industry
consensus standard as well as a realization that the requirements were reasonable and essential to improving system reliability. Where
is the evidence that the current standard is not working as intended? What has changed in the last few years to warrant a complete rewrite of the current standard? Most UVM professionals will agree there are some changes that need to be made to address FERC's
concerns and to clarify intent. However, as presently written, I will recommend our T.O. vote against adoption of FAC-003-2.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The essential changes are: The Critical Clearance Zone concept has been replaced with the concept of minimum clearance
distances, and Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in
real time. Moreover, certain language changes were needed to comply with directives in FERC Order 693. The changes proposed are meant to
capitalize on programs already implemented, not to discard them.
Tampa Electric
Company
Good start. However, this will need additional work and review predicated on the above comments.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The essential changes are: The CCZ concept has been replaced with the concept of minimum clearance distances, and
Transmission Owners are required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time.
Orange and Rockland
Utilities Inc.
Clearance 1 has been eliminated from this draft. Version 2 as drafted only requires that Transmission Owners address vegetation that
approaches the Critical Clearance Zone . This is essentially equivalent to Clearance 2 in version 1, a minimum clearance. Although
unlikely this could result in some Transmission Owners adopting a just in time vegetation management concept that focuses on
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maintaining minimum clearances, rather than removing incompatible vegetation or achieving greater clearances. Although R1 requires
Transmission Owners to design their Transmission Vegetation Management Programs to control vegetation there is no clear
requirement to address incompatible vegetation early and aggressively. The drafting team should revisit this and consider returning to
some form of Clearance 1 or requiring the Transmission Vegetation Management Program to address removal of incompatible
vegetation within their easement rights.
Response: The SDT thanks you for your comments.
The SDT did revisit and reconsider reinserting a Clearance 1. The issue of how and when to remove or control “incompatible vegetation” was also
revisited. The SDT decided to leave C1 and the methods to control (or remove) “incompatible vegetation” to the discretion of the TO. Such
discretionary measures do not meet the qualifications to be a requirement within a standard.
Please take a comprehensive look at all the requirements in the standard we are now re-submitting with this posting. Compliance with these
requirements will ensure that the TO maintained vegetation such that 1) no controllable sustained interruptions have occurred, 2) no imminent threats
were left unaddressed, 3) all the separation distances between the conductors and vegetation every time they were observed were greater than the
distance necessary to prevent a flashover.
Compliance with each of the above requirements can be achieved with inspection and pruning cycles on a frequent basis such as annually, or on a
longer term basis such as every 4 years where warranted by local conditions. There are numerous examples in the industry of these different
approaches being both appropriate and effective. Just because a “shorter cycle” is utilized, does not mean that a compromised or “just-in-time”
concept is has placed the adequate level of reliability of the grid at risk.
American Transmission
Company
FAC-003-1 lacks clarity that is essential for understanding what is necessary for compliance. The proposed FAC-003-2 needs to be
simplified to aid with field implementation and compliance interpretation. Currently, it does not provide the clarity and simplification
needed by Transmission Owners and regulatory bodies to enhance reliability. Requirement 1.3: The proposed requirement does not
allow enough flexibility for making changes to the Annual Plan. We believe that changes to the Annual Plan should be allowed even if
that means delaying something until the next Annual Plan. Our Proposed Changes: Have an annual plan that identifies the applicable
lines to be maintained and associated work to be performed. Adjustments to the annual plan are permissible. We believe that our
proposed language accomplishes the SDT's intent while allowing for appropriate flexibility.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. Those changes, including the removal of the concept of the CCZ, address and provide the clarity and simplifications you suggest
are needed for field implementation of the standard. R1.3 has been revised for to provide clarity.
These R1.3 changes do not explicitly remove the “within the year” clause as you requested, however we do not see the inclusion of that language as
restricting appropriate flexibility. It is expected that the annual work plan will be flexible to adjust to changing condition and findings which occur after
the plan is first issued for the year, then adjusted within the year as appropriate. Adjustment made within a year may mean accelerating work to the
current year that was not in the current year’s plans as well as extending work that was initially planned for this year into the future. And when
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disasters occur, the SDT has addressed an appropriate extension.
Xcel Energy
Attachment 1, Table I- Change the title of the table from "Proposed Minimum Vegetation Clearance Distances" to "Critical Clearance
Zone Distances". The reason being is that the general public could interpret this table to mean that this is all the clearance that is
required by a utility at the time of pruning.
Section C, Violation Severity Levels- There is some inconsistency between the C.2 chart and the contents of the Standard and the White
Paper. For example, the White Paper specifies that an exception to an R6 blowing together violation would exist for sustained winds of
gusts of 45 miles per hour or greater.
As to R7, the Standard itself notes that a violation only occurs if the vegetation falling into the line is from within the ROW ? C 2 does not
incorporate that requirement. There are two approaches: either note the exemptions within the C 2 chart, or add a footnote to the chart
along these lines: "This chart summarizes various provisions, the details of which are more fully set forth in the Standard and White
Paper?. We would recommend the later approach.
General suggestions:
1) It appears that the FAC-003 Standard is the only "zero tolerance" standard, in some respects. Is this reasonable?
2) There appears to be "advisory" language in this version of the Standard. This type of language should be part of the White Paper, not
the Standard itself.
3) Utilities need more support from FERC to deal with regional roadblocks within the USFS regarding the implementation of IVM. The
Memorandum of Understanding is not universally accepted within all regions of the USFS.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment parts of those changes address or remove the issues you raise for exemption and footnotes for Table 1.
Table 1 in not intended to be used by TOs to determine how much to prune. This table provides the actual physical separation distances, which if
observed, will ensure that flashover from the line to vegetation will not occur. When conditions exist such that the separation is reduced the risk of
flashover will become significant. The risk increases as the separation is reduced. Therefore this value represent a threshold which if not violated will
prevent flashover, as such it is a valid physical basis for R4 compliance.
This standard allows the TO to use any combination of pruning, removals of vegetation at ground level, frequency(cycles) of planned maintenance,
enhanced inspections, off-cycle corrective maintenance, etc to prevent violations occurring due to vegetation causing a non-exempted sustained
outage or MVCD violation.
Due to the industry impact that arises from zero tolerance for vegetation-related sustained outages, the Drafting Team tried several approaches but
could not find a mechanism in the standard development process to establish a non-zero threshold for outages that was acceptable to FERC staff
because revisions to Standards may not produce less emphasis on reliability.
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The advisory language in R1.4 has been removed.
The SDT discussed with NERC and FERC the need for support with the USFS issues. The SDT concluded that FERC has no power to change the rights
or restrictions within any permit or easement document across privately owned or publicly owned.
Therefore any efforts to improve permits or reduce limitation on permits or easements on federal lands must be handled through other available
methods.
Ameren
While FAC-003-1 lacks clarity that is essential for understanding what is necessary for compliance, the proposed FAC-003-2 needs to be
simplified to aid with field implementation and compliance interpretation. Currently, it does not provide the clarity and simplicity needed
by Transmission Owners to implement and regulatory bodies to monitor in a manner that will enhance reliability.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. Those changes address and provide the clarity and simplification you suggest are needed for field implementation of the standard.
Long Island power
Authority
1) Disagree with R1.1. The proposed standard is too lenient on the program documentation required for an effective program. R1.1
should include the words " the program will document the program objectives, method of site evaluation, the definition of action
thresholds, the control methodologies, and how the monitoring program is established". There is a wide gulf between listing IVM
methodologies and a vegetation program implementing A300.
2) CHANGE: Within Applicable Facilities listed in section 4.2 the phrase Transmission Line should be changed to Overhead
Transmission Line. The NERC Glossary definition of transmission Line is: " A system of structures, wires, insulators and associated
hardware that carry electric energy from one point to another in an electric power system. Lines are operated at relatively high voltages
varying from 69 kV up to 765 kV, and are capable of transmitting large quantities of electricity over long distances." The accompanying
white paper states the standard is addressing the impact of vegetation growth on overhead transmission lines. The intent of this
standard is the development and implementation of a vegetation management program for overhead transmission lines only. By
specifically stating "overhead transmission lines in Section 4.2 there will be no possibility of an occurrence of an auditor requesting a
vegetation management program for underground lines.
Response: The SDT thanks you for your comments. In R1.1 the SDT chose to direct the TO to specify the methods used to control vegetation vs
specifying a menu of items that may not be applicable to several TOs due to the limited types of vegetation in their areas. The SDT considered the
issue of overhead versus underground and concluded that no further clarification was needed. Further, ANSI A300 is referenced in the Standard as a
best management practice. The SDT leaves up to the TO the extent to which it wishes to apply A300.
USDA Forest Service,
Southwestern Region,
Regional Office for AZ
and NM
I'm having trouble getting comments to "stick" in this section of the form. I have a general concern with the opening paragraph of R1.
The wording seems to encourage a Transmission Owner to develop a Transmission Vegetation Management Program in a vacuum.
The US Forest Service definitely wants input into the development of an annual work plan and USFS land use authorizations include a
requirement for USFS approval of vegetation management plans. It seems much more reasonable to require the Transmission
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Vegetation Management Program to reflect USFS or any other landowner resource management considerations. This tactic would
require more "up front" work, but the end result is a plan which would reflect reasonable landowner input and where the disagreements
could be settled ahead of time rather than being left for the night shift. I also believe that some kind of dispute resolution process is
needed outside the control of either the Transmission Owner or the USFS. I think that NERC could fill that role very well.
Response: The SDT thanks you for your comments. Underlying landowner rights are outside the purview of this Standard. However, the SDT
recognizes the value in “up front” input between landowners and transmission Owners. Notice that in this posting of the standard within Requirement
1 at 1.3.4 the transmission vegetation management program shall “take into consideration permitting and scheduling requirements from landowners
and regulatory authorities”. Such consideration should aid in addressing the issues you raise.
Consumers Energy
Company
The annual work plan should be designed to avoid vegetation growing into a violation of the Critical Clearance Zone or whatever
minimum distance is acceptable. Since the plan can change throughout the year, it needs to be flexible, it should be stated that the plan
at a minimum must provide adequate funding to prevent vegetation growth from violating the minimum clearance distance. The flexibility
of change should be limited to changing to address emergent needs for vegetation management and not reductions in funding that delay
maintenance in the hopes that additional funding at some future point in time will be adequate to remove the backlog of vegetation
maintenance. The Purpose of the standard should be revised to state "(To maintain minimum clearance sufficient to avoid any
vegetation-related Sustained Outages for all applicable conditions) for all Transmission Lines covered by this Standard" as provided by
FERC in Order 693, Paragraph 731. The purpose as stated in FAC-003-2 waters down the intent of FERC to "improve the reliability"
and is only applicable to "outages that could lead to cascading".
Response: The SDT thanks you for your comments. The purpose statement language was chosen to explicitly state the outcome to be achieved by this
standard. The requirements themselves address, among other things, the Sustained Outages and minimum clearances along with the required
supporting language. This separation between the purpose and the requirements appears more appropriate to the SDT. Significant changes have been
made to the current draft of the Standard based upon substantive industry comment. The essential changes are: The CCZ concept has been replaced
with the concept of minimum clearance distances, and Transmission Owners are required to prevent encroachment of vegetation into minimum
vegetation clearances distances as observed in real time. Further, funding is not an issue addressed by this Standard.
National Grid
National Grid has the following comments:
1. Transmission Owners should be able to define their own inspection "year" and not be locked into a calendar year time frame.
National Grid performs inspections at least once per vegetation growth year. Under our Vegetation Management Program, growth years
are not skipped, and our inspections occur prior to new growth every year. For example, a transmission right-of-way may be inspected in
December 2008 and the right-of-way is next inspected in February 2010. Under this scenario, the inspections occurred 14 months apart,
but only one growth year occurred between inspections, and each inspection is ahead of the next year's growth. Transmission Owners
need this flexibility to deal with regional growth rate differences and climate.
2. Section C., Compliance, of Draft Standard FAC-003-2 states "To be added". Issuance of Draft Standard FAC-003-2 should have
been delayed for comments until all sections were complete. This section is likely to include the outage reporting and self-certification
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requirements. Transmission Owners need the opportunity to comment on these items.
3. With the elimination of Clearance 1 and reducing Clearance 2 clearances, there is concern that FERC will view Standard FAC-003-2
as a watered down version of Standard FAC-003-1.
Response: The SDT thanks you for your comments.
1.
It is recognized that most work management systems typically allow for planned work to be performed within a “band of dates” around a specific
end date, such as one-third or one-fourth of an interval. These partial intervals allow for the normal variations that occur in work scheduling. When
work is completed within that band of dates it is considered completed “as scheduled”. Compliance to R2 should be examined for the example
conditions you offer since you are addressing the implementation of the inspections. If the frequency was stated in the vegetation management
program as once per calendar year, and if the work was completed “as scheduled” then the TO would be compliant.
2.
The compliance elements are included with the second posting of the standard and will be subject to stakeholder comments.
3.
Effort were undertaken to address in the standard various elements for outages, imminent threats and clearances in a manner that was
responsive to a substantial number of industry concerns. The SDT is striving to meet industry stakeholder concerns with a standard that will be
approved by its ballot pool, the NERC BOT, and regulatory authorities, including FERC
Pacific Gas & Electric
Co.
1) The standard should be clear that it applies to all Federal and Non-Federal land. PG&E further recommends additional language
specifically dealing with Federal land such as application of ANSI A300.
2) The standard should specify applicability inside substations.
Response: The SDT thanks you for your comments. This Standard states in the applicability section that all lands are subject to the standard. Further,
ANSI A300 is footnoted in the Standard. Substation facilities are not included in this Standard. This will be addressed in the White Paper.
NV Energy (fka Sierra
Pacific / Nevada Power
Co.)
These comments were made with collaboration with other Western Utilities in a conference on this topic held in Denver. Any standard
that is developed should not contain advisory-type language? it should be declarative in tone. For example, in R1.4, the ending clause
that begins “and may include actions” should be removed because it is advisory in nature. The suggested actions are not even the
responsibility of the vegetation management program. NV Energy and the other Western Utilities support the development of this white
paper as a way to help ensure consistent interpretation of the standard. Perhaps the lack of such a paper in the first version of the
standard contributed to the varying interpretations by the auditors. The utilities understand however that this document is not a legal
document and is not binding.
Response: The SDT thanks you for your comments. Please refer to the various responses to your comments provided in the individual questions.
(R1.4 was modified to eliminate the list of possible actions and the use of the word, “may.”)
The changes to the standard in this reposting and the responses to your comments on questions 1-17 are intended to serve as a reply to your various
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comments.
San Diego Gas &
Electric
We feel that any advisory-type language should be removed from the standard and replaced with wording that is in a declarative tone.
We support the development of the white paper as a way to help ensure consistent interpretation of the standard.
Response: The SDT thanks you for your comments. The advisory-type language has been removed form R 1.4
Hydro One Networks
Inc.
Please see our comments on question 3.
Response: The SDT thanks you for your comments. Please see the response to comments on question 3.
Edison Electric Institute
Overall Comments EEI strongly believes that companies are responding assertively to the requirements in FAC-003-1 and that the
existing standard is effective in supporting an adequate level of reliability. The central issue with FAC-003-1 and the draft version 2
centers on circumstances where vegetation encroachments into clearance zones take place and do not result in interruptions. EEI
understands that a potentially broad range of interpretations are being applied to the existing standard, resulting in potential violations
due to clearance encroachments of any possible design position of the conductor being violations, as well as Sustained Outages.
Version 2 should clarify this issue in the context of focusing the industry in the direction that is most effective in establishing an adequate
level of reliability. The technical comments provided by EEI seek to address this critical issue. Quantitative analysis on vegetationrelated line outages or violations made publicly available do not support the need for a substantive revision of the standard. Analysis
needs to recognize a broader range of facts in a consistent manner. Analysis needs to consider whether violations resulted in a
Sustained Outage, whether all outages and vegetation encroachment were voluntarily reported prior to enactment of Section 215, or the
facts and circumstances surrounding violations. For example, while some entities may perceive a decline in industry performance, it
may be that companies are reporting much more completely than in the past. Much more rigorous analysis is needed before concluding
that the existing standard must be made tougher. Rather than focusing on whether the standard should be more stringent, EEI believes
that the emphasis in the standard development process should focus on practicality, both for field personnel in terms of implementing the
standard, and enforceability.
Revisions to the existing standard should therefore seek to a) respond to issues raised by FERC in Order No. 693 b) where possible,
clarify ambiguities in the requirements, and c) improve industry understanding, practicality, and enforceability. For example, it is
impractical to seek development of a ?bright line? set of performance requirements. The standard needs to recognize both the diversity
of the continent in terms of geography, topography, and climate, and the critical need to provide field personnel with workable
performance requirements. Bottom line; it is very important to recognize that the ultimate goal of the standard is to ensure that
vegetation management is conducted in order to maintain an adequate level of reliability, and the industry is achieving this goal. The
standard should aim for increasing clarity in the requirements without sacrificing flexibility, since companies expect high monetary
penalties associated with Sustained Outages caused by vegetation. In addition, a continued ?zero tolerance? approach to vegetation
management will emphasize operational excellence. Seeking ?zero tolerance? on momentary outages is equivalent to pursuit of
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operational perfection, which is achievable only at extraordinary expense to customers. Therefore, the Standard will be most effective if
its elements encourage proactive behavior and provide incentives for Transmission Owners to identify and address vegetation clearance
issues before they result in momentary interruptions or Sustained Outages. Vegetation Outage Data In Order No. 693, Paragraph 732,
FERC ordered NERC to collect and analyze transmission outage data to inform development of the revised standard. EEI encourages
the drafting team and NERC Standards Committee to request that NERC collect and analyze this critically important information. Such
analysis provides an important foundation for determining whether the standard can ensure an adequate level of reliability as required by
Section 215.Applicability Order No. 693, Paragraph 708, directs NERC to 'develop an acceptable definition that covers facilities that
impact reliability but balances extending the applicability of this standard against unreasonably increasing the burden on transmission
owners.' In the order, FERC appears to accept the 200-kv threshold, however, continues to ask about these other critical facilities.
EEI recommends that the drafting team develop a definition of 'sub- 200kv critical facilities' for use in the standard. Reliance on
Reliability Coordinators for developing their own definition raises the likelihood of inconsistent approaches and applications of the term.
In addition, the drafting team should consider whether such critical facilities might require expanding applicability to entities other than
Transmission Owners.
Annual Plan as a Defined Term In order to aid in compliance enforcement and industry compliance, the term 'annual plan' should be a
defined term.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. We agree with many of your points. The SDT developed R2 to promote proactive behavior by requiring the recording and
documentation of imminent threat procedure implementations. The NERC Transmission Availability Data System is set up to collect the outage data as
directed by the FERC. In the revised standard, to address the sub 200 kV facilities to be subject to the standard, the SDT chose the Planning
Coordinator (rather than the Reliability Coordinator) for that task. The Planning Coordinator has the wide area view and appropriate time horizon
perspective to identify sub 200 kV facilities. The SDT considered the situation where non-TO facilities such as generator “leads” would be subject to
this Standard. There is an ongoing discussion within NERC with regard to registration of Generator Owner’s as limited TO’s. Annual plans have
relevance within this Standard’s context and are not needed elsewhere. Therefore a glossary definition is not necessary.
Consolidated Edison
Company of New York
(CECONY)
CECONY does not feel that, as currently written, the Standard would effectively enhance reliability throughout the industry. We
recommend that stricter language be used in the Standard specifically requiring the industry to remove incompatible species on Active
ROWs. This should reduce the number of outages resulting from vegetation grow-ins and vegetation fall-ins from inside the Active ROW
and help maintain a higher level of reliability. This is currently done at the state level (in NY) and the revised wording in the Federal
Standard may help promote consistency industry-wide and avoid confusion. Also, the concept of the Critical Clearance Zone is
theoretically strong but it needs to be made simpler for the auditors and field inspectors.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. We agree with many of your points. The SDT developed R2 to promote proactive behavior by requiring the recording and
documentation of imminent threat procedure implementations. The NERC Transmission Availability Data System is set up to collect the outage data as
directed by the FERC. . In the revised standard, To address the sub 200 kV facilities to be subject to the standard the SDT chose the Planning
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Coordinator (rather than the Reliability Coordinator) for that task. The Planning Coordinator has the wide area view and appropriate time horizon
perspective to identify sub 200 kV facilities. The SDT considered the situation where non-TO facilities such as generator “leads” would be subject to
this Standard. There is an ongoing discussion within NERC with regard to registration of Generator Owner’s as limited TO’s. Annual plans have
relevance within this Standard’s context and are not needed elsewhere. Therefore a glossary definition is not necessary.
WECC
Reporting requirements are not identified in the standard. WECC believes that sustained outages caused by vegetation should be
reported to the Regional Entity using the existing reporting requirements in FAC-003-1 (Transmission Owners report outages to the
Regional Entity). Reports of sustained outages to the Reliability Coordinator should be made for reliability purposes and not compliance
purposes. The Reliability Coordinator should not be required to report vegetation outages of individual Transmission Owners to the
compliance department.
Response: The SDT thanks you for your comments. The revised Standard reflects changes in reporting requirements.
Arizona Public Service
Company
APS has a comment to NERC on picking the standard drafting team. FAC-003 is a vegetation management standard not an engineering
standard. The team members should have been chosen based on managing the vegetation program not because they were engineers.
Any standard that is developed should not contain advisory-type language? it should be declarative in tone. For example, in R1.4, the
ending clause that begins “and may include actions” should be removed because it is advisory in nature. The suggested actions are not
even the responsibility of the vegetation management program. APS supports the development of this white paper as a way to help
ensure consistent interpretation of the standard. Perhaps the lack of such a paper in the first version of the standard contributed to the
varying interpretations by the auditors. The utilities understand however that this document is not a legal document and is not binding.
Response: The SDT thanks you for your comments. The members of the SDT were selected based on their expertise – the following was taken from the
SDT Nomination form:
Candidates should have expertise in one or more of the following areas:
-
Transmission line rights-of-way (ROW) vegetation management or ROW maintenance
-
Transmission line design and ratings
-
Regulatory or legal considerations in ROW maintenance
-
Existing codes and good practices in vegetation management
Most of the SDT members have expertise in vegetation management.
The SDT has removed the advisory language in R1.4. The SDT has professional foresters, vegetation managers, system operators and regulators.
Baltimore Gas & Electric The Applicability Section of the Reliability Standards (4.2 Facilities) defines the Transmission Lines (Applicable Lines) that must comply
to the reliability standard. This section should clearly state that the scope is limited to the facilities that are Bulk Electric System facilities
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consistent with the Bulk Electric System definition as defined by the Regional Entity.
Regarding M5, M6, M7:The intention of these paragraphs is unclear to me as written. At first glance, it appeared that the paragraphs
were asking for a negative to be proven, e.g. prove that you didn't have any tree-related outages. Anther possible meaning is that
utilities have to justify the cause of any outage that may occur. As such, the burden of proof is on the Transmission Owner to provide
evidence that an outage was not caused by trees. If an outage were to occur but the Transmission Owner could not find any evidence of
the cause, the wording in these paragraphs suggests that by default, the outages will be classified as tree-related. If these paragraphs
are intended to assign an outage cause to an outage that has already occurred, then perhaps they could be reworded to say something
to the effect of: "Transmission Owner shall provide results of investigation into all transmission outages?? "If these paragraphs are not
intended to assign an outage cause to an outage that already occurred, but to provide a mechanism to report outage performance that is
currently covered in M3 and M4 in FAC-003-1, then perhaps they could be reworded to say something to the effect of: "Transmission
Owner shall provide documentation of tree-related outage performance on a quarterly basis. Investigation results for unknown outages
shall also be provided on a quarterly basis." Or as one last suggestion, the wording could simply be: " The Transmission Owner has
evidence that there was a Sustained Tree-related Outage?.
Regarding the Tech. Reference, I thought that overall it was helpful and will be valuable to help provide guidance for Transmission
Vegetation Management Program development and implementation. The area that covers the Active/Inactive R/W should be more
clearly explained and illustrated, particularly with respect to the towers with space for another circuit on one side of the structures.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The old M5, M6, and M7 have changed in a manner that should clarify their interpretation as you requested. The CCZ concept has
been replaced with the concept of minimum clearance distances, and Transmission Owners are now required to prevent encroachment of vegetation
into minimum vegetation clearances distances as observed in real time.
Reporting requirements are included in the compliance section with this posting.
The SDT will attempt to incorporate your suggestions on illustrations for double circuits in the white paper with the final posting of this standard.
Duke Energy
Corporation
FAC-003-1 lacks clarity that is essential for understanding what is necessary for compliance. The proposed FAC-003-2 needs to be
simplified to aid with field implementation and compliance interpretation. Currently, it does not provide the clarity and simplification
needed by Transmission Owners and regulatory bodies to enhance reliability.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. The CCZ concept has been replaced with the concept of minimum clearance distances, and Transmission Owners are required to
prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time. These changes are directed at the clarity
and simplification you requested for effective field implementation and compliance interpretation.
CenterPoint Energy
The proposed FAC-003-2 has gone FAR beyond what was contemplated by the Commission in FERC Order 693 and equates to a total
re-writing of the Standard for no apparent reason. The Commission's determination dealt with the following areas: (1) applicability; (2)
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inspection cycles; and (3) minimum clearances on National Forest Service lands. For instance in Paragraph 729, the Commission
states, “As proposed in the NOPR, the Commission approves Reliability Standard FAC-003-1 with no proposed modification on the issue
of clearances. The Commission reaffirms its interpretation that FAC-003-1 requires sufficient clearances to prevent outages due to
vegetation management practices under all applicable conditions?.” Rewriting the minimum clearances introduced a new set of
confusing definitions, and further burdens the Transmission Owners with new documentation requirements with little if any benefit when
compared to the Clearance 2 concept in the existing Standard. A preferred approach would have been to incorporate the following few
items into the existing Standard: (1) the RC versus the RRO; (2) the designation of a specific inspection frequency; (3) the Gallet
equation; and (4) the applicability to National Forest Service lands. We agree that the removal of requirements for quarterly reporting of
outages, Clearance 1, and personnel qualifications reduces the burden on the Transmission Owners and does not affect the purpose of
the standard to prevent vegetation outages. The Standard could meet its purpose and be streamlined by considering the following
changes:1. Delete the new terms and definitions for "Active Transmission Line Right-of-way" and "Critical Clearance Zone" and revert
back to a Clearance 2 requirement while replacing the IEEE 516 standard distances with the Gallet equation standard distances.2.
Delete R2, M2, R4 and M4 which refer to the "Critical Clearance Zone" and rely on R5, M5, R6, M6, R7, and M7 which refer to the
prevention of Sustained Outages.3. Delete R1.5 and M1.5 as a requirement and measure, but footnote the "interim corrective action
process" as a best practice as was ANSI A300 in R1.1.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. Items such as the CCZ concept has been replaced with the concept of minimum clearance distances, and Transmission Owners are
required to prevent encroachment of vegetation into minimum vegetation clearances distances as observed in real time. Note that the SAR for this
project included a list of items to be addressed in the revised standard – and these items included not only the directives in Order 693, but other issues
identified during the initial implementation of the standard and during the refinement of the SAR.
Entergy Services
Entergy requests that the proposed FAC-003-2 revision continue work on clarifying the above mentioned “Disagree” items and
appreciates the consideration of the above comments in the development of the standard. A clear understanding of all standard
requirements by the industry is needed to make certain field implementation is achieved and that ultimately we improve system reliability.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment. Those changes were made in part for the clarity that you and others requested in order to ensure that practical field implementation
may be achieved.
Alberta Electric System
Operator
The AESO is also a signatory to the joint ISO/RTransmission Owner Council Standards Review Committee comments which reflect our
comments to the other questions in the Comment Form.
Response: The SDT thanks you for your comments. Please see the SDT’s responses to the ISO/RTO SRC comments.
JEA
M5, 6 and 7 ask the entity to prove the negative. This type of evidence is problematic, and may result in nothing better than the entity
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making an attestation that the event did not occur, thus this measure is not useful. With well over 100,000 miles of transmission covered
by this standard, even six-sigma performance would result in vegetation related issues. It is unreasonable to expect zero-tolerance for
vegetation events and unnecessary for the industry (and customers) to expend resources to attempt to meet this level of compliance
when the transmission system is planned and operated to handle any single contingency, which means that a vegetation contact should
not, in isolation, cause a major problem to the bulk power system. This standard needs work to make it clear, unambiguous, feasible and
enforceable.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment.
The SDT pursued an approach to develop a metric that would not have a zero-tolerance for outages. Discussion with FERC led the SDT to the
conclusion that such an approach would not be acceptable.
Changes made to the old M5, M6 and M7 in this new draft should alleviate the “prove a negative” dilemma.
Independent Electricity
System Operator
We recommend removing the Transmission Owner as the one to define a major storm, this task should be left to an applicable regulatory
body only, for consistency in assessing such an event. Also, we recommend footnote #5 specify that planned removal of vegetation by
the utility is not part of the exceptions, because in our view this activity is a component of the vegetation management program and that
outages should be preventable. There is a typo in R6. The numeral "4" should be superscripted.
Response: The SDT thanks you for your comments. Significant changes have been made to the current draft of the Standard based upon substantive
industry comment
The SDT has reviewed the data on vegetation related outages that TO have reported on the NERC website. There are 223 reports of outages in that data
covering the period January 2004 to March 2009. The associated documentation with these events indicate that TO are supplying supportive
information to indicate that the level of any disaster exclusion (including major storms) is sufficient to reasonably identify conditions that exceed
design criteria. Further specific on the threshold for each disaster (or storm) would not ensure that weather data would be adequate to support each
location/situation.
Random human error in felling trees whether by loggers, homeowners or vegetation removal crews has not been associated with cascading events and
remains a valid exclusion. The related safety risks and equipment damages tend to effectively self-control this type of activity.
The typographical error in what was R6 (now R7) has been corrected.
Salt River Project
We question the method used in determining the clearance distances for Vegetation near Transmission Lines. First is the use of the
Gallet Equation. Although the Gallet Equation is more definitive than using IEEE 516 as identified in the current standard, we have
questions from an engineering prespective as to how and why this method was chosen for vegetation management. It is stated in the
Technical Reference paper that the Gallet Equation is a well known method of computing the required strike distance for proper
insulation coordination. It is our understanding it's purpose is for designing towers, to define the "tower window" or opening inside of a
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tower under normal conditions. Because this is not a method designed specifically for vegetation management, what is the basis for
applying this to vegetation management? Was there, or could there be testing done? We would find it definitive to substantiate the
calculated equation assertions with test data from actual energized flashover distances to vegetation. The testing ought to include dry
and misting conditions at 200+ kilovolt levels on a sampling of fresh cut common vegetation types. Reputable EHV testing facilities
where such tests can be performed exist within the United States and Canada. Is there additional information to clarify why this method
was used to help establish clearance distances for vegetation near transmission lines? Second, it is expected that each utility needs to
define their "Critical Clearance Zone". It is outlined in the Technical Reference document how complicated it is to define this clearance
area. As the conductor moves throughout its "flight path", the minimum clearance shell surrounding the conductor moves along with it.
The shape and size of the Critical Clearance Zone around the conductors is irregular and will change depending on where a conductor
segment is located within the span. At mid-span, where the potential for conductor movement is the greatest due to sag and wind
deflection, the corresponding Critical Clearance Zone is also the largest and most irregular. With the size, shape, and area of the Critical
Clearance Zone dramatically changing as one progresses along a span, identifying the precise location and boundary of the Critical
Clearance Zone around the conductor in the field becomes very problematic. There are many variables that are involved at any point
along a line and at any given time (loading, operating temperature, wind, maximum design rating, maximum operating loading and so
on). Therefore, even if the exact size and shape of the Critical Clearance Zone is known, it becomes nearly impossible to field correlate
and accurately "superimpose" the Critical Clearance Zone" around the conductor. Therefore, it seems unreasonable to expect each
utility to develop and implement a defensible and auditable clearance zone.
We strongly support the development of the Technical Reference document. This would have been helpful if it was available for the first
version, as it will help both utilities and auditors. We recommend that this be included in the revised version and subsequent future
revisions. Please note that as FAC-003-2 goes through additional revisions prior to finalization, the Technical Reference document
needs to be revised to reflect the final revisions prior to implementation.
Response: The SDT thanks you for your comments. The SDT engaged TO personnel who were technical experts with significant experience and
credentials in transmission line insulation coordination theory and applications. The purpose of the change to the Gallet derived distances was to
provide a set of specific distances that would ensure that flashover would not occur provided those distances were not breeched under expected
outdoor operating conditions. These distances are applicable to the wire with respect to structure components, vegetation or any other object at
ground potential level. These values have already been proven for dry and wet conditions and need no further testing.
We have made changes in R2 and R4 that should remove the problems you have raised regarding the CCZ and how it is “nearly impossible” to apply
under field conditions.
Northeast Utilities
In section 4.2.2. the time period for bringing sub 200-kV lines into compliance with the standard states a 12 month period following the
designation of the lower voltage lines by the Reliability Coordinator. This can present problems if the RC designates the lines during the
course of a plan year, because budgets may not have been established or funded for the additional work. It is suggested that the time
period be revised to state, "by the end of the following calendar or budget year after the designation of lower voltage lines", allowing for a
full calendar/budget year that can be planned and budgeted to bring lines into compliance.
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There is concern over the use of the Critical Clearance Zone and making this the "bright line" where encroachment at any time under
any conditions is a violation of the standard. The Critical Clearance Zone is a very detailed and calculated zone. It is improbable that
an accurate determination of the Critical Clearance Zone could be made in the field. Mere encroachment should not constitute a
violation. If the encorachment can be determined and corrected once found - this should be an acceptable practice. It is reasonable for
utilities to spend the time, money and manpower to actively manage rights-of-way, and dealing with encroachment issues which can be
identified. Many potential encroachments will not be identifiable unless one can accurately identify the Critical Clearance Zone in all
cases in all areas at all times. Also, there is some concern over how the requirements are set up for violations of the Critical Clearance
Zone and for sustained outages. A sustained outage due to vegetation within the active transmission right-of-way is a violation under
R.5, R.6 and R.7. It is also possible that the outage is a violation of the Critical Clearance Zone under R.4. The standard implies that a
utility could be assessed multiple violations of the standard for one outage with multiple penalties. Is this the desired intent?
Finally, version 1 had clear requirements on what was to be reported, when the reports were required, and who was to submit reports. Is
it intended that the standard rely solely on self-reports? Version 2 makes no mention of what is to be reported when a violation occurs,
or of any other reports. Is reporting going to be left up to the Regional Entity to establish?
Response: The SDT thanks you for your comments.
The standard was revised to replace the Reliability Coordinator with the Planning Coordinator as the entity responsible for identifying lines sub 200 kV
for which there should be a TVMP. By moving to the Planning Coordinator, there should be ample time to address the annual work plan. With its focus
on “planning horizon” issues (> 1 year), the PC provides the necessary look-ahead that the RC did not. As soon as a sub-200 kV line is designated as
being applicable to this standard, it is understood the subject line could potentially place the grid at risk of instability, separation or cascading. A 12
month period to perform any vegetation maintenance seems reasonable to the SDT.
Significant changes have been made to the current draft of the Standard based upon substantive industry comment. Items such as the CCZ concept
has been replaced with the concept of minimum clearance distances, and Transmission Owners are required to prevent encroachment of vegetation
into minimum vegetation clearances distances as observed in real time. Reporting requirements have been addressed in the compliance section of the
revised Standard.
Hydro-Quebec
Transenergie (HQT)
HQT recommends that the Standard Drafting Team review the compliance and reporting requirements for consistency and adequacy.
Applicability 4.2.3 contradict first part of Applicability 4.2.1 and that of former Applicability 4.3
Response: The SDT thanks you for your comments. The SDT reviewed your concern and did not see a contradiction.
BCTC
Any standard that is developed should not contain advisory-type language—it should be declarative in tone. For example, in R1.4, the
ending clause that begins “…and may include actions…” should be removed because it is advisory in nature. The suggested actions are
not even the responsibility of the vegetation management program.
BCTC supports the development of this white paper as a way to help ensure consistent interpretation of the standard. Perhaps the lack
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Comments on 1st Draft of FAC-003-2 — Transmission Vegetation Management Program — Project 2007-07
Organization
Question 18 Comment
of such a paper in the first version of the standard contributed to the varying interpretations by the auditors. The utilities understand
however that this document is not a legal document and is not binding.
Response: The SDT thanks you for your comments. R1.4 has been changed to remove the advisory type language.
September 8, 2009
259
FAC-003-2 — Transmission Vegetation Management Program
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and
will be removed when the standard becomes effective.
Development Steps Completed:
1. SC approved SAR for initial posting (January 11, 2007).
2. SAR posted for comment (January 15–February 14, 2007).
3. SAR posted for comment (April 10–May 9, 2007).
4. SC authorized moving the SAR forward to standard development (June 27, 2007).
Proposed Action Plan and Description of Current Draft:
This is the second posting of the proposed revisions to the requirements and measures in the
standard. The drafting team added compliance elements to the standard and requests posting
for a 45-day comment period.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Drafting team considers comments, makes conforming
changes, posts for 45-day second comment period.
August 2009
2. Drafting team considers comments, makes conforming
changes, posts for 30-day third comment period.
February 2010
3. Drafting team considers comments, makes conforming
changes, and requests SC approval to proceed to pre-ballot
comment period.
April 2010
4. First ballot of standards.
May 2010
5. Recirculation ballot of standards.
June 2010
6. Board adopts standards.
August 2010
Draft 2: September 8, 2009
Page 1 of 15
FAC-003-2 — Transmission Vegetation Management Program
Definitions of Terms Used in Standard+
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Active Transmission Line Right of Way — A strip of land that is occupied by active
transmission facilities. This corridor does not include the inactive or unused part of the Right
of Way intended for other facilities.
Vegetation Inspection — The systematic examination of vegetation conditions on an Active
Transmission Line Right of Way. This inspection may be combined with a general line
inspection. The inspection includes the documentation of any vegetation that may pose a threat
to reliability prior to the next planned inspection or maintenance work, considering the current
location of the conductor and other possible locations of the conductor due to sag and sway for
rated conditions.
Draft 2: September 8, 2009
Page 2 of 15
FAC-003-2 — Transmission Vegetation Management Program
A. Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number: FAC-003-2
3.
Purpose: To improve the reliability of the electric transmission system by
preventing those vegetation related outages that could lead to Cascading.
4.
Applicability:
4.1 Functional Entities:
4.1.1
Transmission Owner
4.1.2
Planning Coordinator
4.2 Facilities:
5.
4.2.1
Transmission lines (“applicable lines”) operated at 200kV or higher,
and transmission lines operated below 200kV designated by the
Planning Coordinator as being subject to this standard including but
not limited to those that cross lands owned by federal1, state,
provincial, public, private, or tribal entities.
4.2.2
Transmission lines operated below 200kV designated by the
Planning Coordinator as being subject to this standard become
subject to this standard 12 months after the date the Planning
Coordinator initially designates the transmission line as being
subject to this standard.
4.2.3
Existing transmission lines operated at 200kV or higher which are
newly acquired by a Transmission Owner and were not previously
subject to this standard, become subject to this standard 12 months
after the acquisition date of the transmission lines.
Effective Dates:
In those jurisdictions where regulatory approval is required, the first calendar day of
the first calendar quarter one year after applicable regulatory authority approval for
all requirements; or, in those jurisdictions where no regulatory approval is required,
the first calendar day of the first calendar quarter one year following Board of
Trustees adoption.
1
EPAct 2005 section 1211c: “Access approvals by Federal agencies”
Draft 2: September 8, 2009
Page 3 of 15
FAC-003-2 — Transmission Vegetation Management Program
B. Requirements
R1. Each Transmission Owner shall have a documented transmission vegetation
management program that describes how it conducts work on its Active
Transmission Line Rights of Way to prevent Sustained Outages due to
vegetation, considering all possible locations the conductor may occupy under
the effects of sag and sway throughout its operating range under rated
conditions. The transmission vegetation management program shall: [Violation
Risk Factor — Lower][Time Horizon — Long-term planning]
1.1.
Specify the methods that the Transmission Owner may use to control
vegetation.2
1.2.
Specify a Vegetation Inspection frequency of at least once per calendar
year that takes into account local3 and environmental factors.
1.3.
Require an annual work plan. An annual work plan shall:
1.3.1. Identify the applicable lines to be maintained.
1.3.2. Identify the work to be performed and methods to be used.
1.3.3. Be flexible to adjust to changing conditions and to findings from
Vegetation Inspections. Adjustments to the plan within the year
are permissible.
1.3.4. Take into consideration permitting and scheduling requirements
from landowners or regulatory authorities.
1.4.
Require a process or procedure for response to an imminent threat of a
vegetation-related Sustained Outage. The process or procedure shall
specify actions which shall include communication of the threat to the
responsible control center.
1.5.
Specify an interim corrective action process for use when the
Transmission Owner is temporarily constrained from performing
vegetation maintenance as planned.
1.6.
Specify the maintenance strategies used (such as minimum vegetationto-conductor distance or maximum vegetation height) to ensure that
Table 1 clearances in Attachment 1 are never violated. The maintenance
strategies shall consider the sag and sway of the conductor throughout its
operating range under rated conditions.
R2. Each Transmission Owner shall implement its imminent threat process or
procedure when the Transmission Owner has actual knowledge of such a threat,
2
ANSI A300, Tree Care Operations — Tree, Shrub, and Other Woody Plant Maintenance — Standard Practices,
while not a requirement of this standard, is considered to be an industry best practice.
3
Local factors include items such as treatment cycle, extent and type of treatment, and their relationship to the
normal growth rate.
Draft 2: September 8, 2009
Page 4 of 15
FAC-003-2 — Transmission Vegetation Management Program
obtained through normal operating practices. [Violation Risk Factor —
Medium][Time Horizon — Real Time]
R3. Each Transmission Owner shall conduct Vegetation Inspections of all
applicable lines (as measured in line miles) in accordance with the frequency
specified in its transmission vegetation management program, unless
constrained by natural disasters4. When constrained by a natural disaster, the
Transmission Owner shall conduct the Vegetation Inspection(s) within six
months or a period agreed to by its Regional Entity, whichever is greater.
[Violation Risk Factor — Medium][Time Horizon — Operations Planning]
R4. Each Transmission Owner shall prevent encroachment of vegetation into the
Minimum Vegetation Clearance Distances (MVCD) listed in FAC-003-2 Attachment 1 for its applicable lines as observed in real-time operating between
no-load and their Rating, with the following exceptions: [Violation Risk Factor
— Medium][Time Horizon — Real Time]
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting
from natural disasters.4
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting
from human or animal activity.5
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting
from falling vegetation.
R5. Each Transmission Owner shall prevent Sustained Outages6 of applicable lines
that are identified as an element of an Interconnection Reliability Operating
Limit (IROL) (or Major WECC Transfer Path) due to vegetation growing into a
conductor operating between no-load and its Rating, with the following
exceptions: [Violation Risk Factor — High][Time Horizon — Real Time]
Sustained Outages of applicable lines that result from natural disasters.4
Sustained Outages of applicable lines that result from human or animal
activity.5
R6. Each Transmission Owner shall prevent Sustained Outages6 of applicable lines
that are not an element of an IROL (or major WECC Transfer Path) due to
vegetation growing into a conductor operating between no-load and its Rating,
with the following exceptions: [Violation Risk Factor — Medium][Time
Horizon — Real Time]
Sustained Outages of applicable lines that result from natural disasters.4
4
Examples include, but are not limited to, earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh
gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice storms, and
floods.
5
Examples include, but are not limited to, logging, animal severing tree, vehicle contact with tree, arboricultural
activities or horticultural or agricultural activities, or removal or digging of vegetation.
6
Multiple Sustained Outages on an individual line, if caused by the same vegetation, shall be considered as one
outage regardless of the actual number of outages within a 24-hour period.
Draft 2: September 8, 2009
Page 5 of 15
FAC-003-2 — Transmission Vegetation Management Program
Sustained Outages of applicable lines that result from human or animal
activity.5
R7. Each Transmission Owner shall prevent Sustained Outages6 of applicable lines
due to the blowing together of vegetation and a conductor within an Active
Transmission Line Right of Way (operating within design blow-out conditions)
with the following exception: [Violation Risk Factor — Medium][Time Horizon
— Real Time]
Sustained Outages of applicable lines that result from natural disasters4 or
wind-blown debris.
R8. Each Transmission Owner shall prevent Sustained Outages6 of applicable lines
due to vegetation falling into a conductor from within an Active Transmission
Line Right of Way with the following exceptions: [Violation Risk Factor —
Medium] [Time Horizon — Real Time]
Sustained Outages of applicable lines that result from natural disasters4 or
wind-blown debris.
Sustained Outages of applicable lines that result from human or animal
activity.5
R9. Each Transmission Owner shall implement its annual work plan for vegetation
management to accomplish the purpose of this standard. [Violation Risk Factor
— Medium] [Time Horizon — Operations Planning]
R10. Each Planning Coordinator shall prepare and review annually, a list of lines that
are operated below 200kV, if any, which are subject to this standard. Each
Planning Coordinator shall consult with its Transmission Owner(s) and
neighboring Planning Coordinators to obtain input to develop the list.
[Violation Risk Factor — Lower] [Time Horizon — Long-term Planning]
R11. Each Planning Coordinator shall develop and document its method for
assessing the reliability significance of sub-200kV transmission lines whose
loss would place the grid at an unacceptable risk of instability, separation, or
cascading failures. [Violation Risk Factor — Lower] [Time Horizon — Longterm Planning]
C. Measures
M1. The Transmission Owner has a documented transmission vegetation management
program (paper or electronic copy of dated, current, in force document with specified
elements) that describes how it conducts work on its Active Transmission Line
Rights of Way to prevent Sustained Outages due to vegetation, considering all
possible locations the conductor may occupy under the effects of sag and sway
throughout its operating range under rated conditions. (R1)
1.1. The Transmission Owner’s transmission vegetation management program
documentation specifies the methods that the Transmission Owner may use to
control vegetation.
Draft 2: September 8, 2009
Page 6 of 15
FAC-003-2 — Transmission Vegetation Management Program
1.2. The Transmission Owner’s transmission vegetation management program
documentation specifies a Vegetation Inspection frequency of at least once per
calendar year that takes into account local and environmental factors.
1.3. The Transmission Owner’s transmission vegetation management program
contains an annual work plan which:
1.3.1. Identifies the applicable lines to be maintained
1.3.2. Identifies the work to be performed and the methods used
1.3.3. Shows flexibility to adjust to changing conditions and to findings from
Vegetation Inspections
1.3.4. Considers permitting and scheduling requirements from landowners or
regulatory authorities.
1.4. The Transmission Owner’s transmission vegetation management program
documentation specifies an imminent threat process or procedure for responding
to imminent threats of a vegetation-related Sustained Outage including
communication of the threat to the responsible control center.
1.5. The Transmission Owner’s transmission vegetation management program
documentation specifies the interim corrective action process for use when the
Transmission Owner is temporarily constrained from performing vegetation
maintenance as planned.
1.6. The Transmission Owner’s transmission vegetation management program
documentation specifies the maintenance strategies used (such as minimum
vegetation-to-conductor distance or maximum vegetation height) to ensure that
Table 1 clearances in Attachment 1 are never violated. The maintenance
strategies consider the sag and sway of the conductor throughout its operating
range under rated conditions.
M2. The Transmission Owner has evidence of the implementation of its vegetation
imminent threat process or procedure showing what was done with dates and
activities accomplished. (R2)
M3. The Transmission Owner has evidence that it conducted Vegetation Inspections in
accordance with Requirement R3.
M4. The Transmission Owner has evidence from inspections that indicate there was no
vegetation encroachment into the Minimum Vegetation Clearance Distances listed in
FAC-003-2-Attachment 1 for its applicable lines as observed in real-time operating
between no-load and their Rating, considering exceptions. (R4)
M5. The Transmission Owner’s self-certification reports are adequate evidence of no
Sustained Outage of any applicable line that is identified as an element of an IROL
(or Major WECC Transfer Path) due to vegetation growing into a conductor
operating between no-load and its Rating. (R5)
M6. The Transmission Owner’s self-certification reports are adequate evidence of no
Sustained Outage of any applicable line that is not identified as an element of an
IROL (or Major WECC Transfer Path) due to vegetation growing into a conductor
operating between no-load and its Rating. (R6)
Draft 2: September 8, 2009
Page 7 of 15
FAC-003-2 — Transmission Vegetation Management Program
M7. The Transmission Owner’s self-certification reports are adequate evidence of no
Sustained Outage of any applicable line due to the blowing together of vegetation
and a conductor within the Active Transmission Line Right of Way. (R7)
M8. The Transmission Owner’s self-certification reports are adequate evidence of no
Sustained Outage of any applicable line due to vegetation falling into a conductor
from within the Active Transmission Line Right of Way. (R8)
M9. The Transmission Owner has evidence that it is implementing, or has implemented,
its annual work plan. An example of evidence is a paper or electronic copy of work
plan and work records. (R9)
M10. The Planning Coordinator has evidence that it consulted with its Transmission
Owner(s) and neighboring Planning Coordinator(s), prepared and reviewed annually
a list of designated sub-200kV transmission lines, if any, which are subject to this
standard. (R10)
M11. The Planning Coordinator has documented evidence such as planning study criteria
or other analysis used to develop its method for assessing the reliability significance
of sub-200kV lines whose loss would place the grid at an unacceptable risk of
instability, separation, or cascading failures. (R11)
D. Compliance
1.
Compliance Monitoring Process
1.1 Compliance Enforcement Authority
Regional Entity
1.2
Compliance Monitoring Period and Reset Timeframe
Not Applicable
1.3
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
Periodic Data Submittals for Sustained Outages caused by vegetation
1.4 Data Retention
The Transmission Owner and Planning Coordinator shall keep data or evidence
to show compliance as identified below unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation:
Draft 2: September 8, 2009
Page 8 of 15
FAC-003-2 — Transmission Vegetation Management Program
The Transmission Owner shall retain as evidence of Requirements 1
through 9, Measures 1 through 9 for three years.
The Planning Coordinator shall retain evidence of Requirement 10
and 11, Measure 10 and 11 for one year.
If a Transmission Owner or Planning Coordinator is found non-compliant, it
shall keep information related to the non-compliance until found compliant.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.5 Additional Compliance Information
The Transmission Owner shall report quarterly to its Regional Entity, or the
Regional Entity’s designee, Sustained Outages of its transmission lines
determined by the Transmission Owner to have been caused by vegetation,
including the following:
The name of the circuit(s), the date, time and duration of the outage; a
description of the cause of the outage; other pertinent comments; and any
countermeasures taken by the Transmission Owner, and Sustained Outage
Category based on the following:
7
Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines that are identified as an element of an
IROL (or Major WECC Transfer Path) by vegetation inside and/or
outside of the Active Transmission Line ROW;
Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines but are not identified as an element of an
IROL (or Major WECC Transfer Path) by vegetation inside and/or
outside of the Active Transmission Line ROW;
Category 2 — Fall-ins: Sustained Outages caused by vegetation falling
into lines from within the Active Transmission Line ROW;
Category7 4 — Blowing together: Sustained Outages caused by
vegetation and lines blowing together from within the Active
Transmission Line ROW.
Category 3 reporting is eliminated.
Draft 2: September 8, 2009
Page 9 of 15
FAC-003-2 — Transmission Vegetation Management Program
Violation Severity Levels
R#
Violation
Risk Factor
R1
Lower
R2
Medium
R3
Medium
R4
Medium
Draft 2: September 8, 2009
Violation Severity Level
Lower
The Transmission Owner
has a transmission
vegetation management
program, but the
transmission vegetation
management program is
missing one of the
following:
Requirement 1, Part 1.1, or
Requirement 1, Part 1.2
Moderate
The Transmission Owner
has a transmission
vegetation management
program, but the
transmission vegetation
management program is
missing either Requirement
R1, Part 1.5 or
Requirement R1, Part 1.1
and Part 1.2
High
The Transmission Owner has a
transmission vegetation
management program, but the
transmission vegetation
management program is
missing up to two of the
following parts of
Requirement R1:
Parts 1.3, 1.4 and 1.6
Severe
The Transmission Owner
does not have transmission
vegetation management
program or the transmission
vegetation management
program is missing all of the
following Parts of
Requirement R1:
Parts 1.3, 1.4 and 1.6
The Transmission Owner did
not implement its imminent
threat process or procedure
when the Transmission
Owner had actual knowledge
of such a threat, obtained
through normal operating
practices
The Transmission Owner
inspected greater than 75%
but less than 100% of the
total line miles specified by
its transmission vegetation
management program.
The Transmission Owner
inspected greater than 50%
but less than or equal to
75% of the total line miles
specified by its
transmission vegetation
management program.
The Transmission Owner
inspected greater than 25% but
less than or equal to 50% of
the total line miles specified
by its transmission vegetation
management program.
The Transmission Owner
inspected less than or equal
to 25% of the total line miles
specified by its transmission
vegetation management
program.
The Transmission Owner has
failed to prevent vegetation
from encroaching into the
minimum vegetation
clearance distance.
Page 10 of 15
FAC-003-2 — Transmission Vegetation Management Program
R#
Violation
Risk Factor
Violation Severity Level
Lower
Moderate
High
Severe
R5
High
The Transmission Owner
incurred a Sustained Outage
due to vegetation growing
into an applicable
transmission line that is
identified as an element of an
IROL (or Major WECC
Transfer Path).
R6
Medium
The Transmission Owner
incurred a Sustained Outage
due to vegetation growing
into an applicable
transmission line that is not
identified as an element of an
IROL (or Major WECC
Transfer Path).
R7
Medium
The Transmission Owner
incurred a Sustained Outage
due to the blowing together
of vegetation and a
conductor of an applicable
transmission within an
Active Transmission Line
Right of Way.
R8
Medium
The Transmission Owner
incurred a Sustained Outage
due to vegetation falling into
an applicable transmission
from within an Active
Transmission Line Right of
Way.
R9
Medium
Draft 2: September 8, 2009
The Transmission Owner
failed to implement 5% or
less of its annual work
The Transmission Owner
failed to implement more
than 5% but less than or
The Transmission Owner
failed to implement more than
10% but less than or equal to
Page 11 of 15
The Transmission Owner
failed to implement more
than 15% of its annual work
FAC-003-2 — Transmission Vegetation Management Program
R#
Violation Severity Level
Violation
Risk Factor
Lower
plan.
Moderate
equal to 10% of its annual
work plan.
High
15% of its annual work plan.
Severe
plan.
R10
Lower
The Planning Coordinator
failed to consult with one
of its Transmission Owners
or one of its adjacent
Planning Coordinators in
developing its list of
designated sub-200kV
transmission lines, if any,
that are subject to this
standard..
The Planning Coordinator
failed to consult with more
than one of its
Transmission Owners or
more than one of its
adjacent Planning
Coordinators in developing
its list of designated sub200kV transmission lines,
if any, that are subject to
this standard.
The Planning Coordinator has
not annually reviewed its list
of designated sub-200kV
transmission lines, if any, that
are subject to this standard.
The Planning Coordinator
has not prepared a list of
designated sub-200kV
transmission lines, if any,
that are subject to this
standard.
R11
Lower
The Planning Coordinator
has not documented its
method for assessing the
reliability significance of
sub-200kV lines.
The Planning Coordinator
has not considered lines
whose loss would place the
grid at an unacceptable risk
of instability, separation, or
cascading failures in
developing its method for
assessing the reliability
significance of sub-200kV
lines.
NA
The Planning Coordinator
has not developed a method
for assessing the reliability
significance of sub-200kV
lines.
Draft 2: September 8, 2009
Page 12 of 15
FAC-003-2 — Transmission Vegetation Management Program
Regional Variances
None identified.
Associated Technical Reference Documents
FAC-003 Reference — Transmission Vegetation Management — White Paper.
Version History
Version
Date
Action
Change Tracking
1
TBA
1. Added “Standard Development Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section A, 5.2.
3. Added “Proposed Effective Date: April 7, 2006” to
footer.
4. Added “Draft 3: November 17, 2005” to footer.
1
April 4, 2007
2
Draft 2: September 8, 2009
Regulatory Approval — Effective Date
New
Complete revision
Page 13 of 15
FAC-003-2-Attachment 1
TABLE 1 — Minimum Vegetation Clearance Distances (MVCD)
For Alternating Current Voltages
( AC )
( AC )
Nominal
System
Maximum
System
Voltage
(kV)
Voltage
(kV)
MVCD
feet
(meters)
MVCD
feet
(meters)
MVCD
feet
(meters)
MVCD
feet
(meters)
MVCD
feet
(meters)
MVCD
feet
(meters)
MVCD
feet
(meters)
MVCD
feet
(meters)
MVCD
feet
(meters)
MVCD
feet
(meters)
sea level
3,000ft
(914.4m)
4,000ft
(1219.2m)
5,000ft
(1524m)
6,000ft
(1828.8m)
7,000ft
(2133.6m)
8,000ft
(2438.4m)
9,000ft
(2743.2m)
10,000ft
(3048m)
11,000ft
(3352.8m)
765
800
8.06ft
(2.46m)
8.89ft
(2.71m)
9.17ft
(2.80m)
9.45ft
(2.88m)
9.73ft
(2.97m)
10.01ft
(3.05m)
10.29ft
(3.14m)
10.57ft
(3.22m)
10.85ft
(3.31m)
11.13ft
(3.39m)
500
550
5.06ft
(1.54m)
5.66ft
(1.73m)
5.86ft
(1.79m)
6.07ft
(1.85m)
6.28ft
(1.91m)
6.49ft
(1.98m)
6.7ft
(2.04m)
6.92ft
(2.11m)
7.13ft
(2.17m)
7.35ft
(2.24m)
345
362
3.12ft
(0.95m)
3.53ft
(1.08m)
3.67ft
(1.12m)
3.82ft
(1.16m)
3.97ft
(1.21m)
4.12ft
(1.26m)
4.27ft
(1.30m)
4.43ft
(1.35m)
4.58ft
(1.40m)
4.74ft
(1.44m)
230
242
2.97ft
(0.91m)
3.36ft
(1.02m)
3.49ft
(1.06m)
3.63ft
(1.11m)
3.78ft
(1.15m)
3.92ft
(1.19m)
4.07ft
(1.24m)
4.22ft
(1.29m)
4.37ft
(1.33m)
4.53ft
(1.38m)
161*
169
2ft
(0.61m)
2.28ft
(0.69m)
2.38ft
(0.73m)
2.48ft
(0.76m)
2.58ft
(0.79m)
2.69ft
(0.82m)
2.8ft
(0.85m)
2.91ft
(0.89m)
3.03ft
(0.92m)
3.14ft
(0.96m)
138*
145
1.7ft
(0.52m)
1.94ft
(0.59m)
2.03ft
(0.62m)
2.12ft
(0.65m)
2.21ft
(0.67m)
2.3ft
(0.70m)
2.4ft
(0.73m)
2.49ft
(0.76m)
2.59ft
(0.79m)
2.7ft
(0.82m)
115*
121
1.41ft
(0.43m)
1.61ft
(0.49m)
1.68ft
(0.51m)
1.75ft
(0.53m)
1.83ft
(0.56m)
1.91ft
(0.58m)
1.99ft
(0.61m)
2.07ft
(0.63m)
2.16ft
(0.66m)
2.25ft
(0.69m)
88*
100
1.15ft
(0.35m)
1.32ft
(0.40m)
1.38ft
(0.42m)
1.44ft
(0.44m)
1.5ft
(0.46m)
1.57ft
(0.48m)
1.64ft
(0.50m)
1.71ft
(0.52m)
1.78ft
(0.54m)
1.86ft
(0.57m)
69*
72
0.82ft
(0.25m)
0.94ft
(0.29m)
0.99ft
(0.30m)
1.03ft
(0.31m)
1.08ft
(0.33m)
1.13ft
(0.34m)
1.18ft
(0.36m)
1.23ft
(0.37m)
1.28ft
(0.39m)
1.34ft
(0.41m)
*As designated by the Planning Coordinator
Draft 2: September 8, 2009
Page 14 of 15
TABLE 1 (CONT.) — Minimum Vegetation Clearance Distances (MVCD) For Direct Current Voltages
( DC )
Nominal Pole
to Ground
Voltage
(kV)
MVCD feet
(meters)
sea level
MVCD feet
(meters)
3,000ft
(914.4m)
Alt.
MVCD feet
(meters)
4,000ft
(1219.2m)
Alt.
MVCD
feet
(meters)
5,000ft
(1524m)
Alt.
MVCD feet
(meters)
6,000ft
(1828.8m)
Alt.
MVCD
feet
(meters)
7,000ft
(2133.6m)
Alt.
MVCD
feet
(meters)
(8,000ft
(2438.4m)
Alt.
MVCD
feet
(meters)
9,000ft
(2743.2m)
Alt.
MVCD
feet
(meters)
10,000ft
(3048m)
Alt.
MVCD
feet
(meters)
11,000ft
(3352.8m)
Alt.
±750
13.92ft
(4.24m)
15.07ft
(4.59m)
15.45ft
(4.71m)
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.9ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
±600
10.07ft
(3.07m)
11.04ft
(3.36m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
(13.54ft
4.13m)
±500
7.89ft
(2.40m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
±400
4.78ft
(1.46m)
5.35ft
(1.63m)
5.55ft
(1.69m)
5.75ft
(1.75m)
5.95ft
(1.81m)
6.15ft
(1.87m)
6.36ft
(1.94m)
6.57ft
(2.00m)
6.77ft
(2.06m)
6.98ft
(2.13m)
±250
3.43ft
(1.05m)
4.02ft
(1.23m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5ft
(1.52m)
5.17ft
(1.58m)
Draft 2: September 8, 2009
Page 15 of 15
FAC-003-2 — Transmission Vegetation Management Program
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and
will be removed when the standard becomes effective.
Development Steps Completed:
1. SC approved SAR for initial posting (January 11, 2007).
2. SAR posted for comment (January 15–February 14, 2007).
3. SAR posted for comment (April 10–May 9, 2007).
4. SC authorized moving the SAR forward to standard development (June 27, 2007).
Proposed Action Plan and Description of Current Draft:
This is the second posting of the proposed revisions to the requirements and measures in the
standard. The drafting team added compliance elements to the standard and requests posting
for a 45-day comment period.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Drafting team considers comments, makes conforming
changes, posts for 45-day second comment period.
August 2009
2. Drafting team considers comments, makes conforming
changes, posts for 30-day third comment period.
February 2010
3. Drafting team considers comments, makes conforming
changes, and requests SC approval to proceed to pre-ballot
comment period.
April 2010
4. First ballot of standards.
May 2010
5. Recirculation ballot of standards.
June 2010
6. Board adopts standards.
August 2010
Draft 2: September 8, 2009
Page 1 of 20
FAC-003-2 — Transmission Vegetation Management Program
Definitions of Terms Used in Standard+
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Active Transmission Line Right of Way — A strip of land that is occupied by active
transmission facilities. This corridor does not include the inactive or unused part of the Right
of Way intended for other facilities.
Critical Clearance Zone — The area mapped by the radial distance around a conductor
specified in Table I of Attachment 1 to reliability standard FAC-003-2 — Transmission
Vegetation Management Program when the conductor is energized and operating between noload and its Rating, including the design blowout, however, the zone shall not extend beyond
the limitsInspection — The systematic examination of thevegetation conditions on an Active
Transmission Line Right of Way. This inspection may be combined with a general line
inspection. The inspection includes the documentation of any vegetation that may pose a threat
to reliability prior to the next planned inspection or maintenance work, considering the current
location of the conductor and other possible locations of the conductor due to sag and sway for
rated conditions.
Draft 2: September 8, 2009
Page 2 of 20
FAC-003-2 — Transmission Vegetation Management Program
A. Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number: FAC-003-2
3.
Purpose: To improve the reliability of the Bulk Electric Systemelectric
transmission system by preventing those vegetation related outages that could lead
to Cascading.
4.
Applicability:
Functional Entities:
Transmission Owner
ReliabilityPlanning Coordinator
Facilities:
5.
Transmission lines (“applicable lines”) operated at 200kV or higher, and
transmission lines operated below 200kV designated by the ReliabilityPlanning
Coordinator as being subject to this standard including but not limited to those
that cross lands owned by federal1, state, provincial, public, private, or tribal
entities.
Transmission lines operated below 200kV designated by the ReliabilityPlanning
Coordinator as being subject to this standard become subject to this standard 12
months after the date the ReliabilityPlanning Coordinator initially designates the
transmission line as being subject to this standard.
Existing transmission lines operated at 200kV or higher which are newly
acquired by a Transmission Owner and were not previously subject to this
standard, become subject to this standard 12 months after the acquisition date of
the transmission liness.
Effective Dates:
In those jurisdictions where regulatory approval is required, the first calendar day of
the first calendar quarter one year after applicable regulatory authority approval for
all requirements; or, in those jurisdictions where no regulatory approval is required,
the first calendar day of the first calendar quarter one year following Board of
Trustees adoption.
1
EPAct 2005 section 1211c: “Access approvals by Federal agencies” ”
Draft 2: September 8, 2009
Page 3 of 20
FAC-003-2 — Transmission Vegetation Management Program
B. Requirements
R1.
Each Transmission Owner shall have a documented transmission vegetation
management program designed to control vegetation that describes how it
conducts work on its Active Transmission Lines’ Line Rights of Way to
prevent Sustained Outages due to vegetation, considering all possible locations
the conductor may occupy under the effects of sag and sway throughout its
operating range under rated conditions. The transmission vegetation
management program shall: [Violation Risk Factor – Lower][Time Horizon –
Long-term planning]
1.1.
Specify the methodologies methods that the Transmission Owner uses
may use to control vegetation. 2
1.2.
Specify a vegetation inspectionVegetation Inspection frequency of at
least once per calendar year that takes into account local 3 and
environmental factors.
1.3.
Require an annual work plan that identifies. An annual work plan shall:
1.3.1. Identify the applicable lines to be maintained and associated
1.3.2. Identify the work to be performed during the year. It shall and
methods to be used
1.3.3. Be flexible to adjust to changing conditions and to findings from
vegetation inspections.Vegetation Inspections. Adjustments to
the plan within the year are permissible. The plan shall
1.3.4. Take into consideration permitting and scheduling requirements
from landowners or regulatory authorities. It shall support the
objectives of the transmission vegetation management program
and use the methodologies outlined in the transmission
vegetation management program.
1.4.
Require a process or procedure for response to an imminent threats
threat of a vegetation -related Sustained Outage. The process or
procedure shall specify actions which shall include immediate
communication of the threat to the Transmission Operator, and may
include actions such as a temporary reduction in line Rating, switching
lines out of service, or other actions.responsible control center.
1.5.
Specify an interim corrective action process for use when the
Transmission Owner is temporarily constrained from performing
vegetation maintenance as planned.
2
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices,
while not a requirement of this standard, is considered to be an industry best practice.
3
Local factors include items such as treatment cycle, extent and type of treatment, and their relationship to the
normal growth rate.
Draft 2: September 8, 2009
Page 4 of 20
FAC-003-2 — Transmission Vegetation Management Program
1.6.
Specify the maintenance strategies used (such as minimum vegetationto-conductor distance or maximum vegetation height) to ensure that
Table 1 clearances in Attachment 1 are never violated. The maintenance
strategies shall consider the sag and sway of the conductor throughout its
operating range under rated conditions.
R2.
Each Transmission Owner shall implement its imminent threat process or
procedure when the Transmission Owner has actual knowledge of such a threat,
obtained through normal operating practices or notification from others, that the
Critical Clearance Zone is approached by vegetation to prevent an
encroachment of the Critical Clearance Zone.. [Violation Risk Factor –
Medium][Time Horizon – Real Time]
R3.
Each Transmission Owner shall conduct inspectionsVegetation Inspections of
all applicable lines (as measured in line miles) in accordance with the frequency
specified in its transmission vegetation management program. , unless
constrained by natural disasters4. When constrained by a natural disaster, the
Transmission Owner shall conduct the Vegetation Inspection(s) within six
months or a period agreed to by its Regional Entity, whichever is greater.
[Violation Risk Factor – Medium][Time Horizon – Operations Planning]
R4.
Each Transmission Owner shall prevent encroachment withinof vegetation into
the CriticalMinimum Vegetation Clearance Zone of Distances (MVCD) listed
in FAC-003-2 - Attachment 1 for its applicable lines as observed in real-time
operating between no-load and their Rating, with the following exceptions:
[Violation Risk Factor – Medium][Time Horizon – Real Time]
R5.
Encroachments ofEncroachment into the CriticalMVCD listed in FAC-0032-Attachment 1 resulting from natural disasters. 4
Encroachments of Encroachment into the CriticalMVCD listed in FAC003-2-Attachment 1 resulting from human or animal activity. 5
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting
from falling vegetation.
Each Transmission Owner shall prevent Sustained Outages 6 of applicable lines 7
that are identified as an element of an Interconnection Reliability Operating
Limit (IROL) (or Major WECC Transfer Path) due to vegetation growing into a
conductor operating between no-load and its Rating, with the following
exceptions: [Violation Risk Factor – High][Time Horizon – Real Time]
4
Examples include, but are not limited to, earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh
gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice storms, and
floods.
5
Examples include, but are not limited to, logging, animal severing tree, vehicle contact with tree, arboricultural
activities or horticultural or agricultural activities, or removal or digging of vegetation.
6
Multiple Sustained Outages on an individual line, if caused by the same vegetation, shall be considered as one
outage regardless of the actual number of outages within a 24-hour period.
Draft 2: September 8, 2009
Page 5 of 20
FAC-003-2 — Transmission Vegetation Management Program
R6.
R7.
Sustained Outages of applicable lines that result from natural disasters.4
Sustained Outages of applicable lines that result from human or animal
activity.5
Each Transmission Owner shall prevent Sustained Outages6 of applicable lines6
lines that are not an element of an IROL (or major WECC Transfer Path) due to
vegetation growing into a conductor operating between no-load and its Rating,
with the following exceptions: [Violation Risk Factor – Medium][Time Horizon
– Real Time]
Sustained Outages of applicable lines that result from natural disasters.4
Sustained Outages of applicable lines that result from human or animal
activity.5
Each Transmission Owner shall prevent Sustained Outages6 of applicable lines
due to the blowing together of vegetation and a conductor within an Active
Transmission Line Right of Way (operating within design blow-out conditions)
with the following exception: [Violation Risk Factor – Medium][Time Horizon
– Real Time]
R8.
R9.
Sustained Outages of applicable lines that result from sustained winds or
gusts due to natural disasters.4natural disasters4 or wind-blown debris.
Each Transmission Owner shall prevent Sustained Outages6 of applicable lines6
lines due to vegetation falling into a conductor from within an Active
Transmission Line Right of Way with the following exceptions: [Violation Risk
Factor – Medium] [Time Horizon – Real Time]
Sustained Outages of applicable lines that result from natural disasters.4 or
wind-blown debris.
Sustained Outages of applicable lines that result from human or animal
activity.5
Each Transmission Owner shall implement its annual work plan for vegetation
management to accomplish the purpose of this standard within the extent of its
easement and/or legal rights.. [Violation Risk Factor – Medium] [Time Horizon
– Operations Planning]
R10. Each ReliabilityPlanning Coordinator in consultation with its Transmission
Owner(s) and neighboring Reliability Coordinator(s) shall jointly prepare and
keep current, review annually, a list of designated applicable lines that are
operated below 200200kV, if any, which are subject to this standard. Each
Planning Coordinator shall consult with its Transmission Owner(s) and
neighboring Planning Coordinators to obtain input to develop the list.
[Violation Risk Factor – Lower] [Time Horizon – Long-term Planning]
R10. Each ReliabilityPlanning Coordinator shall develop and document its method
for assessing the reliability significance of sub-200kV lines considering all of
the following:
R10.1 Transmission lines whose loss would result in the exceedance of an
Interconnection Reliability Operating Limit (IROL)
Draft 2: September 8, 2009
Page 6 of 20
FAC-003-2 — Transmission Vegetation Management Program
R11. R10.2
Transmission transmission lines whose loss would place the grid at
an unacceptable risk of instability, separation, or cascading failures.
[Violation Risk Factor – Lower] [Time Horizon – Long-term Planning]
C. Measures
M1. The Transmission Owner has a documented transmission vegetation management
program designed to control (paper or electronic copy of dated, current, in force
document with specified elements) that describes how it conducts work on its Active
Transmission Line Rights of Way to prevent Sustained Outages due to vegetation on
the Active Transmission Line Right of Way., considering all possible locations the
conductor may occupy under the effects of sag and sway throughout its operating
range under rated conditions. (R1)
1.1. The Transmission Owner’s transmission vegetation management program
documentation specifies the methodologiesmethods that the Transmission
Owner usesmay use to control vegetation.
1.2. The Transmission Owner’s transmission vegetation management program
documentation specifies a vegetation inspectionVegetation Inspection frequency
of at least once per calendar year that takes into account local and
environmental factors. This inspection frequency shall be at least once per
calendar year.
1.3. The Transmission Owner’s transmission vegetation management program
requirescontains an annual work plan and it which:
1.3.1.
Identifies the applicable lines to be maintained and related vegetation
management work to be performed during the calendar year while taking
into consideration
1.3.2.
Identifies the work to be performed and the methods used
1.3.3.
Shows flexibility to adjust to changing conditions and to findings from
Vegetation Inspections
1.3.4.
Considers permitting and scheduling requirements from landowners or
regulatory authorities.
1.4. The Transmission Owner’s transmission vegetation management program
requires documentation specifies an imminent threat process or procedure for
responding to imminent threats of a vegetation-related Sustained Outage
including immediate communication of the threat to the Transmission Operator,
and may include a temporary reduction in line Rating, switching lines out of
service, and/or other actions that may be taken until the threat is
relievedresponsible control center.
1.5. The Transmission Owner’s transmission vegetation management
programprogram documentation specifies the interim corrective action process
for use when the Transmission Owner is temporarily constrained from
performing vegetation maintenance as planned.
Draft 2: September 8, 2009
Page 7 of 20
FAC-003-2 — Transmission Vegetation Management Program
1.6. The Transmission Owner’s transmission vegetation management program
documentation specifies the maintenance strategies used (such as minimum
vegetation-to-conductor distance or maximum vegetation height) to ensure that
Table 1 clearances in Attachment 1 are never violated. The maintenance
strategies consider the sag and sway of the conductor throughout its operating
range under rated conditions.
M2. The Transmission Owner has evidence that it implemented its of the implementation
of its vegetation imminent threat process or procedure when it obtained knowledge
that the Critical Clearance Zoneshowing what was approached by vegetation.done
with dates and activities accomplished. (R2)
M3. The Transmission Owner has evidence that it conducted vegetation inspections of all
applicable transmission linesVegetation Inspections in accordance with the frequency
specified in its transmission vegetation management program. (Requirement R3).
M4. The Transmission Owner has evidence such as inspection records, imminent threat
reports or quality assurance reports, demonstrating there were no vegetation
encroachments into the Critical Clearance Zone.The Transmission Owner has
evidence from inspections that indicate there was no vegetation encroachment into
the Minimum Vegetation Clearance Distances listed in FAC-003-2-Attachment 1 for
its applicable lines as observed in real-time operating between no-load and their
Rating, considering exceptions. (R4)
M5. The Transmission Owner hasOwner’s self-certification reports are adequate evidence
that there was not a of no Sustained Outage of an any applicable line that is identified
as an element of an IROL (or Major WECC Transfer Path) due to vegetation growing
into a conductor operating between no-load and its Rating. (R5)
M6. The Transmission Owner’s self-certification reports are adequate evidence of no
Sustained Outage of any applicable line that is not identified as an element of an
IROL (or Major WECC Transfer Path) due to vegetation growing into a conductor
operating between no-load and its Rating. (R5R6)
M7. The Transmission Owner hasOwner’s self-certification reports are adequate evidence
that there was not aof no Sustained Outage of an any applicable line due to the
blowing together of vegetation and a conductor within the Active Transmission Line
Right of Way. (R6R7)
M8. The Transmission Owner hasOwner’s self-certification reports are adequate evidence
that there was not aof no Sustained Outage of anany applicable line due to vegetation
falling into a conductor from within the Active Transmission Line Right of Way.
(R7R8)
M9. The Transmission Owner has evidence that it is implementing, or has implemented,
its annual work plan. (R8An example of evidence is a paper or electronic copy of
work plan and work records. (R9)
M10. The ReliabilityPlanning Coordinator has evidence that it consulted with its
Transmission Owner(s) and adjacent Reliabilityneighboring Planning Coordinator(s),
prepared and kept currentreviewed annually a list of designated sub-200kV
transmission lines, if any, which are subject to this standard. (R9R10)
Draft 2: September 8, 2009
Page 8 of 20
FAC-003-2 — Transmission Vegetation Management Program
M11. The ReliabilityPlanning Coordinator has documented evidence that it has defined its
methodssuch as planning study criteria or other analysis used to develop its method
for assessing the reliability significance of sub-200kV lines and has developed
selection criteria for listing any sub-200kV lines. (R10whose loss would place the
grid at an unacceptable risk of instability, separation, or cascading failures. (R11)
D. Compliance
1.
Compliance Monitoring Process
1.1 Compliance Enforcement
Authority
All compliance information is new and
shown without “track changes” for ease
in reading
Regional Entity
1.2
Compliance Monitoring Period and Reset Timeframe
Not Applicable
1.3
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
Periodic Data Submittals for Sustained Outages caused by vegetation
1.4 Data Retention
The Transmission Owner and Planning Coordinator shall keep data or evidence
to show compliance as identified below unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation:
The Transmission Owner shall retain as evidence of Requirements 1
through 9, Measures 1 through 9 for three years.
The Planning Coordinator shall retain evidence of Requirement 10
and 11, Measure 10 and 11 for one year.
If a Transmission Owner or Planning Coordinator is found non-compliant, it
shall keep information related to the non-compliance until found compliant.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.5 Additional Compliance Information
Draft 2: September 8, 2009
Page 9 of 20
FAC-003-2 — Transmission Vegetation Management Program
The Transmission Owner shall report quarterly to its Regional Entity, or the
Regional Entity’s designee, Sustained Outages of its transmission lines
determined by the Transmission Owner to have been caused by vegetation,
including the following:
The name of the circuit(s), the date, time and duration of the outage; a
description of the cause of the outage; other pertinent comments; and any
countermeasures taken by the Transmission Owner, and Sustained Outage
Category based on the following:
8
Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines that are identified as an element of an
IROL (or Major WECC Transfer Path) by vegetation inside and/or
outside of the Active Transmission Line ROW;
Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines but are not identified as an element of an
IROL (or Major WECC Transfer Path) by vegetation inside and/or
outside of the Active Transmission Line ROW;
Category 2 — Fall-ins: Sustained Outages caused by vegetation falling
into lines from within the Active Transmission Line ROW;
Category 8 4 — Blowing together: Sustained Outages caused by
vegetation and lines blowing together from within the Active
Transmission Line ROW.
Category 3 reporting is eliminated.
Draft 2: September 8, 2009
Page 10 of 20
FAC-003-2 — Transmission Vegetation Management Program
Violation Severity Levels
R#
Violation
Risk
Factor
Violation Severity Level
Lower
The Transmission Owner
has a transmission
vegetation management
program, but the
transmission vegetation
management program is
missing one of the
following:
Requirement 1, Part 1.1, or
Requirement 1, Part 1.2
R1
Lower
R2
Medium
R3
Medium The Transmission Owner
inspected greater than 75%
but less than 100% of the
total line miles specified by
its transmission vegetation
management program.
R4
Medium
Draft 2: September 8, 2009
Moderate
The Transmission Owner
has a transmission
vegetation management
program, but the
transmission vegetation
management program is
missing either Requirement
R1, Part 1.5 or Requirement
R1, Part 1.1 and Part 1.2
High
The Transmission Owner
has a transmission
vegetation management
program, but the
transmission vegetation
management program is
missing up to two of the
following parts of
Requirement R1:
Parts 1.3, 1.4 and 1.6
Severe
The Transmission Owner
does not have transmission
vegetation management
program or the transmission
vegetation management
program is missing all of the
following Parts of
Requirement R1:
Parts 1.3, 1.4 and 1.6
The Transmission Owner
did not implement its
imminent threat process or
procedure when the
Transmission Owner had
actual knowledge of such a
threat, obtained through
normal operating practices
The Transmission Owner
inspected greater than 50%
but less than or equal to
75% of the total line miles
specified by its transmission
vegetation management
program.
The Transmission Owner
inspected greater than 25%
but less than or equal to
50% of the total line miles
specified by its transmission
vegetation management
program.
The Transmission Owner
inspected less than or equal
to 25% of the total line
miles specified by its
transmission vegetation
management program.
The Transmission Owner
has failed to prevent
Page 11 of 20
FAC-003-2 — Transmission Vegetation Management Program
R#
Violation
Risk
Factor
Violation Severity Level
Lower
Moderate
High
Severe
vegetation from encroaching
into the minimum
vegetation clearance
distance.
R5
High
The Transmission Owner
incurred a Sustained Outage
due to vegetation growing
into an applicable
transmission line that is
identified as an element of
an IROL (or Major WECC
Transfer Path).
R6
Medium
The Transmission Owner
incurred a Sustained Outage
due to vegetation growing
into an applicable
transmission line that is not
identified as an element of
an IROL (or Major WECC
Transfer Path).
R7
Medium
The Transmission Owner
incurred a Sustained Outage
due to the blowing together
of vegetation and a
conductor of an applicable
transmission within an
Active Transmission Line
Right of Way.
R8
Medium
The Transmission Owner
incurred a Sustained Outage
Draft 2: September 8, 2009
Page 12 of 20
FAC-003-2 — Transmission Vegetation Management Program
R#
Violation
Risk
Factor
Violation Severity Level
Lower
Moderate
High
Severe
due to vegetation falling into
an applicable transmission
from within an Active
Transmission Line Right of
Way.
The Transmission Owner
failed to implement more
than 5% but less than or
equal to 10% of its annual
work plan.
The Transmission Owner
failed to implement more
than 10% but less than or
equal to 15% of its annual
work plan.
The Transmission Owner
failed to implement more
than 15% of its annual work
plan.
The Planning Coordinator
failed to consult with one of
its Transmission Owners or
one of its adjacent Planning
Coordinators in developing
its list of designated sub200kV transmission lines, if
any, that are subject to this
standard..
The Planning Coordinator
failed to consult with more
than one of its Transmission
Owners or more than one of
its adjacent Planning
Coordinators in developing
its list of designated sub200kV transmission lines, if
any, that are subject to this
standard.
The Planning Coordinator
has not annually reviewed
its list of designated sub200kV transmission lines, if
any, that are subject to this
standard.
The Planning Coordinator
has not prepared a list of
designated sub-200kV
transmission lines, if any,
that are subject to this
standard.
The Planning Coordinator
has not documented its
method for assessing the
reliability significance of
sub-200kV lines.
The Planning Coordinator
has not considered lines
whose loss would place the
grid at an unacceptable risk
of instability, separation, or
cascading failures in
developing its method for
assessing the reliability
significance of sub-200kV
lines.
NA
The Planning Coordinator
has not developed a method
for assessing the reliability
significance of sub-200kV
lines.
R9
Medium The Transmission Owner
failed to implement 5% or
less of its annual work plan.
R10
Lower
R11
Lower
Draft 2: September 8, 2009
Page 13 of 20
FAC-003-2 — Transmission Vegetation Management Program
Regional Variances
None identified.
Associated Technical Reference Documents
FAC-003 Reference — Transmission Vegetation Management — White Paper.
Version History
Version
Date
Action
Change Tracking
1
TBA
1.
Added “Standard Development
Roadmap.”
01/20/06
2.
Changed “60” to “Sixty” in
section A, 5.2.
3.
Added “Proposed Effective
Date: April 7, 2006” to footer.
4.
Added “Draft 3: November 17,
2005” to footer.
1
April 4, 2007
2
Draft 2: September 8, 2009
Regulatory Approval — Effective Date
New
Complete revision
Page 14 of 20
FAC-003-2 — Transmission Vegetation Management Program
FAC-003-2-Attachment 1
The Critical Clearance Zone is the area mapped by the radial distance around a conductor specified in TABLE I below when the conductor
is energized and operating between no-load and its Rating, including the design blow-out, however, the zone shall not extend beyond the
limits of the Active Transmission Line Right of Way.
TABLE I1 — Minimum Vegetation Clearance Distances (MVCD)
For Alternating Current Voltages
( AC )
Nomin
al
System
Voltag
e (kV)
Draft 1: October 22, 2008
( AC )
Maximum
System
D feet
(meters)
D feet
(meters)
D feet
(meters)
D feet
(meters)
D feet
(meters)
Voltage
(kV)
sea level
3,000ft
(914.4m)
4,000ft
(1219.2m)
5,000ft
(1524m)
6,000ft
(1828.8m)
765
800
8.06ft
(2.46m)
8.89ft
(2.71m)
9.17ft
(2.80m)
9.45ft
(2.88m)
9.73ft
(2.97m)
500
550
5.06ft
(1.54m)
5.66ft
(1.73m)
5.86ft
(1.79m)
6.07ft
(1.85m)
6.28ft
(1.91m)
345
362
3.12ft
(0.95m)
3.53ft
(1.08m)
3.67ft
(1.12m)
3.82ft
(1.16m)
3.97ft
(1.21m)
230
242
2.97ft
(0.91m)
3.36ft
(1.02m)
3.49ft
(1.06m)
3.63ft
(1.11m)
3.78ft
(1.15m)
161*
169
2ft
(0.61m)
2.28ft
(0.69m)
2.38ft
(0.73m)
2.48ft
(0.76m)
2.58ft
(0.79m)
138*
145
1.7ft
(0.52m)
1.94ft
(0.59m)
2.03ft
(0.62m)
2.12ft
(0.65m)
2.21ft
(0.67m)
115*
121
1.41ft
(0.43m)
1.61ft
(0.49m)
1.68ft
(0.51m)
1.75ft
(0.53m)
1.83ft
(0.56m)
88*
100
1.15ft
(0.35m)
1.32ft
(0.40m)
1.38ft
(0.42m)
1.44ft
(0.44m)
1.5ft
(0.46m)
Page Draft 2: September 8, 2009
Page 15 of 10 of 20
FAC-003-2 — Transmission Vegetation Management Program
69*
( AC )
( AC )
Nominal
System
Maximum
System
Voltage
(kV)
Voltage
(kV)
72
0.82ft
(0.25m)
0.94ft
(0.29m)
0.99ft
(0.30m)
1.03ft
(0.31m)
1.08ft
(0.33m)
MVCD
feet
(meters)
MVCD
feet
(meters)
MVCD
feet
(meters)
MVCD
feet
(meters)
MVCD
feet
(meters)
MVCD
feet
(meters)
MVCD
feet
(meters)
MVCD
feet
(meters)
MVCD
feet
(meters)
MVCD
feet
(meters)
sea level
3,000ft
(914.4m)
4,000ft
(1219.2m)
5,000ft
(1524m)
6,000ft
(1828.8m)
7,000ft
(2133.6m)
8,000ft
(2438.4m)
9,000ft
(2743.2m)
10,000ft
(3048m)
11,000ft
(3352.8m)
765
800
8.06ft
(2.46m)
8.89ft
(2.71m)
9.17ft
(2.80m)
9.45ft
(2.88m)
9.73ft
(2.97m)
10.01ft
(3.05m)
10.29ft
(3.14m)
10.57ft
(3.22m)
10.85ft
(3.31m)
11.13ft
(3.39m)
500
550
5.06ft
(1.54m)
5.66ft
(1.73m)
5.86ft
(1.79m)
6.07ft
(1.85m)
6.28ft
(1.91m)
6.49ft
(1.98m)
6.7ft
(2.04m)
6.92ft
(2.11m)
7.13ft
(2.17m)
7.35ft
(2.24m)
345
362
3.12ft
(0.95m)
3.53ft
(1.08m)
3.67ft
(1.12m)
3.82ft
(1.16m)
3.97ft
(1.21m)
4.12ft
(1.26m)
4.27ft
(1.30m)
4.43ft
(1.35m)
4.58ft
(1.40m)
4.74ft
(1.44m)
230
242
2.97ft
(0.91m)
3.36ft
(1.02m)
3.49ft
(1.06m)
3.63ft
(1.11m)
3.78ft
(1.15m)
3.92ft
(1.19m)
4.07ft
(1.24m)
4.22ft
(1.29m)
4.37ft
(1.33m)
4.53ft
(1.38m)
161*
169
2ft
(0.61m)
2.28ft
(0.69m)
2.38ft
(0.73m)
2.48ft
(0.76m)
2.58ft
(0.79m)
2.69ft
(0.82m)
2.8ft
(0.85m)
2.91ft
(0.89m)
3.03ft
(0.92m)
3.14ft
(0.96m)
138*
145
1.7ft
(0.52m)
1.94ft
(0.59m)
2.03ft
(0.62m)
2.12ft
(0.65m)
2.21ft
(0.67m)
2.3ft
(0.70m)
2.4ft
(0.73m)
2.49ft
(0.76m)
2.59ft
(0.79m)
2.7ft
(0.82m)
115*
121
1.41ft
(0.43m)
1.61ft
(0.49m)
1.68ft
(0.51m)
1.75ft
(0.53m)
1.83ft
(0.56m)
1.91ft
(0.58m)
1.99ft
(0.61m)
2.07ft
(0.63m)
2.16ft
(0.66m)
2.25ft
(0.69m)
88*
100
1.15ft
(0.35m)
1.32ft
(0.40m)
1.38ft
(0.42m)
1.44ft
(0.44m)
1.5ft
(0.46m)
1.57ft
(0.48m)
1.64ft
(0.50m)
1.71ft
(0.52m)
1.78ft
(0.54m)
1.86ft
(0.57m)
69*
72
0.82ft
(0.25m)
0.94ft
(0.29m)
0.99ft
(0.30m)
1.03ft
(0.31m)
1.08ft
(0.33m)
1.13ft
(0.34m)
1.18ft
(0.36m)
1.23ft
(0.37m)
1.28ft
(0.39m)
1.34ft
(0.41m)
*As designated by the ReliabilityPlanning Coordinator
Draft 1: October 22, 2008
Page Draft 2: September 8, 2009
Page 16 of 10 of 20
FAC-003-2 — Transmission Vegetation Management Program
TABLE I1 (CONT.) — Minimum Vegetation Clearance Distances (MVCD)s (D)
For Alternating Current Voltages
( AC )
Draft 1: October 22, 2008
( AC )
Nomin
al
System
Maximum
System
D feet
(meters)
D feet
(meters)
D feet
(meters)
D feet
(meters)
D feet
(meters)
Voltag
e (kV)
Voltage
(kV)
7,000ft
(2133.6m)
8,000ft
(2438.4m)
9,000ft
(2743.2m)
10,000ft
(3048m)
11,000ft
(3352.8m)
765
800
10.01ft
(3.05m)
10.29ft
(3.14m)
10.57ft
(3.22m)
10.85ft
(3.31m)
11.13ft
(3.39m)
500
550
6.49ft
(1.98m)
6.7ft
(2.04m)
6.92ft
(2.11m)
7.13ft
(2.17m)
7.35ft
(2.24m)
345
362
4.12ft
(1.26m)
4.27ft
(1.30m)
4.43ft
(1.35m)
4.58ft
(1.40m)
4.74ft
(1.44m)
230
242
3.92ft
(1.19m)
4.07ft
(1.24m)
4.22ft
(1.29m)
4.37ft
(1.33m)
4.53ft
(1.38m)
161*
169
2.69ft
(0.82m)
2.8ft
(0.85m)
2.91ft
(0.89m)
3.03ft
(0.92m)
3.14ft
(0.96m)
138*
145
2.3ft
(0.70m)
2.4ft
(0.73m)
2.49ft
(0.76m)
2.59ft
(0.79m)
2.7ft
(0.82m)
115*
121
1.91ft
(0.58m)
1.99ft
(0.61m)
2.07ft
(0.63m)
2.16ft
(0.66m)
2.25ft
(0.69m)
88*
100
1.57ft
(0.48m)
1.64ft
(0.50m)
1.71ft
(0.52m)
1.78ft
(0.54m)
1.86ft
(0.57m)
69*
72
1.13ft
(0.34m)
1.18ft
(0.36m)
1.23ft
(0.37m)
1.28ft
(0.39m)
1.34ft
(0.41m)
Page Draft 2: September 8, 2009
Page 17 of 10 of 20
FAC-003-2 — Transmission Vegetation Management Program
*As designated by the Reliability Coordinator
TABLE I — Minimum Vegetation Clearance Distances (MVCD)
For Direct Current Voltages
( DC )
Pole to Pole
Nominal
Voltage
(kV)
1500
1200
1000
800
Draft 1: October 22, 2008
sea level
D feet
(meters)
3,000ft
(914.4m) Alt.
D feet
(meters)
4,000ft
(1219.2m)
Alt.
D feet
(meters)
5,000ft
(1524m)
Alt.
D feet
(meters)
6,000ft
(1828.8m)
Alt.
13.92ft
(4.24m)
10.07ft
(3.07m)
7.89ft
(2.40m)
4.78ft
(1.46m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
5.35ft
(1.63m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
5.55ft
(1.69m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
5.75ft
(1.75m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
5.95ft
(1.81m)
D feet
(meters)
Page Draft 2: September 8, 2009
Page 18 of 10 of 20
FAC-003-2 — Transmission Vegetation Management Program
500
3.43ft
(1.05m)
4.02ft
(1.23m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
Pole to Pole
Nominal
Voltage
(kV)
D feet
(meters)
7,000ft
(2133.6m)
Alt.
D feet
(meters)
(8,000ft
(2438.4m)
Alt.
D feet
(meters)
9,000ft
(2743.2m)
Alt.
D feet
(meters)
10,000ft
(3048m)
Alt.
D feet
(meters)
11,000ft
(3352.8m)
Alt.
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
6.15ft
(1.87m)
4.5ft
(1.37m)
16.9ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
6.36ft
(1.94m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
6.57ft
(2.00m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
6.77ft
(2.06m)
5ft
(1.52m)
17.97ft
(5.48m)
(13.54ft
4.13m)
10.92ft
(3.33m)
6.98ft
(2.13m)
5.17ft
(1.58m)
1500
1200
1000
800
500
( DC )
Nominal Pole
to Ground
Voltage
(kV)
MVCD feet
(meters)
sea level
MVCD feet
(meters)
3,000ft
(914.4m)
Alt.
MVCD feet
(meters)
4,000ft
(1219.2m)
Alt.
MVCD
feet
(meters)
5,000ft
(1524m)
Alt.
MVCD feet
(meters)
6,000ft
(1828.8m)
Alt.
MVCD
feet
(meters)
7,000ft
(2133.6m)
Alt.
MVCD
feet
(meters)
(8,000ft
(2438.4m)
Alt.
MVCD
feet
(meters)
9,000ft
(2743.2m)
Alt.
MVCD
feet
(meters)
10,000ft
(3048m)
Alt.
MVCD
feet
(meters)
11,000ft
(3352.8m)
Alt.
±750
13.92ft
(4.24m)
15.07ft
(4.59m)
15.45ft
(4.71m)
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.9ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
±600
10.07ft
(3.07m)
11.04ft
(3.36m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
(13.54ft
4.13m)
±500
7.89ft
(2.40m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
Draft 1: October 22, 2008
Page Draft 2: September 8, 2009
Page 19 of 10 of 20
FAC-003-2 — Transmission Vegetation Management Program
±400
4.78ft
(1.46m)
5.35ft
(1.63m)
5.55ft
(1.69m)
5.75ft
(1.75m)
5.95ft
(1.81m)
6.15ft
(1.87m)
6.36ft
(1.94m)
6.57ft
(2.00m)
6.77ft
(2.06m)
6.98ft
(2.13m)
±250
3.43ft
(1.05m)
4.02ft
(1.23m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5ft
(1.52m)
5.17ft
(1.58m)
Draft 1: October 22, 2008
Page Draft 2: September 8, 2009
Page 20 of 10 of 20
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2
Standard FAC-003-1
NERC Board Approved
Comment
Proposed Standard FAC-003-2
0. Definitions
0. The definition of Active Transmission Line
Right of Way was added in response to FERC
693 and industry comments. The glossary
definition of Vegetation Inspection was
changed in response to industry comments.
Active Transmission Line Right of Way — A strip of land that is
occupied by active transmission facilities. This corridor does not
include the inactive Right of Way or unused part of the Right of Way
intended for other facilities.
Vegetation Inspection — The systematic examination of vegetation
conditions on an Active Transmission Line Right of Way. This
inspection may be combined with a general line inspection. The
inspection includes the documentation of any vegetation that may pose
a threat to reliability prior to the next planned inspection or
maintenance work, considering the current location of the conductor
and other possible locations of the conductor due to sag and sway for
rated conditions.
1. Title: Transmission Vegetation Management
Program
1. Title: No Change (N/C)
1. Title: Transmission Vegetation Management Program
3. Purpose: To improve the reliability of the
electric transmission systems by preventing
outages from vegetation located on
transmission rights-of-way (ROW) and
minimizing outages from vegetation located
adjacent to ROW, maintaining clearances
between transmission lines and vegetation on
and along transmission ROW, and reporting
vegetation related outages of the transmission
systems to the respective Regional Reliability
Organizations (RRO) and the North American
Electric Reliability Council (NERC).
3. Purpose: Changed to a shorter more
concise purpose statement. The various
explanatory objectives are now addressed
within the standard’s requirements.
3. Purpose: To improve the reliability of the electric transmission
system by preventing those vegetation related outages that could lead to
Cascading.
4. Applicability:
4. Applicability:
4. Applicability:
September 8, 2009
1
4.1. Functional Entities
4.1. Transmission Owner
4.1 N/C
4.1.1. Transmission Owner
4.1.2. Planning Coordinator
4.2. Regional Reliability Organization
4.2 Removed Regional Reliability
Organization in response to FERC Order 693
and later added Planning Coordinator in lieu
of Reliability Coordinator in response to
industry comments to the October 27, 2008
comments.
4.3. This standard shall apply to all
transmission lines operated at 200 kV and
above and to any lower voltage lines
designated by the RRO as critical to the
reliability of the electric system in the region.
4.3 (Note that the version 1 section 4.3 is now
covered in version 2 section 4.2)
4.2.1 Added reference to lines that cross lands
owned by federal, state, provincial, public,
private, or tribal entities. Changed RRO to
Planning Coordinator
4.2.2. Added criterion to identify the time
frame provided to manage sub 200kV lines to
the standard after the Planning Coordinator
has determined that they are subject to the
standard.
4.2. Facilities
4.2.1. Transmission lines (“applicable lines”) operated at 200kV or
higher, and transmission lines operated below 200kV
designated by the Planning Coordinator as being subject to
this standard including but not limited to those that cross
lands owned by federal1, state, provincial, public, private, or
tribal entities.
4.2.2. Transmission lines operated below 200kV designated by the
Planning Coordinator as being subject to this standard
become subject to this standard 12 months after the date the
Planning Coordinator initially designates the transmission
line as being subject to this standard.
4.2.3. Existing transmission line(s) operated at 200kV or higher
that are newly acquired by a Transmission Owner and were
not previously subject to this standard, become subject to
this standard 12 months after the acquisition date of the
transmission line(s).
4.2.3.
Added criterion to specify when a newly
acquired line above 200kV will become
1
EPAct 2005 section 1211c: “Access approvals by Federal agencies”
September 8, 2009
2
subject to the standard.
Effective Dates:
5.1 One calendar year from the date of
adoption by the NERC Board of Trustees for
Requirement 1 and 2.
5.2 Sixty calendar days from the date of
adoption by the NERC Board of Trustees for
the Requirements 3 and 4.
Effective Dates:
Consistency with standards approval process
for a standard revision.
5. Effective Dates:
In those jurisdictions where regulatory approval is required, the first
calendar day of the first calendar quarter one year after applicable
regulatory authority approval for all requirements; or, in those
jurisdictions where no regulatory approval is required, the first
calendar day of the first calendar quarter one year following Board
of Trustees adoption.
R1. The Transmission Owner shall prepare,
and keep current, a formal transmission
vegetation management program (TVMP). The
TVMP shall include the Transmission Owner’s
objectives, practices, approved procedures, and
work specifications1.
R1.1. The TVMP shall define a schedule for
and the type (aerial, ground) of ROW
vegetation inspections. This schedule should be
flexible enough to adjust for changing
conditions. The inspection schedule shall be
based on the anticipated growth of vegetation
and any other environmental or operational
factors that could impact the relationship of
vegetation to the Transmission Owner’s
transmission lines.
R1.2 The Transmission Owner, in the TVMP,
shall identify and document the clearances
between vegetation and any overhead,
ungrounded supply concoctors taking into
consideration transmission line voltage, the
effects of ambient temperature on conductor
sag under maximum design loading, and the
effects of wind velocities on conductor sway.
R1. Changed R1 to be a TVMP
“documentation” requirement not an
implementation requirement.
Items changed or modified were removed
Clearance 1 (which was a fill in the blank)
Clearance 2 was replaced by MVCD (to find a
more acceptable alternative to MAID), added
the frequency of at least once per calendar
year to Vegetation Inspections, moved
imminent threat action from the original R1.5
to the new requirement R2, removed personnel
qualifications (they were fill-in-the-blank),
replaced the term “mitigation measures “ with
“interim corrective action process” to avoid
conflict with NERC’s use of the term
“imminent threat:, specified that maintenance
strategies to achieve clearance must consider
the sag and sway under all rated conditions,
and clarified that this applies on the active
transmission line ROW. Added requirements
for the documentation of an annual work plan
R1.
September 8, 2009
Each Transmission Owner shall have a documented
transmission vegetation management program that describes
how it conducts work on its Active Transmission Line Rights of
Way to prevent Sustained Outages due to vegetation,
considering all possible locations the conductor may occupy
under the effects of sag and sway throughout its operating range
under rated conditions. The transmission vegetation
management program shall:
1.1. Specify the methods that the Transmission Owner may use
to control vegetation.
1.2. Specify a Vegetation Inspection frequency of at least once
per calendar year that takes into account local and
environmental factors.
1.3. Require an annual work plan. An annual work plan shall:
1.3.1.
1.3.2.
Identify the applicable lines to be maintained
1.3.3.
Be flexible to adjust to changing conditions and
to findings from Vegetation Inspections.
Adjustments to the plan within the year are
permissible.
1.3.4.
Take into consideration permitting and
scheduling requirements from landowners or
Identify the work to be performed and methods
to be used
3
Specifically, the Transmission Owner shall
establish clearances to be achieved at the time
of vegetation management work identified
herein as Clearance 1, and shall also establish
and maintain a set of clearances identified
herein as Clearance 2 to prevent flashover
between vegetation and overhead ungrounded
supply conductors.
R1.2.1. Clearance 1 — The Transmission
Owner shall determine and document
appropriate clearance distances to be achieved
at the time of transmission vegetation
management work based upon local conditions
and the expected time frame in which the
Transmission Owner plans to return for future
R1.2.2. Clearance 2 — The Transmission
Owner shall determine and document specific
radial clearances to be maintained between
vegetation and conductors under all rated
electrical operating conditions. These minimum
clearance distances are necessary to prevent
flashover between vegetation and conductors
and will vary due to such factors as altitude and
operating voltage. These Transmission Ownerspecific minimum clearance distances shall be
no less than those set forth in the Institute of
Electrical and Electronics Engineers (IEEE)
Standard 516-2003 (Guide for Maintenance
Methods on Energized Power Lines) and as
specified in its Section 4.2.2.3, Minimum Air
Insulation Distances without Tools in the Air
Gap.
R1.2.2.1 Where transmission system transient
September 8, 2009
regulatory authorities.
1.4. Require a process or procedure for response to an
imminent threat of a vegetation-related Sustained Outage.
The process or procedure shall specify actions which shall
include communication of the threat to the responsible
control center.
1.5. Specify an interim corrective action process for use when
the Transmission Owner is temporarily constrained from
performing vegetation maintenance as planned.
1.6. Specify the maintenance strategies used (such as
minimum vegetation-to-conductor distance or maximum
vegetation height) to ensure that Table 1 clearances in
Attachment 1 are never violated. The maintenance
strategies shall consider the sag and sway of the conductor
throughout its operating range under rated conditions.
4
overvoltage factors are not known, clearances
shall be derived from Table 5, IEEE 516-2003,
phase-to-ground distances, with appropriate
altitude correction factors applied.
R1.2.2.2 Where transmission system transient
overvoltage factors are known, clearances shall
be derived from Table 7, IEEE 516-2003,
phase-to-phase voltages, with appropriate
altitude correction
factors applied
R1.3. All personnel directly involved in the
design and implementation of the TVMP shall
hold appropriate qualifications and training, as
defined by the Transmission Owner, to perform
their duties.
R1.4. Each Transmission Owner shall develop
mitigation measures to achieve sufficient
clearances for the protection of the
transmission facilities when it identifies
locations on the ROW where the Transmission
Owner is restricted from attaining the
clearances specified in Requirement 1.2.1.
R1.5. Each Transmission Owner shall establish
and document a process for the immediate
communication of vegetation conditions that
present an imminent threat of a transmission
line outage.
R2. The Transmission Owner shall create and
implement an annual plan for vegetation
management work to ensure the reliability of
the system. The plan shall describe the methods
used, such as manual clearing, mechanical
September 8, 2009
R2. Reduced the verbiage, moved the
“create” function and other documentation
activities/actions into new R1.section 1.3,
and moved the implementation function into
R9.
R9. Each Transmission Owner shall implement its annual work plan
for vegetation management to accomplish the purpose of this
standard.
5
clearing, herbicide treatment, or other actions.
The plan should be flexible enough to adjust to
changing conditions, taking into consideration
anticipated growth of vegetation and all other
environmental factors that may have an impact
on the reliability of the transmission systems.
Adjustments to the plan shall be documented as
they occur. The plan should take into
consideration the time required to obtain
permissions or permits from landowners or
regulatory authorities. Each Transmission
Owner shall have systems and procedures for
documenting and tracking the planned
vegetation management work and ensuring that
the vegetation management work was
completed according to work specifications.
R3. The Transmission Owner shall report
quarterly to its RRO, or the RRO’s designee,
sustained transmission line outages determined
by the Transmission Owner to have been
caused by vegetation.
September 8, 2009
Reporting requirements are now located in the
compliance section, Additional Compliance
Information, as required by “NERC Standard
format”, specifically, reporting outages in and
of itself does not improve reliability.
Additional Compliance Information
The Transmission Owner shall report quarterly to its Regional Entity,
or the Regional Entity’s designee, Sustained Outages of its
transmission lines determined by the Transmission Owner to have been
caused by vegetation, including the following:
The name of the circuit(s), the date, time and duration of the
outage; a description of the cause of the outage; other pertinent
comments; and any countermeasures taken by the Transmission
Owner, and Sustained Outage Category based on the following:
Category 1A — Grow-ins: Sustained Outages caused by
vegetation growing into applicable lines that are identified as
an element of an IROL (or Major WECC Transfer Path) by
vegetation inside and/or outside of the Active Transmission
Line ROW;
Category 1B — Grow-ins: Sustained Outages caused by
vegetation growing into applicable lines but are not identified
6
as an element of an IROL (or Major WECC Transfer Path) by
vegetation inside and/or outside of the Active Transmission
Line ROW;
Category 2 — Fall-ins: Sustained Outages caused by
vegetation falling into lines from within the Active
Transmission Line ROW;
Category2 4 — Blowing together: Sustained Outages caused by
vegetation and lines blowing together from within the Active
Transmission Line ROW.
R4. The RRO shall report the outage
This is now covered in the Additional
information provided to it by Transmission
Compliance Information as is appropriate
Owner’s, as required by Requirement 3,
for all reporting issues.
quarterly to NERC, as well as any actions taken
by the RRO as a result of any of the reported
outages.
NOTE:
2
Below are new requirement in Version 2 that were not in Version 1 and were not mapped above.
The new Version 2 of the standard now has a separate
requirement for documenting and implementing the
imminent threat.
R2.
Each Transmission Owner shall implement its
imminent threat procedure when the
Transmission Owner has actual knowledge of
such a threat, obtained through normal
operating practices
The new Version 2 of the standard now has a separate
requirement for documenting and implementing the
Vegetation Inspections.
R3.
Each Transmission Owner shall conduct
Vegetation Inspections of all applicable lines
(as measured in line miles) in accordance with
the frequency specified in its transmission
vegetation management program, unless
constrained by natural disasters5. When
constrained by a natural disaster, the
Transmission Owner shall conduct the
Category 3 reporting is eliminated.
September 8, 2009
7
Vegetation Inspection(s) within 6 months or a
period agreed to by its Regional Entity,
whichever is greater
The new Version 2 utilizes MVCD, a technically
justifiable separation distance at which flashover will
not occur, and applies it to real time observations to
provide the clarity needed for field applications. The
combination of choosing an effective maintenance
strategy (R1 section 1.6), effective inspections (R3),
and annual work performance (R9), will ensure a high
level of reliability while imminent threat
implementation (R2) and MVCD findings (R4) will
provide the feedback to the Transmission Owner
necessary to in make improvements in the overall
maintenance of vegetation.
R4.
R5, R6, R7 and R8 explicitly state that sustained
outages from vegetation are violations of this standard.
This removes the implicit interpretation that is
currently in Version 1.
R5. Each Transmission Owner shall prevent Sustained
Outages of applicable lines that are identified as
an element of an Interconnection Reliability
Operating Limit (or Major WECC Transfer Path
in the Western Interconnection) due to vegetation
growing into a conductor operating between noload and its Rating with the following exceptions:
R5 and its companion R6 apply to grow-ins. R5
applies to the most significant circuits and is separated
from R6 to allow application of the most appropriate
VRF.
R7 addresses blowing together and R8 addresses fallins.
Each Transmission Owner shall prevent
encroachment of vegetation into the Minimum
Vegetation Clearance Distances (“MVCD”)
listed in FAC-003-2-Attachment 1 for its
applicable lines as observed in real-time
operating between no-load and their Rating with
the following exceptions:
Sustained Outages of applicable lines that
result from natural disasters.
Sustained Outages of applicable lines that
result from human or animal activity.
R6. Each Transmission Owner shall prevent Sustained
Outages of applicable lines that are not an element
of an Interconnection Reliability Operating Limit
(or Major WECC Transfer Path in the Western
September 8, 2009
8
Interconnection) due to vegetation growing into a
conductor operating between no-load and its
Rating with the following exceptions:
Sustained Outages of applicable lines that
result from natural disasters.
Sustained Outages of applicable lines that
result from human or animal activity.
R7. Each Transmission Owner shall prevent Sustained
Outages of applicable lines due to the blowing
together of vegetation and a conductor within an
Active Transmission Line Right of Way
(operating within design blow-out conditions)
with the following exception:
Sustained Outages of applicable lines that
result from natural disasters or wind-blown
debris.
R8. Each Transmission Owner shall prevent Sustained
Outages of applicable lines due to vegetation
falling into a conductor from within an Active
Transmission Line Right of Way with the
following exceptions:
Two separate and distinct elements in this standard
were created to remove confusion about the difference
between the TVMP (a document) and the annual work
plan. The annual work plan documentation is in R1
September 8, 2009
R9.
Sustained Outages of applicable lines that
result from natural disasters or wind-blown
debris.
Sustained Outages of applicable lines that
result from human or animal activity.
Each Transmission Owner shall implement its
annual work plan for vegetation management to
accomplish the purpose of this standard.
9
section 1.3 and the implementation of the annual work
plan is in R9,
September 8, 2009
In response to FERC order 693 and industry comment,
the PC has been assigned as the appropriate functional
entity to prepare the list of applicable lines below 200
kV.
R10. Each Planning Coordinator shall prepare and
keep current, a list of lines that are operated
below 200 kV, if any, which are subject to this
standard. Each Planning Coordinator shall
consult with its Transmission Owner(s) and
neighboring Planning Coordinators to obtain
input to develop the list.
This requirement captures the methodology and the
parameters to be used by each PC to assess the
significance of sub 200 kV lines.
R11. Each Planning Coordinator shall develop and
document its method for assessing the reliability
significance of sub-200kV transmission lines
whose loss would place the grid at an
unacceptable risk of instability, separation, or
cascading failures.
10
Unofficial Comment Form for Transmission Vegetation Management
Standard FAC-003-2 (Project 2007-07)
Please DO NOT use this comment form. Please use the electronic comment form located at
the link below to submit comments on the proposed standard. Comments must be
submitted by October 24, 2009. If you have questions please contact Harry Tom at
[email protected].
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
Opening Remarks:
The SDT appreciates the valuable responses provided by the industry and other
stakeholders on this Standard revision. We have worked diligently, utilizing those
comments and directives in FERC Order 693 to improve this revision.
Given the importance and complexity of this standard, the SDT felt it was appropriate to
develop and provide a comprehensive Technical Reference Document (White Paper) to
assist in the interpretation and application of this standard. This companion document is
included in this posting of FAC-003-2.
We are optimistic that this Standard fully satisfies stakeholder concerns and FERC Order 693
and believe this version will be ready for balloting after this comment period.
Background Information:
The Vegetation Management Standard Drafting Team (SDT) prepared a proposed revision of
FAC-003-1 in accordance with the scope as contained in the Standard Authorization Request
(SAR). The SAR includes addressing FERC directives in Order 693. These included:
•
Removal of ‘fill in the blank’ components where the Transmission Owner
determines the requirement with no limits or direction. Examples include Clearance
1 and “personnel requirements” in version 1.
•
Removal of references to the Regional Reliability Organization (RRO) and
replacement with the correct designation of Regional Entity (RE).
•
Application of new NERC Drafting Team Guidelines (DTG) to the standard.
Examples include the replacement of the current compliance section with Violation
Risk Factors (VRFs) and Violation Severity Levels (VSLs) as referenced in the
Sanction Guidelines. Additionally, documentation and implementation elements are
separated into different requirements in the proposed standard as required by the
DTG.
•
Address the applicability and appropriateness of IEEE 516 in determining clearance
distances.
•
Address applicability of this standard to sub 200kV lines that could place the grid at
an unacceptable risk of instability, separation, or cascading failures.
•
Address a minimum vegetation inspection frequency that accounts for local factors.
•
Address applicability to federal lands.
The initial proposed revision was posted for industry comment during a public comment
period from October 27, 2008 to November 25, 2008. The SDT received comments from 66
separate entities on the initial posting of this proposed standard revision. The completed
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Unofficial Comment Form — Transmission Vegetation Management Standard FAC-003-2
(Project 2007-07)
Consideration of Comments document spans 279 pages making it one of the largest
comment documents for any of the NERC draft standards. There were 17 specific questions
and a summary question in the posting.
After careful consideration of FERC Order 693 and all comments from the stakeholders, the
Standards Drafting Team (SDT) made revisions to the proposed second in order to make it
stronger, clearer and more practical for field implementation. These revisions are fully
articulated in the mapping document and should be reviewed by the reader. The SDT also
developed a Technical Reference Document (White Paper) to clarify the intent and purpose
of each requirement found in FAC-003-2. Many of the significant revisions are, however,
highlighted in the following:
The key difference between the current standard and this posting is the requirement that
certain vegetation outages are violations of the standard (R5, R6, R7 and R8). These
requirements, in a clear and unambiguous manner, address prevention of Sustained
Outages due to vegetation.
Key differences between first posting and second posting of proposed FAC-003 -2 include:
•
Replaced the Critical Clearance Zone (CCZ) concept found in R4 with a practical
field measurement to address commenter’s concerns.
•
Eliminated the CCZ as the trigger of imminent threat in R2 to address commenters’
concerns.
•
Added a new part to Requirement R1 - TVMP (1.6) to address commenters’
concerns regarding the elimination of Clearance 1. This change requires that the
TO account for anticipated conductor movement.
•
Developed VRFs and VSLs consistent with the NERC Drafting Team Guidelines.
•
Created a second grow-in outage requirement to allow for different VRF levels
based on the actual criticality of the line.
The SDT believes that this posting is an improvement over both the FAC 003-1 and the
October 27, 2008 posting of FAC 003-2. The following illustrates examples of these
improvements.
1. The purpose statement was shortened to be in line with the Drafting Team
Guidelines for a more concise purpose statement. The various explanatory objectives
in the current standard’s Purpose statement are now addressed within the body of
the requirements of this second revision.
2. Revised the purpose statement in response to comments about the use of the term
Bulk Electric System.
3. The TVMP Requirement found in R1 was re-written to clarify that the objective of the
TVMP is to improve reliability by preventing Sustained Outages due to vegetation.
4. Requirement R1, Part 1.6 now requires that the TO effectively describe the strategies
used to prevent tree and conductor conflicts, replacing “Clearance 1”.
5. Requirement R4 replaces the CCZ concept with a practical “real time” method of
observing/measuring vegetation that could cause spark-over.
6. Requirement R2 eliminates the CCZ trigger for the Imminent Threat Process in favor
of a more practical field implementation strategy.
Page 2 of 7
Unofficial Comment Form — Transmission Vegetation Management Standard FAC-003-2
(Project 2007-07)
7. Defined Vegetation Inspection as a NERC Glossary term. This definition recognizes
that vegetation inspections can be performed concurrently with other transmission
line inspections.
8. Defined Active Transmission Line Right-of-Way as NERC Glossary term. This limits
applicability of the requirements to the portion of the ROW with active transmission
facilities.
9. Established a minimum inspection frequency of one calendar year to address FERC
concerns about inspection cycles. This also includes a provision to address impact of
natural disasters on schedule attainment.
10. Clarified Applicability section to include all types of land ownerships to address FERC
concerns identified in Order 693.
11. Established clear process and responsibility to identify and designate sub 200kV lines
which will be subject to the provisions of this standard.
12. Developed VRFs in accordance with the Drafting Team Guidelines to better reflect
impact/risk to the reliability of the grid.
13. Developed separate requirements for documentation and implementation of the
Imminent Threat Process, Vegetation Inspections, and the Annual Work Plan in
accordance with the Drafting Team Guidelines.
14. Replaced Clearance 2 with Minimum Vegetation Clearance Distance (MVCD) based on
the Gallet equation. This removes the ambiguity about hypothetical versus real-time
clearance while still accounting for conductor movement in R1, Part 1.6.
15. Replaced the Reliability Coordinator (RC) with the Planning Coordinator (PC) as the
appropriate entity to designate applicable sub 200kV lines.
16. Clarified Interim Corrective Action Plan as “temporary” in nature when the TO is
constrained from getting adequate clearance. The Interim Corrective Action Plan also
replaces the term Mitigation Plan avoiding conflicts with the Compliance term
“Mitigation Plan.”
17. Eliminated the reporting requirement for Category 3 (fall-in from outside the ROW)
outages.
18. Assigned new Sustained Outage reporting categories (1A, 1B, 2 and 4) which will
allow tracking and trending to use historical outages.
Analysis of Industry Comments:
Disagreements were high for questions 1, 7, 11, and 15, with values of 52%, 47%, 57%
and 94% respectively. Those disagreements related to the use of the term “Bulk Electric
System” in the purpose statement, the identification of actions required of the Transmission
Operator when implementing the imminent threat procedure in Requirement R1.4, the use
of “approaching” the calculated boundary of the Critical Clearance Zone as the threshold for
implementation of the imminent threat procedure in requirement R2, and the use of the
calculated boundary of the Critical Clearance Zone as a surface for determining clearance
violations in R4. The comments contained numerous suggestions for changes to address
the disagreements. The other questions were given mostly agreeable remarks; however
some changes were made based on those comments.
The SDT has posted its response to the comments submitted in response to the last draft of
this standard. The team updated its Technical Reference to align with the changes made to
the proposed standard, updated the “mapping” document, and added an implementation
plan. Please review these documents and then answer the following questions.
Page 3 of 7
Unofficial Comment Form — Transmission Vegetation Management Standard FAC-003-2
(Project 2007-07)
*Please use the electronic comment form to submit your final responses to NERC.
1.
As stated in the background information above, in response to industry comments,
the Requirement for documentation of a TVMP (the new R1) is revised.
Additionally the SDT assigned Time Horizons, Violation Risk Factors, and Violation
Severity Levels. Do you agree? If not, please explain and propose an alternative.
Agree
Disagree
Comments:
2.
As stated in the background information above, in response to industry comments,
the Requirement for implementation of Imminent Threat process/procedure (the
new R2) is revised. Additionally the SDT assigned Time Horizons, Violation Risk
Factors, and Violation Severity Levels. Do you agree? If not, please explain and
propose an alternative.
Agree
Disagree
Comments:
3.
As stated in the background information above, in response to industry comments,
the Requirement for conducting Vegetation Inspections (the new R3) is revised.
Additionally the SDT assigned Time Horizons, Violation Risk Factors, and Violation
Severity Levels. Do you agree? If not, please explain and propose an alternative.
Agree
Disagree
Comments:
4.
As stated in the background information above, in response to industry comments,
the Requirement for preventing vegetation encroachments (the new R4) is
revised. Additionally the SDT assigned Time Horizons, Violation Risk Factors, and
Violation Severity Levels. Do you agree? If not, please explain and propose an
alternative.
Agree
Disagree
Comments:
5.
As stated in the background information above, in response to industry comments,
the Requirement for preventing Sustained Outages due to grow-ins on IROL or
Major WECC Transfer Paths (the new R5) is developed. Additionally the SDT
assigned Time Horizons, Violation Risk Factors, and Violation Severity Levels. Do
you agree? If not, please explain and propose an alternative.
Agree
Page 4 of 7
Unofficial Comment Form — Transmission Vegetation Management Standard FAC-003-2
(Project 2007-07)
Disagree
Comments:
6.
As stated in the background information above, in response to industry comments,
the Requirement for preventing Sustained Outages due to grow-ins on non-IROL
or Major WECC Transfer Paths (the new R6) is developed. Additionally the SDT
assigned Time Horizons, Violation Risk Factors, and Violation Severity Levels. Do
you agree? If not, please explain and propose an alternative.
Agree
Disagree
Comments:
7.
As stated in the background information above, in response to industry comments,
the Requirement for preventing Sustained Outages due to blowing together of
vegetation and transmission line conductors (the new R7) is developed.
Additionally the SDT assigned Time Horizons, Violation Risk Factors, and Violation
Severity Levels. Do you agree? If not, please explain and propose an alternative.
Agree
Disagree
Comments:
8.
As stated in the background information above, in response to industry comments,
the Requirement for preventing Sustained Outages due to fall-ins of vegetation
(the new R8) is developed. Additionally the SDT assigned Time Horizons, Violation
Risk Factors, and Violation Severity Levels. Do you agree? If not, please explain
and propose an alternative.
Agree
Disagree
Comments:
9.
As stated in the background information above, in response to industry comments,
the Requirement for implementation of annual work plan (the new R9) is
developed. Additionally the SDT assigned Time Horizons, Violation Risk Factors,
and Violation Severity Levels. Do you agree? If not, please explain and propose an
alternative.
Agree
Disagree
Comments:
10.
As stated in the background information above, in response to industry comments,
the Requirement for the preparation of list for sub 200kV transmission lines by the
Page 5 of 7
Unofficial Comment Form — Transmission Vegetation Management Standard FAC-003-2
(Project 2007-07)
Planning Coordinator (the new R10) is developed. Additionally the SDT assigned
Time Horizons, Violation Risk Factors, and Violation Severity Levels. Do you agree?
If not, please explain and propose an alternative.
Agree
Disagree
Comments:
11.
As stated in the background information above, in response to industry comments,
the Requirement for the Planning Coordinator to document method for
identification of applicable sub-200kV transmission lines (the new R11) is
developed. Additionally the SDT assigned Time Horizons, Violation Risk Factors,
and Violation Severity Levels. Do you agree? If not, please explain and propose an
alternative.
Agree
Disagree
Comments:
12.
The SDT received suggestions from commenters to re-sequence the requirements
contained in the standard to improve the logical flow of this document. The SDT
submits for consideration a proposed alternative sequence. Do you agree with the
proposed alternative sequencing? If not, please recommend a suggested
sequence.
Proposed Alternative
Sequence
Current
Sequence
Description
R1
R11
PC to document method to determine sub 200kV lines
R2
R10
PC to prepare list of sub 200kV lines
R3
R1
Document TVMP
R4
R3
Conduct Vegetation Inspections
R5
R9
Implement Annual Work Plan
R6
R2
Implement Imminent Threat
R7
R4
Prevent Vegetation Encroachments
R8
R8
Prevent Fall-in Outages
R9
R7
Prevent Blow-in Outages
R10
R6
Prevent Grow-in Outages (non-IROL lines)
R11
R5
Prevent Grow-in Outages (IROL lines)
* If the standard is re-sequenced, it will be reflected in the next version.
Agree
Disagree
Page 6 of 7
Unofficial Comment Form — Transmission Vegetation Management Standard FAC-003-2
(Project 2007-07)
Comments:
13.
The Implementation Plan proposes an effective date that gives entities at least a
year to become fully compliant. Do you agree with this implementation plan? If
not, please indicate what should be changed and indicate why.
Agree
Disagree
Comments:
14.
Do you have further questions about the standard that the Technical Reference
document (White Paper) does not clear up? If so, please elaborate and propose
additions.
Comments:
15.
As stated in the background information above, in response to industry comments,
the applicability section is revised to replace Reliability Coordinator with Planning
Coordinator. Do you agree with these changes? If not, please explain and propose
an alternative.
Agree
Disagree
Comments:
16.
As stated in the background information above, in response to industry comments,
changes were made to the definitions. Do you agree with these changes? If not,
please explain and propose an alternative.
Agree
Disagree
Comments:
17.
When compared to Version 1, does this proposed Version 2 of the standard either
maintain or improve overall electric reliability? Please provide a technical basis for
your response?
V2 Does maintain or improve overall reliability
V2 Does not maintain or improve overall reliability
Comments:
18.
Besides the comments you have already provided for the preceding questions, do
you have further suggestions for improving this standard? If so, please elaborate.
Comments:
Page 7 of 7
Transmission Vegetation Management
NERC Standard FAC-003-2 Technical
Reference
Prepared by the North American Electric Reliability Corporation
Vegetation Management Standard Drafting Team
September, 2009
NERC Standard FAC-003-2 Technical Reference
Table of Contents
INTRODUCTION ...................................................................................................................................... 3
DISCLAIMER ............................................................................................................................................ 4
DEFINITION OF TERMS ......................................................................................................................... 5
APPLICABILITY OF THE STANDARD ................................................................................................. 8
TRANSMISSION VEGETATION MANAGEMENT PROGRAM........................................................ 10
METHODS TO CONTROL VEGETATION........................................................................................................ 11
ANSI A300 – BEST MANAGEMENT PRACTICES FOR TREE CARE OPERATIONS .......................................... 12
VEGETATION INSPECTION FREQUENCY ...................................................................................................... 17
ANNUAL PLANS ......................................................................................................................................... 18
VEGETATION IMMINENT THREAT PROCEDURE........................................................................................... 20
IMPLEMENT IMMINENT THREAT PROCEDURE ............................................................................ 28
CONDUCT VEGETATION INSPECTIONS .......................................................................................... 29
ENCROACHMENTS WITHIN THE “MINIMUM VEGETATION CLEARANCE DISTANCES” .... 30
SUSTAINED OUTAGES — VEGETATION GROWING INTO CONDUCTOR ................................ 32
SUSTAINED OUTAGES — VEGETATION AND CONDUCTOR BLOWING TOGETHER............ 35
SUSTAINED OUTAGES — VEGETATION FALLING INTO CONDUCTOR................................... 37
IMPLEMENT ANNUAL WORK PLAN................................................................................................. 39
DESIGNATING SUB-200KV LINES ..................................................................................................... 40
DOCUMENTING METHOD OF IDENTIFYING SUB-200KV LINES................................................ 41
APPENDIX ONE: CLEARANCE DISTANCE DERIVATION BY THE GALLET EQUATION ...... 42
LIST OF ACRONYMS AND ABBREVIATIONS ................................................................................. 49
REFERENCES ......................................................................................................................................... 50
FAC-003-2 Technical Reference
September, 2009
2
NERC Standard FAC-003-2 Technical Reference
Introduction
This document is intended to provide supplemental information and guidance for complying with
the requirements of Reliability Standard FAC-003-2. It is a supporting document and provides
explanatory background to the requirements of the Standard. The intentions of the Standard
Drafting Team in developing many key areas of this Revision are also explained in this
document.
The purpose of the Standard is to improve the reliability of the electric transmission system by
preventing those vegetation related outages that could lead to Cascading.
Compliance with the Standard is mandatory and enforceable.
FAC-003-2 Technical Reference
September, 2009
3
NERC Standard FAC-003-2 Technical Reference
Disclaimer
This supporting document may explain or facilitate implementation of reliability standard FAC003-2 — Transmission Vegetation Management but does not contain any additional mandatory
requirements subject to compliance review.
FAC-003-2 Technical Reference
September, 2009
4
NERC Standard FAC-003-2 Technical Reference
Def inition of Terms
Active Transmission Line Right of Way* — A strip of land that is occupied by active
transmission facilities. This corridor does not include the inactive Right of Way or unused part of
the Right of Way intended for other facilities.
Examples of inactive or unused portions of corridors include:
1) The portions of the right of way acquired to accommodate future facilities. Power
plant exits are examples where large rights of way are obtained for maximum corridor
utilization and may currently have fewer lines constructed.
2) The portion of the right of way where corridor edge zones (i.e., buffer zones) are
provided for vegetation to exist.
3) The portions of the right of way where double-circuit structures are installed but only
one circuit is currently strung with conductors.
4) Portions of the right of way with deactivated transmission lines that are unavailable
for service.
Vegetation Inspection** — The systematic examination of vegetation conditions on an Active
Transmission Line Right of Way. This inspection may be combined with a general line
inspection. The inspection includes the documentation of any vegetation that may pose a threat
to reliability prior to the next planned inspection or maintenance work, considering the current
location of the conductor and other possible locations of the conductor due to sag and sway for
rated conditions.
*To be added to the NERC glossary of terms with final approval of this standard revision
** This term is listed in the NERC glossary of terms, but has been modified for the purposes of
this standard and is to be modified in the NERC glossary of terms with final approval of this
standard revision
FAC-003-2 Technical Reference
September, 2009
5
NERC Standard FAC-003-2 Technical Reference
Figure 1
Figure 2
FAC-003-2 Technical Reference
September, 2009
6
NERC Standard FAC-003-2 Technical Reference
Figure 3
FAC-003-2 Technical Reference
September, 2009
7
NERC Standard FAC-003-2 Technical Reference
Applicability of the Standard
4.
Applicability:
Functional Entities:
Transmission Owner
Planning Coordinator
Facilities:
Transmission lines (“applicable lines”) operated at 200kV or higher, and
transmission lines operated below 200kV designated by the Planning Coordinator as
being subject to this standard including but not limited to those that cross lands
owned by federal1, state, provincial, public, private, or tribal entities.
Transmission lines operated below 200kV designated by the Planning Coordinator as
being subject to this standard become subject to this standard 12 months after the
date the Planning Coordinator initially designates the transmission line as being
subject to this standard.
Existing transmission lines operated at 200kV or higher which are newly acquired by
a Transmission Owner and were not previously subject to this standard, become
subject to this standard 12 months after the acquisition date of the transmissions
lines.
1
EPAct 2005 section 1211c: “Access approvals by Federal agencies”
The reliability objective of this NERC Vegetation Management Standard (“Standard”) is to
prevent vegetation-related outages which could lead to Cascading by effective vegetation
maintenance while recognizing that certain outages such as those due to vandalism, human errors
and acts of nature are not preventable. Operating experience clearly indicates that trees that have
grown out of specification could contribute to a cascading grid failure, especially under heavy
electrical loading conditions.
Serious outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations. To
properly reduce and manage this risk, it is necessary to apply the Standard to applicable lines on
any kind of land or easement, whether they are Federal Lands, state or provincial lands, public or
private lands, franchises, easements or lands owned in fee. For the purposes of the Standard and
this technical paper, the term “public lands” includes municipal lands, village lands, city lands,
and a host of other governmental entities.
The Standard addresses vegetation management along applicable overhead lines that serve to
connect one electric station to another. However, it is not intended to be applied to lines sections
inside the electric station fence or other boundary of an electric station or underground lines.
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The Standard is intended to reduce the risk of Cascading involving vegetation. It is not intended
to prevent customer outages from occurring due to tree contact with all transmission lines and
voltages. For example, localized customer service might be disrupted if vegetation were to make
contact with a 69kV transmission line supplying power to a 12kV distribution station. However,
this Standard is not written to address such isolated situations which have little impact on the
overall Bulk Electric System. In fact, the inclusion of such a transmission line (which does not
lead to the undesirable conditions listed in Requirement R11) on the Planning Coordinator’s list
of sub-200kV lines may constitute a violation of Requirement R11.
Vegetation growth is constant and always present. Unmanaged vegetation poses an increased
outage risk when numerous transmission lines are operating at or near their Rating. This poses a
significant risk of multiple line failures and Cascading. On the other hand, most other outage
causes (such as trees falling into lines, lightning, animals, motor vehicles, etc.) are statistically
intermittent. The probability of occurrence of these events is not dependent on heavy loads.
There is no cause-effect relationship which creates the probability of simultaneous occurrence of
other such events. Therefore these types of events are highly unlikely to cause large-scale grid
failures.
In preparing the original vegetation management standard in 2005, industry stakeholders set the
threshold for applicability of the standard at 200kV. This was because an unexpected loss of
lines operating at above 200kV has a higher probability of initiating a widespread blackout or
cascading outages compared with lines operating at less than 200kV. Thus, the 200kV threshold
was an arbitrary proxy for those circuits whose Sustained Outage might lead to a Cascade.
The NERC vegetation management standard FAC-003-1 also allowed for application of the
standard to “critical” circuits (critical from the perspective of initiating widespread blackouts or
cascading outages) operating below 200kV. While the percentage of these circuits is relatively
low, it remains a fact that there are sub-200kV circuits whose loss could contribute to a
widespread outage. Given the very limited exposure and unlikelihood of a major event related to
these lower-voltage lines, it would be an imprudent use of resources to apply the Standard to all
sub-200kV lines. The drafting team, after evaluating several alternatives, selected the Planning
Coordinator as the best entity to determine applicable lines below 200kV that are subject to this
standard in a time horizon that best matches requirements for vegetation management methods.
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Transmission Vegetation Management Program
R1.
Each Transmission Owner shall have a documented transmission vegetation management
program that describes how it conducts work on its Active Transmission Line Rights of
Way to prevent Sustained Outages due to vegetation, considering all possible locations
the conductor may occupy under the effects of sag and sway throughout its operating
range under rated conditions. The transmission vegetation management program shall:
[Violation Risk Factor: Lower][Time Horizon: Long-term planning]
M1.
The Transmission Owner has a documented transmission vegetation management
program (paper or electronic copy of dated, current, in force document with specified
elements) that describes how it conducts work on its Active Transmission Line Rights of
Way to prevent Sustained Outages due to vegetation, considering all possible locations
the conductor may occupy under the effects of sag and sway throughout its operating
range under rated conditions. (R1)
The purpose of the Standard is to prevent vegetation-related outages that can result in Cascading.
Under Requirement R1, each Transmission Owner is required to have a transmission vegetation
management program (TVMP) designed to control vegetation on the Active Transmission Line
Right of Way. The TVMP is an important component of the Standard because it is the formal
document that Transmission Owners use to manage vegetation to achieve the purpose of the
Standard. An adequate TVMP formally establishes the guidelines that are used by the
Transmission Owner to plan and perform vegetation work that is necessary to prevent
transmission outages and minimize risk to the transmission system.
Requirement R1 is concerned with the content of the TVMP and supporting documents, but does
not address implementation of the elements of the TVMP. Other requirements address
implementation of the TVMP. For example, sub-part 1.2 requires Transmission Owners to
specify a vegetation inspection frequency. However, sub-part 1.2 does not address
implementation of the inspection. This is addressed in Requirement R3.
The numbered “Parts” of Requirement 1 are elements of Requirement 1 and, while these parts
identify performance that is mandatory, these parts do not constitute separate Requirements. For
assessing compliance, each requirement has a single Violation Risk Factor and a single set of
Violation Severity Levels so that compliance is assessed with the requirement, “in total.”
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Methods to Control Vegetation
R1
1.1 The transmission vegetation management program shall specify the methods that
the Transmission Owner may use to control vegetation.2
2
ANSI A300, Tree Care Operations — Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices, while not a
requirement of this standard, is considered to be an industry best practice.
M1
1.1 The Transmission Owner’s transmission vegetation management program
documentation specifies the methods that the Transmission Owner may use to
control vegetation.
Each Transmission Owner is required to specify the methods used to control vegetation on
applicable lines in its transmission vegetation management program. The methods specified in
the transmission vegetation management program under this requirement are the methods that
will be applied to the development and implementation of the annual work plan (1.3 and R9).
The intent of Requirement R1, Part 1.1 is for the Transmission Owner to list and generally
describe the vegetation management methods that are used on its Active Transmission Line
Rights of Way. Transmission Owners are not required to deploy each of the methods listed in
every situation. Nor are they required to provide a detailed description of each method, although
these may exist in the Transmission Owner’s specifications. Instead, the methods listed under
this requirement are intended to provide a menu of vegetation management options that the
Transmission Owner may deploy when developing and implementing its annual work plan based
upon the many different circumstances that are typically encountered.
Pruning is an inefficient maintenance method. Removal is always superior to pruning in
ensuring tree conflicts do not occur.
In general, the best management practice for the Transmission Owner is to exercise its maximum
legal rights to achieve the objectives of the transmission vegetation management program. This
minimizes the possibility of conflicts between energized conductors and vegetation. Since this is
not always possible, the Transmission Owner’s strategy should be to use its prescribed
vegetation maintenance methods to work towards or achieve the maximum use of the Active
Transmission Line Right of Way.
The following are several examples of how methods could be specified in the transmission
vegetation management program under this requirement. These are offered as examples only and
numerous other methods could be included in the transmission vegetation management program.
More detailed descriptions would typically be included in the Transmission Owner’s internal
specifications and procedures. In summary, methods must be applied in a sound biological
manner.
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Mechanical Clearing — Remove all trees and brush in the Active Transmission Line Right of
Way. Cut or mow all stumps to 3 inches or less above grade. De-limb and windrow on the edge
of the right of way those larger trees that could be obstructive to other line maintenance
activities.
Selective Mechanical Tree Removal — Selectively remove with chain saws or mechanized
equipment all tall-growing species of trees, as listed in the specifications. Chemically treat the
stumps of re-sprouting trees with the herbicide mixtures identified in the specification within one
hour of making the cut. All low-growing species of shrubs and trees, as listed in the
specification, will be preserved unless otherwise noted.
Low-Volume Foliar Selective Herbicide Treatment — Selectively treat with herbicide all tallgrowing species of trees as listed in the specification which are less than ten feet in height, using
the low-volume foliar herbicide mixture and application process listed in the specification. All
low-growing species of shrubs and trees, as listed in the specification will be preserved unless
otherwise noted.
Side Pruning — Prune trees adjacent to the Active Transmission Line Right of Way that have
grown to an extent that they have encroached upon or will soon encroach upon the clearances
listed in the specification. In cases where specified clearances can not be achieved due to Active
Transmission Line Right of Way width restrictions, remove branches to prevent entry into the
Active Transmission Line Right of Way.
ANSI A300 – Best Management Practices for Tree Care Operations
Transmission Owners have the option of adopting the procedures and practices contained in an
industry-recognized ANSI Standard known as A300 for use as a central component of its
vegetation management program. The following is a description of A300.
Introduction
Integrated Vegetation Management (IVM) is a best management practice conveyed in the
American National Standard for Tree Care Operations, Part 7 (ANSI 2006) and the International
Society of Arboriculture’s Best Management Practices: Integrated Vegetation Management
(Miller 2007). IVM is consistent with the requirements in FAC-003-02, and it provides
practitioners with what industry experts consider to be the most appropriate techniques to apply
to electric right of way projects in order to exceed those requirements.
IVM is a system of managing plant communities whereby managers set objectives, identify
compatible and incompatible vegetation, consider action thresholds, and evaluate, select and
implement the most appropriate control method or methods to achieve set objectives. The choice
of control method or methods should be based on their environmental impact and anticipated
effectiveness, along with site characteristics, security, economics, current land use and other
factors.
Planning and Implementation
Best management practices provide a systematic way of planning and implementing a vegetation
management program. While designed primarily with transmission systems in mind, it is also
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applicable to distribution projects. As presented in ANSI A300 part 7 and the ISA best
management practices, IVM consists of 6 elements:
1)
2)
3)
4)
5)
6)
Set Objectives
Evaluate the Site
Define Action Thresholds
Evaluate and Select Control Methods
Implement IVM
Monitor Treatment and Quality Assurance
The setting of objectives, defining action thresholds, and evaluating and selecting control
methods all require decisions. The planning and implementation process is cyclical and
continuous, because vegetation is dynamic and managers must have the flexibility to adjust their
plans. Adjustments may be made at each stage as new information becomes available and
circumstances evolve.
Set Objectives
Objectives should be clearly defined and documented. Examples of objectives can
include promoting safety, preventing outages caused by vegetation growing into electric
facilities and minimizing them from trees growing outside the right of way, maintaining
regulatory compliance, protecting structures and security, restoring electric service during
emergencies, maintaining access and clear lines of sight, protecting the environment, and
facilitating cost effectiveness.
Objectives should be based on site factors, such as workload and vegetation type, in
addition to available human, equipment and financial resources. They will vary from
utility to utility and project to project, depending on line voltage and criticality, as well as
topographical, environmental, fiscal and political considerations. However, where it is
appropriate, the overriding focus should be on environmentally-sound, cost effective
control of species that potentially conflict with the electric facility, while promoting
compatible, early successional, sustainable plant communities.
Work Load Evaluations
Work-load evaluations are inventories of vegetation that could have a bearing on
management objectives. Work load assessments can capture a variety of vegetation
characteristics, such as location, height, species, size and condition, hazard status, density
and clearance from conductors. Assessments should be conducted considering voltage,
conductor sag from ambient temperatures and loading, and the potential influence of
wind on line sway.
Evaluations can be comprehensive or point sample, and can be done to obtain
information on an entire program or an individual project. Comprehensive evaluations
account for vegetation that could potentially affect management objectives, including
hazard trees. Program-level comprehensive evaluations can be made of all target
vegetation on a system, while project-level evaluations focus on vegetation relevant to a
specific job. Comprehensive evaluations provide the advantage of supplying a complete
set of data upon which to base management decisions. On the other hand, comprehensive
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surveys can be impractical for utilities with large numbers of trees, limited human and
financial resources, or both.
Point sampling offers an alternative for utilities for which comprehensive inventories are
impractical. Point sampling is cost effective, and has a proven track record for
reasonable accuracy. A common method involves dividing a management area (a system
or project) into equal-sized units and selecting a random sample sufficient to statistically
represent the total work quantity. Random selection eliminates the chance of bias on the
part of the investigator. Every plant or plant community of interest within each selected
area is inventoried, with collected data used to forecast the total workload.
Evaluate and Select Control Methods
Control methods are the process through which managers achieve objectives. The most
suitable control method best achieves management objectives at a particular site. Many
cases call for a combination of methods. Managers have a variety of controls from which
to choose, including manual, mechanical, herbicide and tree growth regulators,
biological, and cultural options.
Manual Control Methods
Manual methods employ workers with hand-carried tools, including chainsaws,
handsaws, pruning shears and other devices to control incompatible vegetation. The
advantage of manual techniques is that they are selective and can be used where others
may not be. On the other hand, manual techniques can be inefficient and expensive
compared to other methods. If pruning is necessary, it should comply with ANSI A300
Part 1 (ANSI 2001) and ISA best management practices for utility pruning (Kempter
2004).
Mechanical Control Methods
Mechanical controls are done with machines. They are efficient and cost effective,
particularly for clearing dense vegetation during initial establishment, or reclaiming
neglected or overgrown rights of way. On the other hand, mechanical control methods
can be non-selective and disturb sensitive sites.
Tree Growth Regulator and Herbicide Control Methods
Tree growth regulators and herbicides are essential for effective vegetation management.
Tree growth regulators (TGRs) are designed to reduce growth rates by interfering with
natural plant processes. TGRs can be helpful where removals are prohibited or
impractical by reducing the growth rates of some fast-growing species.
Herbicides control plants by interfering with specific botanical biochemical pathways.
Herbicide use can control individual plants that are prone to re-sprout or sucker after
removal. When trees that re-sprout or sucker are removed without herbicide treatment,
dense thickets develop, impeding access, swelling workloads, increasing costs, blocking
lines-of-site, and deteriorating wildlife habitat. Treating suckering plants allows early
successional, compatible species to dominate the right of way and out-compete
incompatible species, ultimately reducing work.
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Cultural Control Methods
Cultural methods modify habitat to discourage incompatible vegetation and establish and
manage desirable, early successional plant communities. Cultural methods take
advantage of seed banks of native, compatible species lying dormant on site. In the long
run, cultural control is the most desirable method where it is applicable.
A cultural control known as cover-type conversion provides a competitive advantage to
short-growing, early successional plants, allowing them to thrive and eventually outcompete unwanted tree species for sunlight, essential elements and water. The early
successional plant community is relatively stable, tree-resistant and reduces the amount
of work, including herbicide application, with each successive treatment.
Wire-Border Zone
The wire-border zone technique is a management philosophy that can be applied through
cultural control. W.C. Bramble and W.R. Byrnes developed it in the mid-1980s out of
research begun in 1952 on a transmission right of way in the Pennsylvania State Game
Lands 33 Research and Demonstration project (Yahner and Hutnik (2004).
The wire zone is the section of a utility transmission right of way directly under the wires
and extending outward about 10 feet on each side. The wire zone is managed to promote
a low-growing plant community dominated by grasses, herbs and small shrubs (under 3
feet in height at maturity). The border zone is the remainder of the right of way. It is
managed to establish small trees and tall shrubs (under 25 feet in height at maturity).
When properly managed, diverse, tree-resistant plant communities develop in wire and
border zones. The communities not only protect the electric facility and reduce long-term
maintenance, but also enhance wildlife habitat, forest ecology and aesthetic values.
Although the wire-border zone is a best practice in many instances, it is not necessarily
universally suitable. For example, standard wire-border zone prescriptions may be
unnecessary where lines are high off the ground, such as across low valleys or canyons,
so the technique can be modified without sacrificing reliability.
One way to accommodate variances in topography is to establish different regions based
on wire height. For example, over canyon bottoms or other areas where conductors are
100 feet or more above the ground, only a few trees are likely to be tall enough to conflict
with the lines. In those cases, trees that potentially interfere with the transmission lines
can be removed selectively on a case-by-case basis.
In areas where the wire is lower, perhaps between 50-100 feet from the ground, a border
zone community can be developed throughout the right of way. Note that in many cases,
conductor attachment points are more than 50 feet off the ground, so a border zone
community can be cultivated near structures. Where the line is less than 50 feet off the
ground, managers could apply a full wire-border zone prescription.
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An environmental advantage of this type of modification is stream protection. Streams
often course through the valleys and canyons where lines are likely to be elevated.
Leaving timber or border zone communities in canyon bottoms helps shelter this valuable
habitat, enabling managers to achieve environmentally sensitive objectives.
Implement Integrated Vegetation Management (IVM)
All laws and regulations governing IVM practices and specifications written by qualified
vegetation managers must be followed. IVM control methods should be implemented on
regular work schedules, which are based on established objectives and completed
assessments. Work should progress systematically, using control measures determined to
be best for varying conditions at specific locations along a right of way. Some
considerations used in developing schedules include the importance and type of line,
vegetation clearances, work loads, growth rate of predominant vegetation, geography,
accessibility, and in some cases, time lapsed since the last scheduled work.
Clearances Following Work
Clearances following work should be sufficient to meet management objectives,
including preventing trees from entering the Minimum Vegetation Clearance Distance,
electric safety risks, service-reliability threats and cost.
Monitor Treatment and Quality Assurance
An effective program includes documented processes to evaluate results. Evaluations
can involve quality assurance while work is underway and after it is completed.
Monitoring for quality assurance should begin early to correct any possible
miscommunication or misunderstanding on the part of crewmembers. Early and
consistent observation and evaluation also provides an opportunity to modify the plan, if
need be, in time for a successful outcome.
Utility vegetation management programs should have systems and procedures in place
for documenting and verifying that vegetation management work was completed to
specifications. Post-control reviews can be comprehensive or based on a statistically
representative sample. This final review points back to the first step and the planning
process begins again.
Summary
IVM offers among others, a systematic way of planning and implementing a vegetation
management program as presented in ANSI A300 Part 7. This methodology enables a program
to comply with the NERC Transmission Vegetation Management Program standard (FAC-0032). Managers should select control options to best promote management objectives.
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Vegetation Inspection Frequency
R1
1.2 The transmission vegetation management program shall specify a Vegetation
Inspection frequency of at least once per calendar year that takes into account local4
and environmental factors.
M1
1.2 The Transmission Owner’s transmission vegetation management program
documentation specifies a Vegetation Inspection frequency of at least once per
calendar year that takes into account local and environmental factors.
4
Local factors include items such as treatment cycle, extent and type of treatment, and their relationship to the
normal growth rate.
The Transmission Owner’s Transmission Vegetation Management Program (TVMP) shall
specify the frequency of vegetation inspections. The inspection frequency is required to be at
least once per calendar year. Transmission Owners should consider local and environmental
factors that could warrant more frequent inspections. Such factors may include anticipated
growth rates of the local vegetation, length of the growing season for the geographical area,
limited Active Transmission Line Right of Way widths, rainfall amounts, etc.
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Annual Plans
R1
1.3.
The transmission vegetation management program shall require an annual work
plan. An annual work plan shall:
1.3.1 Identify the applicable lines to be maintained
1.3.2 Identify the work to be performed and methods to be used
1.3.3 Be flexible to adjust to changing conditions and to findings from Vegetation
Inspections. Adjustments to the plan within the year are permissible.
1.3.4 Take into consideration permitting and scheduling requirements from
landowners or regulatory authorities.
M1
1.3
The Transmission Owner’s transmission vegetation management program contains
an annual work plan which:
1.3.1 Identifies the applicable lines to be maintained
1.3.2 Identifies the work to be performed and the methods used
1.3.3 Shows flexibility to adjust to changing conditions and to findings from
Vegetation Inspections
1.3.4 Considers permitting and scheduling requirements from landowners or
regulatory authorities
The work plan is not intended to be a “span-by-span” detailed description of all work to be
performed. It is intended to require the Transmission Owner to annually plan and schedule
vegetation work to prevent encroachment into the Minimum Vegetation Clearance Distance.
Work plans can vary in their level of detail.
The flexibility to adjust the annual work plan in response to changing conditions must not be
invoked in a manner that adversely impacts reliability. The intent of the standard drafting team
was to allow adjustments for changing conditions of the vegetation on the Active Transmission
Line ROW, emergencies, and other significant changing conditions, and not for budget
constraints. Annual work plan adjustments must always ensure the reliability of the electric
transmission system.
This Standard requires that the annual work plan be flexible to allow the Transmission Owner to
change priorities during the year as conditions or situations dictate. For example, weather
conditions (drought) could make herbicide application ineffective during the plan year. Another
situational variance could be a major storm that redirects local resources away from planned
maintenance. This situation may also include complying with mutual assistance agreements by
moving resources off the Transmission Owner’s system to work on another system. Examples of
adjustments may include deferrals or additions to the annual work plan.
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The drafting team cites the following conditions that may result in adjustments to the annual
work plan: abnormal weather such as drought, major storms, excessive rainfall, other
environmental conditions such as infestation, disease, fire, etc. These conditions may be found as
part of a special or scheduled Vegetation Inspection. Examples of annual work plan adjustments
that are permitted may include revising the work plan priorities, rescheduling work to another
time or selecting alternate vegetation control methods. Changes in land usage made by a property
owner, such as timber clearing, may be another condition that warrants an adjustment.
When developing the annual work plan the Transmission Owner should allow time for
procedural requirements to obtain permits to work on federal, state, provincial, public, tribal
lands. In some cases the lead time for obtaining permits may necessitate preparing work plans
more than a year prior to work start dates. Transmission Owners may also need to consider those
special landowner requirements as documented in easement instruments.
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Vegetation Imminent Threat Procedure
R1.
1.4
The transmission vegetation management program shall require a process or
procedure for response to an imminent threat of a vegetation-related Sustained
Outage. The process or procedure shall specify actions which shall include
communication of the threat to the responsible control center.
1.4
The Transmission Owner’s transmission vegetation management program
documentation specifies an imminent threat process or procedure for responding to
imminent threats of a vegetation-related Sustained Outage including communication
of the threat to the responsible control center.
M1.
The term “imminent threat” refers to a vegetation condition which is likely to cause a Sustained
Outage at any moment. An imminent threat requires immediate action by the Transmission
Owner to alert the responsible control center (usually the Transmission Operator) that there is an
increased probability of the occurrence of a Sustained Outage.
Two key elements of an acceptable imminent threat process or procedure are outlined below:
Specify the vegetation-related conditions that warrant a response:
Examples of these vegetation-related conditions include vegetation that is near or
encroaching into the MVCD (growth issue) or vegetation that presents an imminent
danger of falling into the transmission conductor (fall-in issue).
Notify the responsible control center:
So that the responsible control center holds situational awareness of known risks to
the power system, the Transmission Owner has the responsibility to ensure the proper
communication between field personnel and the responsible control center. This will
allow the responsible control center to take the appropriate action until the threat is
relieved. Appropriate actions may include, but are not limited to, a temporary
reduction in the line loading, or switching the line out of service.
The protocol for contacting the responsible control center should be defined. For
example, some Transmission Owners’ processes may require a call directly to the
responsible control center, while other Transmission Owners may require a call to a
supervisor or field forester who will in turn notify the responsible control center .
The urgency of vegetation-related imminent threats may be contrasted with the longer time
frames of interim corrective action plans which are developed from a corrective action process as
defined in Requirement R1, Part 1.5.
The imminent threat process or procedure should be implemented in terms of minutes or hours as
opposed to a longer time frame for interim corrective action plans.
All serious growth or fall-in vegetation-related conditions are not necessarily considered
imminent threats under the Standard. For example, some Transmission Owners may have a
danger tree identification program that identifies for removal trees with the potential to fall near
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the line. These trees are not necessarily considered imminent threats under the Standard unless
they pose an immediate fall-in threat.
Also, there can be situations involving vegetation that are not considered vegetation-related
imminent threats under the Standard. For example, a logging operation on or near the Active
Transmission Line Right of Way can pose an immediate threat of a sustained outage and result in
the initiation of an imminent threat process in the same manner as the presence of a nearby crane
or the notification of a hot-spot on a conductor connector. Although the logging threat in this
example tangentially involves vegetation, it is not considered a vegetation-related imminent
threat under the Standard.
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Interim Corrective Action Process
R1.
1.5. The transmission vegetation management program shall specify an interim corrective
action process for use when the Transmission Owner is temporarily constrained from
performing vegetation maintenance as planned.
M1
1.5
The Transmission Owner’s transmission vegetation management program
documentation specifies the interim corrective action process for use when the
Transmission Owner is temporarily constrained from performing vegetation
maintenance as planned.
The intent of this requirement is to deal with situations that temporarily prevent the Transmission
Owner from performing planned vegetation management work and, as a result, have the potential
to put the transmission line at risk. This is not intended to address situations where an alternate
work method can be substituted for the planned method. For example, a land owner may prevent
the planned use of chemicals but allow the use of mechanical clearing. In this case the
Transmission Owner can still perform work sufficient to eliminate the risk to the transmission
line and does not need an interim corrective action plan. However, in situations where
transmission line reliability is at risk due to a constraint and an alternate work method will not
suffice, the Transmission Owner is required to develop a specific interim corrective action plan
to mitigate the potential risk to the transmission line during the interim period.
The interim corrective action process should be flexible to provide a framework that can be
applied over a wide range of situations to ensure line reliability.
Elements of the interim corrective action process include:
Identifying locations where the Transmission Owner is constrained from performing
planned vegetation maintenance work.
Developing the specific plan to mitigate the risk associated with not performing the
vegetation maintenance work as planned.
Documenting and tracking the specific plan for each location.
Constraints to performing vegetation maintenance work as planned could result from legal
injunctions filed by property owners, the discovery of easement stipulations which limit the
Transmission Owner’s rights, or other circumstances.
In developing a specific plan to mitigate the risk to the transmission line, the Transmission
Owner could consider location-specific measures such as modifying inspection and/or
maintenance intervals. Where a legal constraint would not allow any vegetation work, the
interim corrective action plan could include limiting the loading on the transmission line.
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The Transmission Owner should document and track each specific corrective action work plan
by location. This location may be indicated as one span, one tree or a combination of spans on
one property where the constraint is considered to be temporary.
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Maintenance Strategies
R1.
1.6
The transmission vegetation management program shall specify the maintenance
strategies used (such as minimum vegetation-to-conductor distance or maximum
vegetation height) to ensure that Table 1 clearances in FAC-003-2-Attachment 1 are
never violated. The maintenance strategies shall consider the sag and sway of the
conductor throughout its operating range under rated conditions.
M1.
1.6
The Transmission Owner’s transmission vegetation management program
documentation specifies the maintenance strategies used (such as minimum
vegetation-to-conductor distance or maximum vegetation height) to ensure that
Table 1 clearances in FAC-003-2-Attachment 1 are never violated. The maintenance
strategies consider the sag and sway of the conductor throughout its operating range
under rated conditions.
For a Transmission Owner to develop a specific maintenance strategy, it is important to
understand the dynamics of a line conductor’s movement. First, the complexities inherent in
observing and predicting conductor movement, particularly for field personnel, will be
addressed. Then, some examples of maintenance strategies that take into account these
complexities will be described.
The phrase in Requirement R1 Part 1.6 that reads ". . . ensure that Table 1 clearances in FAC003-2-Attachment 1 are never violated.” is intended to require the TO to design its maintenance
strategies considering all possible locations of the conductor for rated design conditions, and not
to suggest that a compliance violation exists merely by a possible future proximity of the
conductor to vegetation. Requirement R4 indicates that a real-time MVCD encroachment will
result in a compliance violation.
Understanding Conductor Position and Movement
The conductor’s position in space at any point in time changes as a reaction to a number of
different loading variables. Vertical and horizontal conductor movement results from variations
in thermal and physical loads applied to the line. Thermal loading is a function of line current
and the combination of numerous variables influencing ambient heat dissipation including wind
velocity/direction, ambient air temperature and precipitation. Physical loading applied to the
conductor affects sag and sway by combining physical factors such as ice and wind loading
When calculating the range of conductor positions, the Transmission Owner should use the same
design criteria and assumptions that the Transmission Owner uses when establishing Ratings.
Typically, the greatest conductor movement is at mid-span. As the conductor moves through
various positions, a spark-over zone surrounding the conductor moves with it. The radius of the
spark-over zone may be found by referring to Table 1 (“Minimum Vegetation Clearance
Distances”) in the standard. For illustrations of this zone and conductor movements, Figures 4
through 6 on the following pages demonstrate these concepts. At the time of making a field
observation, however, it is very difficult to precisely know where the conductor is in relation to
its wide range of all possible positions. Therefore, Transmission Owners must adopt
maintenance strategies that account for this dynamic situation.
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NERC Standard FAC-003-2 Technical Reference
Selecting a Maintenance Strategy
To maintain adequate separation between vegetation and transmission line conductors, the
Transmission Owner must craft a maintenance strategy that keeps vegetation well away from the
spark-over zone mentioned above. In fact, it is generally necessary to incorporate a variety of
maintenance strategies. For example, one Transmission Owner may utilize a combination of
routine cycles, traditional Integrated Vegetation Management (IVM) techniques and long-term
planning. Another Transmission Owner may place a higher reliance on frequent inspections and
quick remediation as opposed to a cyclical approach. This variation of strategies is further
warranted when factors, such as terrain, legal and other constraints, vegetation types, and
climates, are considered in developing a Transmission Owner’s specific strategy to satisfying
this requirement.
The following is a sample description of one combination of strategies which may be utilized by
a Transmission Owner.
A Transmission Owner’s basic maintenance strategy could be to remove all incompatible
vegetation from the right of way if it has the right to do so and has no constraints. In
mountainous terrain, however, this strategy could change to one where the Transmission Owner
manages vegetation based on vegetation-to-conductor clearances, since it might not be necessary
to remove vegetation in a valley that is far below.
If faced with constraints and assuming a line design with sufficient ground clearance, the
Transmission Owner ’s strategy could then be to allow vegetation such as fruit trees, but perhaps
only up to a given height at maturity (perhaps 10 feet from the ground). If constraints cannot be
overcome and if design clearances are sufficient, an exception to the Transmission Owner’s 10foot guideline might be made. Finally, if the Transmission Owner has chosen to utilize
vegetation-to-conductor clearance distance methods, the Transmission Owner could have an
inspection regimen in place to regularly ensure that any impending clearance problems are
identified early for rectification.
Additional information regarding proper maintenance strategies for achieving and ensuring Table
I clearances can be found in the “Methods to Control Vegetation” and “Vegetation Inspection
Frequency” sections of this document.
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NERC Standard FAC-003-2 Technical Reference
Figure 4
CONDUCTOR SWAY (BLOWOUT)
DUE TO WIND
Figure 5
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NERC Standard FAC-003-2 Technical Reference
Cross-Section View of a Single Conductor
at a Given Point along the Span
Showing Six Possible Conductor Positions Due to Movement
Resulting from Thermal and Mechanical Loading
For Consideration in Developing a Maintenance Strategy
Figure 6
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NERC Standard FAC-003-2 Technical Reference
Implement Imminent Threat Procedure
R2.
Each Transmission Owner shall implement its imminent threat process or procedure
when the Transmission Owner has actual knowledge of such a threat, obtained through
normal operating practices. [Violation Risk Factor- Medium][Time Horizon – Real
Time]
M2.
The Transmission Owner has evidence of the implementation of its vegetation imminent
threat process or procedure showing what was done with dates and activities
accomplished. (R2)
Each Transmission Owner must implement its imminent threat process or procedure when the
Transmission Owner becomes aware of and confirms the existence of such a vegetation-related
threat. The Transmission Owner could learn of the threat through a variety of normal operating
practices, including routine line inspections, reports from landowners, observations made by
public safety agencies or other utilities, etc. If a situation requires the Transmission Owner to
implement its imminent threat process or procedure, it must retain some evidence of the threat
and its response as outlined by Measure M2.
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NERC Standard FAC-003-2 Technical Reference
Conduct Vegetation Inspections
R3. Each Transmission Owner shall conduct Vegetation Inspections of all applicable lines (as
measured in line miles) in accordance with the frequency specified in its transmission
vegetation management program, unless constrained by natural disasters4. When
constrained by a natural disaster, the Transmission Owner shall conduct the Vegetation
Inspection(s) within six months or a period agreed to by its Regional Entity, whichever is
greater. [Violation Risk Factor: Medium][Time Horizon: Operations Planning]
4
Examples include, but are not limited to, earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale,
major storms as defined either by the Transmission Owner or an applicable regulatory body, ice storms, and floods.
M3. The Transmission Owner has evidence that it conducted Vegetation Inspections in
accordance with Requirement R3.
This requirement is the implementation requirement for the Vegetation Inspections identified in
Requirement R1, Part 1.2. The Standard allows Vegetation Inspections to be performed in
conjunction with general line inspections. The inspections will be measured in line miles based
on the defined inspection frequency.
The measure of “line miles” was selected so that if a Transmission Owner were to fail to
completely inspect its system according to its stated frequency, an appropriate Violation Severity
Level would be determined based upon the percentage of the system that was actually inspected.
As an example, where a Transmission Owner operates 1,000 miles of 230kV transmission lines
with a stated Vegetation Inspection frequency (Requirement R1, Part 1.2) of twice per year; this
Transmission Owner will be responsible for inspecting all 1,000 miles of 230kV transmission
lines two times during the calendar year. This would yield a “total line miles inspection plan” of
2,000 miles for that calendar year.
Continuing with this example, if the Transmission Owner completed inspections of more than
1900 miles or 95% of its 2,000-mile but not 100% of the full 2000 miles, then, a VSL of
“Moderate” would be used in determining a sanction.
In the event that extensive resources are devoted to a lengthy service restoration following a
natural disaster on its own system or by assisting another utility, the Transmission Owner is
permitted to reasonably postpone its line inspections until the resource constraint is relieved.
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NERC Standard FAC-003-2 Technical Reference
Encroachments within the “Minimum Vegetation
Clearance Distances”
R4. Each Transmission Owner shall prevent encroachment of vegetation into the Minimum
Vegetation Clearance Distances (MVCD) listed in FAC-003-2-Attachment 1 for its
applicable lines as observed in real-time operating between no-load and their Rating, with
the following exceptions: [Violation Risk Factor VRF= Medium][Time Horizon – Real
Time]
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting from natural
disasters.4
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting from human
or animal activity.5
Brief encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting from
falling vegetation.
4
Examples include, but are not limited to, earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale,
major storms as defined either by the Transmission Owner or an applicable regulatory body, ice storms, and
floods.
5
Examples include, but are not limited to, logging, animal severing tree, vehicle contact with tree, arboricultural
activities or horticultural or agricultural activities, or removal or digging of vegetation.
M4. The Transmission Owner has evidence from inspections that indicate there was no
vegetation encroachment into the Minimum Vegetation Clearance Distances listed in FAC003-2-Attachment 1 for its applicable lines as observed in real-time operating between noload and their Rating, considering exceptions. (R4)
This requirement indicates that if a Transmission Owner observes vegetation at a distance less
than that prescribed in Table 1 of FAC-003-2-Attachment 1, it is in violation of this standard
since sparkover is likely to occur. Requirement R4 refers to observation in “real time”. This is
an actual field observation or measurement of the conductor-to-vegetation distance and is not to
be a calculated separation between the conductor and the vegetation
When possible encroachments of the MVCD are discovered through inspections or other means,
the Transmission Owner must take appropriate action, which might include initiating vegetation
management activities or implementation of its imminent threat process. If there is a confirmed
clearance violation, the Transmission Owner must report to the Regional Entity as appropriate.
Certain exceptions are recognized in the Standard, including provisions for natural disasters and
human or animal activity. Also, brief encroachments by falling vegetation are not considered to
be a violation.
This requirement applies to transmission lines that are operating within their Rating. If a line is
intentionally or inadvertently operated beyond its rating (potentially in violation of other
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NERC Standard FAC-003-2 Technical Reference
standards), the occurrence of a clearance encroachment would not be a violation of this Standard.
An encroachment of the MVCD that results from operation of a transmission line beyond its
recognized Rating (for example emergency actions taken by an operator to protect an
Interconnection) is beyond the scope of this standard.
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NERC Standard FAC-003-2 Technical Reference
Sustained Outages — Vegetation Growing Into
Conductor
R5. Each Transmission Owner shall prevent Sustained Outages6 of applicable lines that are
identified as an element of an Interconnection Reliability Operating Limit (IROL) (or
Major WECC Transfer Path) due to vegetation growing into a conductor operating
between no-load and its Rating, with the following exceptions: [Violation Risk Factor –
High][Time Horizon – Real Time]
Sustained Outages of applicable lines that result from natural disasters.4
Sustained Outages of applicable lines that result from human or animal activity.5
M5. The Transmission Owner’s self-certification reports are adequate evidence of no Sustained
Outage of any applicable line that is identified as an element of an IROL (or Major WECC
Transfer Path) due to vegetation growing into a conductor operating between no-load and
its Rating. (R5)
R6. Each Transmission Owner shall prevent Sustained Outages6 of applicable lines that are not
an element of an IROL (or Major WECC Transfer Path) due to vegetation growing into a
conductor operating between no-load and its Rating, with the following exceptions
[Violation Risk Factor – High][Time Horizon – Real Time]
Sustained Outages of applicable lines that result from natural disasters.4
Sustained Outages of applicable lines that result from human or animal activity.5
M6. The Transmission Owner’s self-certification reports are adequate evidence of no Sustained
Outage of any applicable line that is not identified as an element of an IROL (or Major
WECC Transfer Path) due to vegetation growing into a conductor operating between noload and its Rating. (R6)
4
Examples include, but are not limited to, earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale,
major storms as defined either by the Transmission Owner or an applicable regulatory body, ice storms, and
floods.
5
Examples include, but are not limited to, logging, animal severing tree, vehicle contact with tree, arboricultural
activities or horticultural or agricultural activities, or removal or digging of vegetation.
6
Multiple Sustained Outages on an individual line, if caused by the same vegetation, shall be considered as one
outage regardless of the actual number of outages within a 24-hour period.
Vegetation grow-in events have contributed to several major blackouts and present a potential
risk to the electric transmission system. Requirements R5 and R6 have been established to
convey the seriousness of an outage caused by a vegetation grow-in and to distinguish between
lines of differing impact to the system. Outages on certain lines are more likely to cause
Cascading than on others. Accordingly, R5 applies to lines associated with IROLs (or major
WECC transfer paths) and has been assigned a High Violation Risk Factor due to the higher
probability of leading to a Cascading event. R6 applies to lines which are not associated with an
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NERC Standard FAC-003-2 Technical Reference
IROL (or major WECC transfer path) and has been assigned a Medium Violation Risk Factor,
since outages on such lines are less likely to cause a Cascading event.
Planning Coordinators in planning time, and Reliability Coordinators in real time, determine
operating limits for circuits or groups of circuits that may impact interconnected system
reliability. The implication is that if these limits are exceeded; cascading, uncontrolled
separation, instability, or voltage collapse might occur. Therefore these circuits or groups of
circuits need to be protected from the risk of vegetation related outages. Planning Coordinators
are required to identify circuits or groups of circuits that make up an IROL in NERC Standard
FAC-010, Reliability Coordinators in FAC-011.
In the Western Interconnection there are some circuits or groups of circuits that do not meet the
definition of an IROL, but nonetheless are very important to that Interconnection. Theses circuits
or groups of circuits are classified as Major WECC Transfer Path(s) in the Western
Interconnection. These are found in NERC Standard TOP-007-WECC-1.
It is important to note that for a Sustained Outage to be classified as a vegetation-related event,
the conductor must be operating between no load and its Rating when the event occurs. Events
that occur when the conductor is operating beyond its Rating would not be classified as
vegetation-related Sustained Outages under the Standard.
Vegetation-related Sustained Outages that occur due to natural disasters are beyond the control
of the Transmission Owner. These events are not classified as vegetation-related Sustained
Outages and are therefore exempt from the Standard. Transmission lines are not designed to
withstand the impacts of natural disasters such as tornadoes, hurricanes, severe ice loads,
landslides, etc.
Sustained Outages due to human or animal activity are also beyond the control of the
Transmission Owner are not classified as vegetation-related Sustained Outages and are therefore
exempt from the Standard. Examples of these events may include new plantings of tall
vegetation under the transmission line planted since the last Vegetation Inspection, tree contacts
with line initiated by vehicles, logging activities, etc.)
Multiple Sustained Outages on an individual line can be caused by the same vegetation. Such
events within a 24 hour period are considered to be a single vegetation-related Sustained Outage
under the Standard. For example, a Sustained Outage caused by a tree could be mistakenly
attributed to something else (e.g. contaminated insulator string, lightning, etc). After the
apparent cause of the outage is addressed the line could be re-energized without the root cause
being identified and removed. The transmission line could remain energized for a period of time
while the thermal loading on the transmission line builds back to the point where the conductor
contacts the same tree that caused the earlier Sustained Outage. These multiple outages resulting
from the same tree would be considered as a single outage as long as all Sustained Outages
occurred within a 24 hour period.
The Transmission Owner must self-certify each year that all vegetation-related Sustained
Outages are documented and reported. If no vegetation-related Sustained Outages have
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NERC Standard FAC-003-2 Technical Reference
occurred, a null report is sufficient documentation of compliance with these requirements.
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NERC Standard FAC-003-2 Technical Reference
Sustained Outages — Vegetation and Conductor
Blowing Together
R7. Each Transmission Owner shall prevent Sustained Outages6 of applicable lines due to the
blowing together of vegetation and a conductor within an Active Transmission Line Right
of Way (operating within design blow-out conditions) with the following exception:
[Violation Risk Factor - Medium][Time Horizon - Real Time]
Sustained Outages of applicable lines that result from natural disasters4 or wind-blown
debris.
4
Examples include, but are not limited to, earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale,
major storms as defined either by the Transmission Owner or an applicable regulatory body, ice storms, and
floods.
6
Multiple Sustained Outages on an individual line, if caused by the same vegetation, shall be considered as one
outage regardless of the actual number of outages within a 24-hour period.
M7. The Transmission Owner’s self-certification reports are adequate evidence of no Sustained
Outage of any applicable line due to the blowing together of vegetation and a conductor
within the Active Transmission Line Right of Way. (R7)
This requirement is intended to prevent vegetation-related risk of a Cascading event on the
electric transmission system by requiring the Transmission Owner to manage vegetation such
that a vegetation-related Sustained Outage due to blowing together of vegetation and conductor
does not occur.
Again, for a Sustained Outage to be classified as a vegetation-related event, the conductor must
be operating between no load and its Rating when the event occurs. Events that occur when the
conductor is operating beyond its Rating are not classified as vegetation-related Sustained
Outages under the Standard. Also, this requirement clarifies that the conductor and the
vegetation must be within the Active Transmission Line Right of Way.
Vegetation-related Sustained Outages that occur due to natural disasters are beyond the control
of the Transmission Owner. These events are not classified as vegetation-related Sustained
Outages and are therefore exempt from the Standard. Transmission lines are not designed to
withstand the impacts of natural disasters such as tornadoes, hurricanes, severe ice loads,
landslides, etc. Additionally, Sustained Outages due to wind-blown debris, such as large limbs
and branches, separated tree tops, etc., are exempt from the Standard.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. Such
events within a 24 hour period are considered to be a single vegetation-related Sustained Outage
under the Standard. For example, a Sustained Outage caused by a tree could be mistakenly
attributed to something else (e.g. contaminated insulator string, lightning, etc). After the
apparent cause of the outage is addressed the line could be re-energized without the root cause
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NERC Standard FAC-003-2 Technical Reference
being identified and removed. The transmission line could remain energized for a period of time
while the thermal loading on the transmission line builds back to the point where the conductor
contacts the same tree that caused the earlier Sustained Outage. These multiple outages resulting
from the same tree would be considered as a single outage as long as all Sustained Outages
occurred within a 24 hour period.
The Transmission Owner must self-certify each year that all vegetation-related Sustained
Outages are documented and reported. If no vegetation-related Sustained Outages have
occurred, a null report is sufficient documentation of compliance.
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NERC Standard FAC-003-2 Technical Reference
Sustained Outages — Vegetation Falling Into
Conductor
R8. Each Transmission Owner shall prevent Sustained Outages6 of applicable lines due to
vegetation falling into a conductor from within an Active Transmission Line Right of Way
with the following exceptions: [Violation Risk Factor - Medium] [Time Horizon - Real
Time]
4
Sustained Outages of applicable lines that result from natural disasters4 or wind-blown
debris.
Sustained Outages of applicable lines that result from human or animal activity.5
Examples include, but are not limited to, earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale,
major storms as defined either by the Transmission Owner or an applicable regulatory body, ice storms, and
floods.
5
Examples include, but are not limited to, logging, animal severing tree, vehicle contact with tree, arboricultural
activities or horticultural or agricultural activities, or removal or digging of vegetation.
6
Multiple Sustained Outages on an individual line, if caused by the same vegetation, shall be considered as one
outage regardless of the actual number of outages within a 24-hour period.
M8. The Transmission Owner’s self-certification reports are adequate evidence of no Sustained
Outage of any applicable line due to vegetation falling into a conductor from within the
Active Transmission Line Right of Way. (R8)
This requirement is intended to prevent vegetation-related risk of a Cascading event on the
electric transmission system by requiring the Transmission Owner to manage vegetation to
prevent a vegetation-related Sustained Outage due to vegetation falling into a conductor from
within the Active Transmission Line Right of Way.
Note that for a Sustained Outage to be classified as a vegetation-related event, the conductor
must be operating between no load and its Rating when the event occurs. Events that occur
when the conductor is operating beyond its Rating are not classified as vegetation-related
Sustained Outages under the Standard. Also, this requirement clarifies that the conductor and the
vegetation must be within the Active Transmission Line Right of Way.
Vegetation-related Sustained Outages that occur due to natural disasters are beyond the control
of the Transmission Owner. These events are not classified as vegetation-related Sustained
Outages and are therefore exempt from the Standard. Transmission lines are not designed to
withstand the impacts of natural disasters such as tornadoes, hurricanes, severe ice loads,
landslides, etc. Additionally, Sustained Outages due to wind-blown debris, such as large limbs
and branches, separated tree tops, etc., are exempt from the Standard.
Sustained Outages due to human or animal activity are beyond the control of the Transmission
Owner. These events would not be classified as vegetation-related Sustained Outages and are
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NERC Standard FAC-003-2 Technical Reference
exempt from the Standard. Examples of these events may include new plantings of tall
vegetation under the transmission line planted since the last Vegetation Inspection, tree contacts
with line initiated by vehicles, logging activities, etc.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. Such
events are considered to be a single vegetation-related Sustained Outage under the Standard.
The Transmission Owner must self-certify each year that all vegetation-related Sustained
Outages are documented and reported. If no vegetation-related Sustained Outages have
occurred, a null report is sufficient documentation of compliance.
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NERC Standard FAC-003-2 Technical Reference
Implement Annual Work Plan
R9. Each Transmission Owner shall implement its annual work plan for vegetation
management to accomplish the purpose of this standard. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
M9. The Transmission Owner has evidence that it is implementing, or has implemented, its
annual work plan. An example of evidence is a paper or electronic copy of work plan and
work records. (R9)
This requirement sets the expectation that the work identified in the annual work plan
(Requirement R1, Part 11.3) will be completed as planned.
Documentation or other evidence of the work performed typically consists of signed-off work
orders, signed contracts, printouts from work management systems, spreadsheets of planned
versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence
may include photographs, work inspection reports and walk-through reports.
Documentation is required when the annual work plan is adjusted or not completely
implemented as originally planned. The reasons for the deferrals or changes and the expected
completion date of postponed work should be documented.
The Transmission Owner's vegetation maintenance work necessary to implement the annual
work plan is most effective when performed to the maximum extent allowed by any easement,
fee simple and other legal rights. The Transmission Owner, therefore, should endeavor as a best
practice to maintain its Active Transmission Line Right of Way to the full extent of its legal
rights at all times and in all cases.
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NERC Standard FAC-003-2 Technical Reference
Designating Sub-200kV Lines
R10. Each Planning Coordinator shall prepare and review annually, a list of lines that are
operated below 200kV, if any, which are subject to this standard. Each Planning
Coordinator shall consult with its Transmission Owner and neighboring Planning
Coordinator to obtain to develop the list [Violation Risk Factor: Lower] [Time Horizon:
Long-Term Planning]
M10. The Planning Coordinator has evidence that it consulted with its Transmission Owner(s)
and neighboring Planning Coordinator(s), prepared and reviewed annually a list of
designated sub-200kV transmission lines, if any, which are subject to this standard. (R10)
Requirement R10 assigns to the Planning Coordinator the task of designating sub-200kV lines
that are subject to this standard. The Planning Coordinator is appropriate because it operates
within a time horizon that allows a vegetation manager to develop and implement the necessary
vegetation management plan.
The Standard places the responsibility on the Planning Coordinator for the identification of
specific sub-200kV circuits to which the Standard is to be applied. Identification of such sub200kV circuits is to be done in consultation with the Planning Coordinator’s Transmission
Owners and neighboring Planning Coordinators. This is intended to ensure that the individual
Transmission Owners at the two ends of interconnections will receive identical signals regarding
applicability of the Standard to the line in question.
Planning Coordinators, using their methodologies described in R11, will need to conduct the
necessary studies and identify candidate sub-200kV transmission lines for potential applicability
under the Standard. The Planning Coordinators will next need to consult with its Transmission
Owners and neighboring Planning Coordinators to resolve any differences in the selection of
sub-200kV transmission lines of common interest. Finally, the Planning Coordinator will need to
finalize, adopt, and issue the list of designated sub-200kV lines.
For audit purposes, Planning Coordinators can offer documentation that they have consulted with
their Transmission Owners and neighboring Planning Coordinators and that they have reviewed
annually the list of designated sub-200kV transmission lines that are subject to the Standard.
Documentation may include dated letters, e-mails, spreadsheets, etc.
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NERC Standard FAC-003-2 Technical Reference
Documenting Method of Identifying Sub-200kV Lines
R11.
Each Planning Coordinator shall develop and document its method for assessing the
reliability significance of sub-200kV transmission lines whose loss would place the grid
at an unacceptable risk of instability, separation, or cascading failures. [Violation Risk
Factor: Lower] [Time Horizon: Long-term Planning]
M11. The Planning Coordinator has documented evidence such as planning study criteria or
other analysis used to develop its method for assessing the reliability significance of sub200kV lines whose loss would place the grid at an unacceptable risk of instability,
separation, or cascading failures. (R11)
Requirement R11 assigns to the Planning Coordinator the task of documenting its methods for
assessing the reliability significance of sub-200kV lines. The methods and requirements for
assessing significance of transmission lines are complex and spelled out in other prevailing
NERC standards. Essentially, however, these methods include activities such as load flow
studies, contingency analyses, and transient and dynamic voltage stability studies. Through the
use of such studies, the significance of each transmission line to the reliability of the system is
determined. Because such activities are already being conducted by the Planning Coordinator(s)
to meet other standards, the Planning Coordinator may choose to adopt the same methods for
meeting Requirement R11.
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NERC Standard FAC-003-2 Technical Reference
Appendix One: Clearance Distance Derivation by the
Gallet Equation
The Gallet Equation is a well-known method of computing the required strike distance for proper
insulation coordination, and has the ability to take into account various air gap geometries, as
well as non-standard atmospheric conditions. When the Gallet Equation and conservative
probabilistic methods are combined, i.e. deterministic design, sparkover probabilities of 10-6 or
less are achieved. This approach is well known for its conservatism and was used to design the
first 500kV and 765kV lines in North America [1]. Thus, the deterministic design approach
using the Gallet Equation is used for the standard to compute the minimum strike distance
between transmission lines and the vegetation that may be present in or along the transmission
corridor.
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NERC Standard FAC-003-2 Technical Reference
Method Explanation (Gallet Equation)
In 1975 G. Gallet published a benchmark paper that provided a method to compute the critical
flashover (CFO) voltage of various air gap geometries [4]. The Gallet Equation uses various
“gap factors” to take into account various air gap geometries. Various gap factor values are
provided in [1]. If the vegetation in a transmission corridor, e.g. a tree, is assumed electrically to
be a large structure then the CFO of such an air gap geometry can be computed for dry or wet
conditions using a well established equation proposed by Gallet [1],[2],[4],
CFOA k w k g m
3400
8
1
D
(1)
Where:
kw
is defined as the factor that takes into account wet or
dry conditions (dry = 1.0 and wet =
0.96) and phase arrangement (multiply by 1.08 for outside phase), e.g. outside phase and wet
conditions = (0.96)(1.08) = 1.037,
kg
is defined as the gap factor (1.3 for conductor to large structure),
D
is the strike distance (m),
CFOA
is the CFO for the relative air density (kV).
δ
is defined as the relative air density and is approximately equal to (2) where A is the altitude
in km,
e
A
8.6
(2)
m 1.25G0 G0 0.2
(3)
CFOs
500 D
(4)
G0
CFOs kw k g
3400
8
1
D
(5)
Where CFOS is the CFO for standard atmospheric conditions (kV). Using (1)-(5), the required CFOA can
be computed using an iterative process.
Once the CFOA is known, deterministic methods can be used to determine the required clearance
distance. If we let the maximum switching overvoltage be equal to the withstand voltage of the
air gap (CFOA - 3) then the CFOA can be written as (6).
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NERC Standard FAC-003-2 Technical Reference
CFOA
Vm
1 3
CFOA
(6)
Where:
Vm is equal to the maximum switching overvoltage, i.e. the value that has a 0.135% chance of being
exceeded,
is the standard deviation of the air gap insulation,
CFOA is the critical flashover voltage of the air gap insulation under non-standard atmospheric
conditions.
The ratio of to the CFOA given in (6) can be assumed to be 0.05 (5%) [1]. Thus, (6) can be
written as (7).
CFOA
Vm
0.85
(7)
Substituting (7) into (1) we arrive at (8).
Vm 0.85 kw k g m
3400
8
1
D
(8)
Equation 8 relates the maximum transient overvoltage, Vm, to the air gap distance, D. Using (8)
to compute the required clearance distance for the specified air gap geometry (conductor to large
structure) results in a probability of flashover in the range of 10-6.
Transient Overvoltage
In general, the worst case transient overvoltages occurring on a transmission line are caused by
energizing or re-energizing the line with the latter being the extreme case if trapped charge is
present. The intent of FAC-003 is to keep a transmission line that is in service from becoming
de-energized (i.e. tripped out) due to sparkover from the line conductor to nearby vegetation.
Thus, the worst case scenarios that are typically analyzed for insulation coordination purposes
(e.g. line energization and re-energization) can be ignored. For the purposes of FAC-003-2, the
worst case transient overvoltage then becomes the maximum value that can occur with the line
energized. Determining a realistic value of transient overvoltage for this situation is difficult
because the maximum transient overvoltage factors listed in the literature are based on a
switching operation of the line in question. In other words, these maximum overvoltage values
(e.g. the values listed in [2], [3] and [5]) are based on the assumption that the subject line is being
energized, re-energized or de-energized. These operations, by their very nature, will create the
largest transient overvoltages. Typical values of transient overvoltages of in-service lines, as
such, are not readily available in the literature because the resulting level of overvoltage is
negligible compared with the maximum (e.g. re-energizing a transmission line with trapped
charge). A conservative value for the maximum transient overvoltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 p.u.[2]. This value is a
FAC-003-2 Technical Reference
September, 2009
44
NERC Standard FAC-003-2 Technical Reference
conservative estimate of the transient overvoltage that is created at the point of application (e.g. a
substation) by switching a capacitor bank without a pre-insertion device (e.g. closing resistors).
At voltage levels where capacitor banks are not very common (e.g. 362kV), the maximum
transient overvoltage of an “in-service” ac line are created by fault initiation on adjacent ac lines
and shunt reactor bank switching. These transient voltages are usually 1.5 p.u. or less [2]. It is
well known that these theoretical transient overvoltages will not be experienced at locations
remote from the bus at which they were created; however, in order to be conservative, it will be
assumed that all nearby ac lines are subjected to this same level of overvoltage. Thus, a
maximum transient overvoltage factor of 2.0 p.u. for 242 kV and below and 1.4 p.u. for ac
transmission lines 362 kV and above is used to compute the required clearance distances for
vegetation management purposes.
The overvoltage characteristics of dc transmission lines vary somewhat from their ac
counterparts. The referenced empirically derived transient overvoltage factor used to calculate
the minimum clearance distances from dc transmission lines to vegetation for the purpose of
FAC-003-2 will be 1.8 p.u.[3].
Example Calculation
An example calculation is presented below using the proposed method of computing the
vegetation clearance distances. It is assumed that the line in question has a maximum operating
voltage of 550 kVrms line-to-line. Using a per unit transient overvoltage factor of 1.4, the result
is a peak transient voltage of 629 kVcrest. It is further assumed that the line in question operates
at a maximum altitude of 7000 feet (2.134 km) above sea level.
The required withstand voltage of the air gap must be equal to or greater than 629 kVcrest. Since
the altitude is above sea level, (1) - (5) have to be iterated on to achieve the desired result.
Equation (9) can be used as an initial guess for the clearance distance.
Di
8
3400 k w k g
Vm
0.85
(9)
1
For our case here, Vm is equal to 629 kV, kw = 1.037 and kg = 1.3. Thus,
Di
8
3400 k w k g
Vm
0.85
1
8
1.535m
3400 1.037 1.3
1
629
0.85
(10)
Using (2)-(5) and (8) the withstand voltage of the air gap is next computed. This value will then
be compared to the maximum transient overvoltage.
CFO S k w k g
FAC-003-2 Technical Reference
September, 2009
3400
3400
1 .037 1 .3
737 .7 kV
8
8
1
1
D
1 .535
(11)
45
NERC Standard FAC-003-2 Technical Reference
e
GO
A
8.6
e
2.134
8.6
0.78
(12)
CFO S
737 .7
0.961
500 D 500 1 .535
(13)
m 1.25 G O G O 0.2 1.25 0.9610.961 0.2 0.915
V m 0 . 85 k w k g
m
3400
3400
0 . 85 1 .037 1 . 3 0 .78 0 .915
8
8
1
1
1 . 535
D
(14)
499 . 8 kV
(15)
The calculated Vm is less than 629 kV; thus, the clearance distance must be increased. A few
iterations using (2)-(5) and (8) are required until the computed Vm 629 kV. For this case it was
found that D = 1.978 m (6.49 feet) yielded Vm = 629.3kV. Using this clearance distance the
following values were computed for the final iteration.
CFO
S
kw kg
e
GO
3400
3400
1 . 037 1 . 3
908 . 5 kV
8
8
1
1
D
1 . 978
A
8.6
e
2.134
8.6
0.78
(17)
CFOS
908.5
0.919
500 D 500 1.978
(18)
m 1.25 G O G O 0.2 1.25 0.919 0.919 0.2 0.825
V m 0 . 85 k w k g
m
3400
3400
0 .825
0 . 85 1 . 037 1 . 3 0 . 78
8
8
1
1
1 .978
D
(16)
(19)
629 . 3 kV
(20)
Therefore, the minimum vegetation clearance distance for a maximum line to line ac operating
voltage of 550 kV at 7000 feet above sea level is 1.978 m (6.49 feet). Table 1 provides
calculated distances for various altitudes and maximum system operating ac voltages.
FAC-003-2 Technical Reference
September, 2009
46
NERC Standard FAC-003-2 Technical Reference
TABLE 1 — Minimum Vegetation Clearance Distances (MVCD)
For Alternating Current Voltages
( AC )
Nominal
System
Voltage
(kV)
( AC )
Maximum
System
Voltage
(kV)
765
800
500
550
345
362
230
242
161*
169
138*
145
115*
121
88*
100
69*
72
MVCD
feet
(meters)
Sea
level
8.06ft
(2.46m)
5.06ft
(1.54m)
3.12ft
(0.95m)
2.97ft
(0.91m)
2ft
(0.61m)
1.7ft
(0.52m)
1.41ft
(0.43m)
1.15ft
(0.35m)
0.82ft
(0.25m)
MVCD
feet
(meters)
3,000ft
(914.4m)
8.89ft
(2.71m)
5.66ft
(1.73m)
3.53ft
(1.08m)
3.36ft
(1.02m)
2.28ft
(0.69m)
1.94ft
(0.59m)
1.61ft
(0.49m)
1.32ft
(0.40m)
0.94ft
(0.29m)
MVCD
feet
(meters)
4,000ft
(1219.2m)
9.17ft
(2.80m)
5.86ft
(1.79m)
3.67ft
(1.12m)
3.49ft
(1.06m)
2.38ft
(0.73m)
2.03ft
(0.62m)
1.68ft
(0.51m)
1.38ft
(0.42m)
0.99ft
(0.30m)
MVCD
feet
(meters)
5,000ft
(1524m)
9.45ft
(2.88m)
6.07ft
(1.85m)
3.82ft
(1.16m)
3.63ft
(1.11m)
2.48ft
(0.76m)
2.12ft
(0.65m)
1.75ft
(0.53m)
1.44ft
(0.44m)
1.03ft
(0.31m)
MVCD
feet
(meters)
6,000ft
(1828.8m)
9.73ft
(2.97m)
6.28ft
(1.91m)
3.97ft
(1.21m)
3.78ft
(1.15m)
2.58ft
(0.79m)
2.21ft
(0.67m)
1.83ft
(0.56m)
1.5ft
(0.46m)
1.08ft
(0.33m)
MVCD
feet
(meters)
7,000ft
(2133.6m)
10.01ft
(3.05m)
6.49ft
(1.98m)
4.12ft
(1.26m)
3.92ft
(1.19m)
2.69ft
(0.82m)
2.3ft
(0.70m)
1.91ft
(0.58m)
1.57ft
(0.48m)
1.13ft
(0.34m)
*As designated by the Planning Coordinator
FAC-003-2 Technical Reference
September, 2009
47
MVCD
feet
(meters)
8,000ft
(2438.4m)
10.29ft
(3.14m)
6.7ft
(2.04m)
4.27ft
(1.30m)
4.07ft
(1.24m)
2.8ft
(0.85m)
2.4ft
(0.73m)
1.99ft
(0.61m)
1.64ft
(0.50m)
1.18ft
(0.36m)
MVCD
feet
(meters)
9,000ft
(2743.2m)
10.57ft
(3.22m)
6.92ft
(2.11m)
4.43ft
(1.35m)
4.22ft
(1.29m)
2.91ft
(0.89m)
2.49ft
(0.76m)
2.07ft
(0.63m)
1.71ft
(0.52m)
1.23ft
(0.37m)
MVCD
feet
(meters)
10,000ft
(3048m)
10.85ft
(3.31m)
7.13ft
(2.17m)
4.58ft
(1.40m)
4.37ft
(1.33m)
3.03ft
(0.92m)
2.59ft
(0.79m)
2.16ft
(0.66m)
1.78ft
(0.54m)
1.28ft
(0.39m)
MVCD
feet
(meters)
11,000ft
(3352.8m)
11.13ft
(3.39m)
7.35ft
(2.24m)
4.74ft
(1.44m)
4.53ft
(1.38m)
3.14ft
(0.96m)
2.7ft
(0.82m)
2.25ft
(0.69m)
1.86ft
(0.57m)
1.34ft
(0.41m)
NERC Standard FAC-003-2 Technical Reference
TABLE 1 (CONT.) — Minimum Vegetation Clearance Distances (MVCD)
For Direct Current Voltages
sea level
MVCD feet
(meters)
3,000ft
(914.4m)
Alt.
MVCD feet
(meters)
4,000ft
(1219.2m)
Alt.
MVCD feet
(meters)
5,000ft
(1524m)
Alt.
±750
13.92ft
(4.24m)
15.07ft
(4.59m)
15.45ft
(4.71m)
±600
10.07ft
(3.07m)
11.04ft
(3.36m)
±500
7.89ft
(2.40m)
±400
±250
( DC )
Nominal Pole
to Ground
Voltage
(kV)
MVCD
feet
(meters)
11,000ft
(3352.8m)
Alt.
MVCD feet
(meters)
6,000ft
(1828.8m)
Alt.
MVCD
feet
(meters)
7,000ft
(2133.6m)
Alt.
MVCD
feet
(meters)
(8,000ft
(2438.4m)
Alt.
MVCD
feet
(meters)
9,000ft
(2743.2m)
Alt.
MVCD
feet
(meters)
10,000ft
(3048m)
Alt.
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.9ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
(13.54ft
4.13m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
4.78ft
(1.46m)
5.35ft
(1.63m)
5.55ft
(1.69m)
5.75ft
(1.75m)
5.95ft
(1.81m)
6.15ft
(1.87m)
6.36ft
(1.94m)
6.57ft
(2.00m)
6.77ft
(2.06m)
6.98ft
(2.13m)
3.43ft
(1.05m)
4.02ft
(1.23m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5ft
(1.52m)
5.17ft
(1.58m)
MVCD feet
(meters)
FAC-003-2 Technical Reference
September, 2009
48
NERC Standard FAC-003-2 Technical Reference
List of Acronyms and Abbreviations
AC
Alternating Current
ANSI
American National Standards Institute
CFO
Critical Flashover
DC
Direct Current
IEEE
Institute of Electrical and Electronics Engineers
IROL
Interconnection Reliability Operating Limit
IVM
Integrated Vegetation Management
NERC
North American Electric Reliability Corporation
IROL
Interconnection Reliability Operating Limit
MVCD
Minimum Vegetation Clearance Distance
TGR
Tree Growth Regulator
TO
Transmission Owner
TVMP
Transmission Vegetation Management Program
WECC
Western Electricity Coordinating Council
FAC-003-2 Technical Reference
September, 2009
49
NERC Standard FAC-003-2 Technical Reference
References
[1] Andrew Hileman, Insulation Coordination for Power System, Marcel Dekker, New York,
NY 1999
[2] EPRI, EPRI Transmission Line Reference Book 345 kV and Above, Electric Power Research
Council, Palo Alto, Ca. 1975.
[3] IEEE Std. 516-2003 IEEE Guide for Maintenance Methods on Energized Power Lines
[4] G. Gallet, G. Leroy, R. Lacey, I. Kromer, General Expression for Positive Switching
Impulse Strength Valid Up to Extra Long Air Gaps, IEEE Transactions on Power Apparatus
and Systems, Vol. pAS-94, No. 6, Nov./Dec. 1975.
[5] IEEE Std. 1313.2-1999 (R2005) IEEE Guide for the Application of Insulation Coordination.
[6] 2007 National Electric Safety Code
[7] EPRI, HVDC Transmission Line Reference Book, EPRI TR-102764 , Project 2472-03, Final
Report, September 1993
[8] ANSI. 2001. American National Standard for Tree Care Operations – Tree, Shrub, and
Other Plant Maintenance – Standard Practices (Pruning). Part 1. American National
Standards Institute, NY
[9] ANSI. 2006. American National Standard for Tree Care Operations – Tree, Shrub, and
Other Plant Maintenance – Standard Practices (Integrated Vegetation Management a.
Electric Utility Rights-of-way). Part 7. American National Standards Institute, NY.
[10] Cieslewicz, S. and R. Novembri. 2004. Utility Vegetation Management Final Report.
Federal Energy Regulatory Commission. Commissioned to support the Federal
Investigation of the August 14, 2003 Northeast Blackout. Federal Energy Regulatory
Commission, Washington, DC. pg. 39.
[11] Kempter, G.P. 2004. Best Management Practices: Utility Pruning of Trees.
International Society of Arboriculture, Champaign, IL
[12] Miller, R.H. 2007. Best Management Practices: Integrated Vegetation Management.
Society of Arboriculture, Champaign, IL.
[13] Yahner, R.H. and R.J. Hutnik. 2004. Integrated Vegetation Management on an electric
transmission right-of-way in Pennsylvania, U.S. Journal of Arboriculture. 30:295-300
FAC-003-2 Technical Reference
September, 2009
50
Implementation Plan for FAC-003-2
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress
or approved, that must be implemented before this standard can be implemented.
FAC-003-2 — Vegetation Management
Revision to Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards associated
with the approval of FAC-003-2.
The drafting team is proposing the following changes to definitions:
Retire the existing approved definition for “Vegetation Inspection:”
The systematic examination of a transmission corridor to document vegetation
conditions.
Implement a new definition for “Vegetation Inspection:”
The systematic examination of vegetation conditions on an Active Transmission Line
Right of Way. This inspection may be combined with a general line inspection. The
inspection includes the documentation of any vegetation that may pose a threat to
reliability prior to the next planned inspection or maintenance work, considering the
current location of the conductor and other possible locations of the conductor due to sag
and sway for rated conditions.
Implement a new definition for “Active Transmission Line Right of Way:”
A strip of land that is occupied by active transmission facilities. This corridor does not
include the inactive or unused part of the Right of Way intended for other facilities.
FAC-003-1 and the existing definition of “Vegetation Inspection” will be retired and the new
definitions for “Vegetation Inspection” and “Active Transmission Line Right of Way” will
become effective at the same time that FAC-003-2 becomes effective.
Compliance with Standard
The standard applies to Transmission Owners and Planning Coordinators.
Effective Date
The effective date is the date entities are expected to meet the performance identified in this
standard. The effective date (for all requirements), for jurisdictions where regulatory approval is
required, is the first calendar day of the first calendar quarter one year after applicable regulatory
authority. The effective date (for all requirements), for jurisdictions where no regulatory
approval is required, is the first calendar day of the first calendar quarter one year following
Board of Trustees adoption. The effective date allows the Planning Coordinator time to conduct
the analyses needed to identify sub-200kV transmission lines that should be subject to this
standard.
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com
Standards Announcement
Comment Period Open
September 9–October 24, 2009
Now available at: http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
Project 2007-07: Transmission Vegetation Management
The Transmission Vegetation Management Standard Drafting Team is seeking comments on the following documents
until 8 p.m. EDT on October 24, 2009:
FAC-003-2 — Transmission Vegetation Management Program
Mapping document (comparing FAC-003-1 to FAC-003-2)
Implementation plan for FAC-003-2
Technical reference document
This is the second comment period for proposed standard FAC-003-2. The drafting team revised the proposed standard,
updated the technical reference document to align with the changes made to the proposed standard, updated the mapping
document, and added an implementation plan. The drafting team has also posted its consideration of industry comments
received during the previous comment period.
Instructions
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic form, please
contact Lauren Koller at [email protected]. An off-line, unofficial copy of the comment form is posted on the
project page: http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
Next Steps
The drafting team will draft and post responses to comments received during this period. The drafting team will also
determine whether to post the standard for an additional comment period or seek approval from the Standards Committee
to proceed to balloting.
Project Background
The project is an update to FAC-003-1, which was approved in 2006. The items identified for revision include the
incorporation of FERC Order 693 comments related to applicability, procedural repairs to conform to the current
standards format and development procedure, technical updates and guidance to address stakeholder suggestions, and the
elimination of “fill-in-the-blank” components. More information is available on the project page.
Applicability of Standards in Project
Transmission Owner
Planning Coordinator
Specific facilities (see proposed standard for more information)
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance,
please contact Shaun Streeter at [email protected] or at 609.452.8060.
Consideration of Comments on Vegetation Management FAC-003-2
Standard — Project 2007-07
The Vegetation Management Standard Drafting Team thanks all commenters who submitted
comments on the proposed FAC-003-2 — Transmission Vegetation Management Standard.
This standard was posted for a 30-day public comment period from September 10, 2009
through October 24, 2009. The stakeholders were asked to provide feedback on the
standard through a special Electronic Comment Form. There were 66 sets of comments,
including comments from 156 different people from more than 85 companies representing
all of the 10 Industry Segments as shown in the table on the following pages.
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
On January 14, 2010, the NERC Standards Committee endorsed the use of Project 2007-07
Vegetation Management as the prototype for the proof-of-concept for using the resultsbased criteria for developing a reliability standard. The results-based initiative is intended
to focus the collective effort of NERC and industry participants on improving the clarity and
quality of NERC reliability standards by developing performance, risk and competency-based
requirements that accomplish a reliability objective through a defense-in-depth strategy,
while eliminating documentation-driven requirements that do not have an impact on bulk
power system reliability.
The Standards Committee directed the Vegetation Management SDT to stop work in refining
its second draft of the Vegetation Management standard but to inform stakeholders on how
the team had used stakeholder comments to refine the technical requirements carried over
into draft 3 of the standard. The drafting team did not develop individual responses to the
comments submitted by stakeholders on the second draft of FAC-003-2. Instead, the
drafting team produced a special summary report that shows all the questions asked and
provides a summary indicating how the drafting team used stakeholder comments
submitted in response to that question. The special report is posted on the FAC-003 project
page identified in the URL above under the title, “Summaries.”
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Index to Questions, Comments, and Responses
1.
As stated in the background information above, in response to industry
comments, the Requirement for documentation of a TVMP (the new R1) is
revised. Additionally the SDT assigned Time Horizons, Violation Risk Factors,
and Violation Severity Levels. Do you agree? If not, please explain and
propose an alternative...................................................................................13
2. As stated in the background information above, in response to industry
comments, the Requirement for implementation of Imminent Threat
process/procedure (the new R2) is revised. Additionally the SDT assigned
Time Horizons, Violation Risk Factors, and Violation Severity Levels. Do you
agree? If not, please explain and propose an alternative. ..............................30
3. As stated in the background information above, in response to industry
comments, the Requirement for conducting Vegetation Inspections (the new
R3) is revised. Additionally the SDT assigned Time Horizons, Violation Risk
Factors, and Violation Severity Levels. Do you agree? If not, please explain
and propose an alternative. ...........................................................................36
4. As stated in the background information above, in response to industry
comments, the Requirement for preventing vegetation encroachments (the
new R4) is revised. Additionally the SDT assigned Time Horizons, Violation
Risk Factors, and Violation Severity Levels. Do you agree? If not, please
explain and propose an alternative. ...............................................................43
5. As stated in the background information above, in response to industry
comments, the Requirement for preventing Sustained Outages due to growins on IROL or Major WECC Transfer Paths (the new R5) is developed.
Additionally the SDT assigned Time Horizons, Violation Risk Factors, and
Violation Severity Levels. Do you agree? If not, please explain and propose an
alternative.....................................................................................................54
6. As stated in the background information above, in response to industry
comments, the Requirement for preventing Sustained Outages due to growins on non-IROL or Major WECC Transfer Paths (the new R6) is developed.
Additionally the SDT assigned Time Horizons, Violation Risk Factors, and
Violation Severity Levels. Do you agree? If not, please explain and propose an
alternative.....................................................................................................60
7. As stated in the background information above, in response to industry
comments, the Requirement for preventing Sustained Outages due to blowing
together of vegetation and transmission line conductors (the new R7) is
developed. Additionally the SDT assigned Time Horizons, Violation Risk
Factors, and Violation Severity Levels. Do you agree? If not, please explain
and propose an alternative. ...........................................................................65
8. As stated in the background information above, in response to industry
comments, the Requirement for preventing Sustained Outages due to fall-ins
of vegetation (the new R8) is developed. Additionally the SDT assigned Time
Horizons, Violation Risk Factors, and Violation Severity Levels. Do you agree?
If not, please explain and propose an alternative. .........................................71
9. As stated in the background information above, in response to industry
comments, the Requirement for implementation of annual work plan (the new
R9) is developed. Additionally the SDT assigned Time Horizons, Violation Risk
Factors, and Violation Severity Levels. Do you agree? If not, please explain
and propose an alternative. ...........................................................................77
10. As stated in the background information above, in response to industry
comments, the Requirement for the preparation of list for sub 200kV
transmission lines by the Planning Coordinator (the new R10) is developed.
Additionally the SDT assigned Time Horizons, Violation Risk Factors, and
2
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
11.
12.
13.
14.
15.
16.
17.
18.
Violation Severity Levels. Do you agree? If not, please explain and propose an
alternative.....................................................................................................83
As stated in the background information above, in response to industry
comments, the Requirement for the Planning Coordinator to document method
for identification of applicable sub-200kV transmission lines (the new R11) is
developed. Additionally the SDT assigned Time Horizons, Violation Risk
Factors, and Violation Severity Levels. Do you agree? If not, please explain
and propose an alternative. ...........................................................................91
The SDT received suggestions from commenters to re-sequence the
requirements contained in the standard to improve the logical flow of this
document. The SDT submits for consideration a proposed alternative
sequence. Do you agree with the proposed alternative sequencing? If not,
please recommend a suggested sequence. ....................................................96
The Implementation Plan proposes an effective date that gives entities at
least a year to become fully compliant. Do you agree with this
implementation plan? If not, please indicate what should be changed and
indicate why. ............................................................................................... 101
Do you have further questions about the standard that the Technical
Reference document (White Paper) does not clear up? If so, please elaborate
and propose additions. ................................................................................ 106
As stated in the background information above, in response to industry
comments, the applicability section is revised to replace Reliability
Coordinator with Planning Coordinator. Do you agree with these changes? If
not, please explain and propose an alternative. ........................................... 112
As stated in the background information above, in response to industry
comments, changes were made to the definitions. Do you agree with these
changes? If not, please explain and propose an alternative. ........................ 118
When compared to Version 1, does this proposed Version 2 of the standard
either maintain or improve overall electric reliability? Please provide a
technical basis for your response? ............................................................... 126
Besides the comments you have already provided for the preceding questions,
do you have further suggestions for improving this standard? If so, please
elaborate. .................................................................................................... 141
3
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
1.
Group
Richard Kafka
Additional Member
Pepco Holdings, Inc - Affiliates (PHI)
X
Additional Organization
2
3
X
4
5
6
X
X
Region
Potomac Electric Power Company
RFC
1
2. Dave Paduda
Potomac Electric Power Company
RFC
1
3. Steve Benn
Delmarva Power & Light
RFC
1
4. Olivia Watts
Atlantic City Electric
RFC
1
Group
Guy Zito
Additional Member
8
9
10
Segment Selection
1. Pat Byrne
2.
7
Northeast Power Coordinating Council-RSC
X
Additional Organization
Region
Segment Selection
1. Ralph Rufrano
New York Power Authority
NPCC
5
2. Alan Adamson
New York State Reliability Council, LLC
NPCC
10
3. Gregory Campoli
New York Independent System Operator
NPCC
2
4. Roger Champagne
Hydro-Quebec TransEnergie
NPCC
2
5. Kurtis Chong
Independent Electricity System Operator
NPCC
2
6. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
4
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7. Saurabh Saksena
National Grid
NPCC
8. Chris de Graffenried
Consolidated Edison Co. of New York, Inc.
NPCC
1
9. Brian D. Evans-Mongeon
Utility Services
NPCC
8
10. Mike Garton
Dominion Resources Services, Inc.
NPCC
5
11. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC
5
12. Kathleen Goodman
ISO - New England
NPCC
2
13. David Kiguel
Hydro One Networks Inc.
NPCC
1
14. Michael R. Lombardi
Northeast Utilities
NPCC
1
15. Randy MacDonald
New Brunswick System Operator
NPCC
2
16. Greg Mason
Dynegy Generation
NPCC
5
17. Bruce Metruck
New York Power Authority
NPCC
6
18. Chris Orzel
FPL Energy/NextEra Energy
NPCC
5
19. Robert Pellegrini
The Untied Illuminating Company
NPCC
1
20. Michael Schiavone
National Grid
NPCC
1
21. Peter Yost
Consolidated Edison Co. of New York, Inc.
NPCC
3
22. Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
23. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
10
Public Service Co. of New Mexico
X
3.
Group
Jim Butler
Additional Member
1. Anne Beard
4.
Additional Organization
PNM
Group
Deborah Schaneman
Additional Member
Region
X
Additional Organization
X
X
Region
Segm
Platte River Power Authority
WECC
1, 3, 5
Platte River Power Authority
WECC
1, 3, 5
John Neagle
Associated Electric Cooperative, Inc.
10
Segment Selection
2. Gary Whittenberg
Group
9
1
1. Scott Rowley
5.
8
1
WECC
Platte River Power Authority Vegetation
Management Group
7
X
X
X
5
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
Additional Member
Additional Organization
2
3
4
5
6
7
Associated Electric Cooperative, Inc.
SERC
1, 5, 6
Associated Electric Cooperative, Inc.
SERC
1, 5, 6
3. Kevin Hopper
Associated Electric Cooperative, Inc.
SERC
1, 5, 6
4. Jeff Neas
Associated Electric Cooperative, Inc.
SERC
1, 5, 6
5. Gary Highfill
Associated Electric Cooperative, Inc.
SERC
1, 5, 6
6. Ted Hilmes
Associated Electric Cooperative, Inc.
SERC
1, 5, 6
7. David McDowell
Associated Electric Cooperative, Inc.
SERC
1, 5, 6
8. Bill Price
Associated Electric Cooperative, Inc.
SERC
1, 5, 6
9. Bob Schreiner
Associated Electric Cooperative, Inc.
SERC
1, 5, 6
10. Ralph Schulte
Associated Electric Cooperative, Inc.
SERC
1, 5, 6
11. John Settle
Associated Electric Cooperative, Inc.
SERC
1, 5, 6
12. John Stickley
Associated Electric Cooperative, Inc.
SERC
1, 5, 6
13. Craig Thomas
Associated Electric Cooperative, Inc.
SERC
1, 5, 6
14. Kevin White
Associated Electric Cooperative, Inc.
SERC
1, 5, 6
Joe Spencer
SERC Vegetation Management Subcommittee (VMS)
Additional Member
10
Segment
2. John Bussman
Group
9
Region
1. Chris Bolick
6.
8
X
Additional Organization
Region
Segment Selection
1. Randy Gann
Alabama Power Company
SERC
1, 3, 5
2. Jeffrey Hackman
Ameren Services Company
SERC
1, 3, 5
3. Gerald Beckerle
Ameren Services Company
SERC
1, 3, 5
4. John Neagle
Associated Electric Cooperative, Inc.
SERC
1, 3, 5, 6
5. Billy George
Duke Energy Carolinas
SERC
1, 3, 5, 6
6. Robert Trimble
E.ON U.S. Services Inc. for LG&E & KU
Companies
SERC
1, 3, 5, 6
7. Ralph Hale
Entergy
SERC
1, 3, 5, 6
8. Jim Case
Entergy
SERC
1, 3, 5, 6
9. Marc Tunstall
Fayetteville Public Works Commission
SERC
1, 3
6
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
10. Reggie Wallace
Fayetteville Public Works Commission
SERC
1, 3
11. Terry Wilson
PowerSouth Energy Cooperative
SERC
6, 1, 3, 5
12. Jack Gardner
Progress Energy Carolinas
SERC
1, 3, 5, 6
13. Jerry Lindler
South Carolina Electric & Gas Company
SERC
1, 3, 5, 6
14. Richard Dearman
Tennessee Valley Authority
SERC
1, 3, 5, 9
15. Ron Adams
Duke Energy Carolinas
SERC
1, 3, 5, 6
16. Joe Spencer
SERC Reliability Corp.
SERC
10
17. Dane Jonas (VMS visitor)
Va. Electric and Power Co.
SERC
1, 3, 5
7.
Group
Denise Koehn
Bonneville Power Administration
Additional Member
X
Additional Organization
X
X
Region
Transmission Vegetation/Access Road Mgmt
WECC
1
Transmission Engineering
WECC
1
3. Jerry Reding
Transmission Line Design
WECC
1
4. Marian Wolcott
Transmission Real Property Services
WECC
1
5. Jennifer Bailey
Transmission TLM Technical Svcs
WECC
1
6. Berhanu Tesema
Transmission Planning
WECC
1
7. Mark Newbil
Transmission Vegetation/Access Road Mgmt
WECC
1
8. Mike Viles
Transmission Technical Operations
WECC
1
9. Dan Tuominen
Transmission Line Design
WECC
1
10. Steve Narolski
Transmission Vegetation/Access Road Mgmt
WECC
1
11. Frank Weintraub
Transmission Line Design
WECC
1
12. Allen Chan
Office of General Counsel
WECC
1
Doug Hohlbaugh
FirstEnergy Corp
Additional Member
X
Additional Organization
X
10
Segment Selection
2. Mike Staats
Group
9
X
1. John Jamrog
8.
8
X
X
X
Region
Segment Selection
1. Rebecca Spach
FE
RFC
1
2. Shawn Standish
FE
RFC
1
3. Katrina Schnobrich
FE
RFC
1
7
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
4. Mike Ferncez
FE
RFC
1
5. Sam Ciccone
FE
RFC
1, 3, 4, 5, 6
6. David Folk
FE
9.
Group
Carol Gerou
NERC Standards Review
Subcommittee
Additional Member
Additional Organization
Region
Segment Selection
MRO
3, 4, 5, 6
2. Terry Bilke
Midwest ISO Inc.
MRO
2
3. Jodi Jenson
Western Area Power Administration
MRO
1, 6
4. Ken Goldsmith
Alliant Energy
MRO
4
5. Alice Murdock
Xcel Energy
MRO
1, 3, 5, 6
6. Dave Rudolph
Basin Electric Power Cooperative
MRO
1, 3, 5, 6
7. Eric Ruskamp
Lincoln Electric System
MRO
1, 3, 5, 6
8. Joseph Knight
Great River Energy
MRO
1, 3, 5, 6
9. Joe DePoorter
Madison Gas & Electric
MRO
3, 4, 5, 6
10. Scott Nickels
Rochester Public Utilties
MRO
4
11. Terry Harbour
MidAmerican Energy Company
MRO
1, 3, 5, 6
Ben Li
ISO/RTO Council
Additional Member
10
X
WPS Corporation
Group
9
1, 3, 4, 5, 6
1. Neal Balu
10.
8
Additional Organization
X
Region
Segment Selection
1. Charles Yeung
SPP
SPP Region
2
2. Matt Goldberg
ISO-NE
NPCC Region
2
3. Patrick Brown
PJM
RFC Region
2
4. Bill Phillips
MISO
MRO Region
2
5. James Castle
NYISO
NPCC Region
2
6. Steve Myers
ERCOT
ERCOT Region
2
7. Mark Thompson
AESO
WECC Region
2
8. Lourdes Estrada-Salinero
CAISO
WECC Region
2
8
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
X
2
3
4
X
5
6
11.
Individual
Chip Turner
Tampa Electric Company
12.
Individual
Michael Davis
WECC RC
13.
Individual
Tom Glock-
Arizona Public Service
X
X
14.
Individual
Sandra Shaffer
PacifiCorp
X
X
X
X
15.
Individual
Derek Vannice
Utility Arborist Association
16.
Individual
Mary Hetz
Ameren
X
17.
Individual
Jim Fulton
Vegetation Management Team
X
18.
Individual
Brent Ingebrigtson
E.ON U.S.
X
X
X
X
19.
Individual
Silvia Parada-Mitchell
Transmission Owner
X
X
X
20.
Individual
Hugh Francis
Southern Company
X
21.
Individual
James P. Fama
Edison Electric Institute
X
22.
Individual
Jody Nelson
Georgia Transmission Corporation
X
23.
Individual
Frank Gaffney
Florida Municipal Power Agency, and its
Member Cities, Lakeland Electric and
Kissimmee Utility Authority
X
X
24.
Individual
Linwood Blacksmith
Superintendent Transmission
Maintenance
X
X
25.
Individual
Weston Davis
Central Maine Power an Energy East
Company
X
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
9
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
X
5
6
X
X
26.
Individual
James Starling
SCE&G
X
27.
Individual
Anthony Johnson
Northeast Utilities
X
28.
Individual
Thomas E. Sullivan
National Grid
X
X
29.
Individual
Virginia Cook
JEA
X
X
30.
Individual
Richard Dearman
TVA
X
31.
Individual
Pat Simons
Idaho Power Company
X
32.
Individual
Diana Gilman
Lee County Electric Cooperative
X
33.
Individual
Stephen Tankersley
Pacific Gas and Electric Co.
X
34.
Individual
James Manning
North Carolina Electric Membership
Corporation
35.
Individual
James H. Sorrels, Jr.
American Electric Power
X
36.
Individual
Gwen shrimpton
BC Transmission Corporation
X
37.
Individual
Larry Akens
TVA
X
38.
Individual
Rao Somayajula
ReliabilityFirst Corporation
39.
Individual
Ian S Grant
Tennessee Valley Authority
X
X
X
40.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
X
41.
Individual
ron turley
Western Area Power Administration,
Rocky Mountain Region
X
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
10
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
42.
Individual
Greg Rowland
Duke Energy
X
X
43.
Individual
Doug Bailey
TVA
X
X
44.
Individual
Alice Murdock
Xcel Energy
X
X
45.
Individual
Patricia Metro
NRECA - National Rural Electric
Cooperative Association
46.
Individual
Larry Rodriguez
Entegra Power Group LLC
47.
Individual
David Kiguel
Hydro One Networks inc.
X
48.
Individual
Edward Bedder
Orange and Rockland Utilities, Inc.
X
49.
Individual
Brian Scott
New Brunswick Power Transmission
X
50.
Individual
Michael Pakeltis
CenterPoint Energy
X
51.
Individual
John Humphrey
Nebraska Public Power District
X
52.
Individual
Darryl Curtis
Oncor Electric Delivery
X
53.
Individual
Ed Davis
Entergy Services, Inc
X
54.
Individual
Russell Hardison
Tennessee Valley Authority
X
55.
Individual
Kathleen Goodman
ISO New England Inc.
56.
Individual
Martin Bauer
US Bureau of Reclamation
57.
Individual
Jason Shaver
American Transmission Company
X
4
5
6
X
X
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
11
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
X
X
58.
Individual
Jack Gardner
Progress Energy Carolinas, Inc.
X
X
59.
Individual
Gary Cox
Tucson Electric Power Company
X
X
60.
Individual
Patrick Farrell
Southern California Edison Company
X
X
X
X
61.
Individual
Karen Powell
Salt River Project
X
X
X
X
62.
Individual
Steve Rueckert
WECC
63.
Individual
Roger Champagne
Hydro-Québec TransEnergie (HQT)
64.
Individual
Dan Rochester
Independent Electricity System
Operator
65.
Individual
George Czerniewski
Consolidated Edison Company of New
York Inc.
X
66.
Individual
Catherine Koch
Puget Sound Energy
X
67.
Individual
Jason Lietz
Northern Indiana Public Service
Company
X
7
8
9
10
X
X
X
12
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
1. As stated in the background information above, in response to industry comments, the Requirement for
documentation of a TVMP (the new R1) is revised. Additionally the SDT assigned Time Horizons, Violation Risk
Factors, and Violation Severity Levels. Do you agree? If not, please explain and propose an alternative.
Summary Consideration:
Organization
Yes or No
Entegra Power Group LLC
Question 1 Comment
No comment
American Electric Power
Agree
Associated Electric Cooperative,
Inc.
Agree
BC Transmission Corporation
Agree
Bonneville Power Administration
Agree
Duke Energy
Agree
Entergy Services, Inc
Agree
Georgia Transmission
Corporation
Agree
Hydro One Networks inc.
Agree
New Brunswick Power
Transmission
Agree
North Carolina Electric
Membership Corporation
Agree
Northeast Utilities
Agree
13
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Pacific Gas and Electric Co.
Agree
ReliabilityFirst Corporation
Agree
SCE&G
Agree
SERC Vegetation Managment
Sub-committee (VMS)
Agree
Southern Company
Agree
Superintendent Transmission
Maintenance
Agree
Tampa Electric Company
Agree
Tenessee Valley Authority
Agree
Tennessee Valley Authority
Agree
Tucson Electric Power Company
Agree
TVA
Agree
TVA
Agree
TVA
Agree
US Bureau of Reclamation
Agree
WECC RC
Agree
Western Area Power
Administration, Rocky Mountain
Agree
Question 1 Comment
14
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
Region
Orange and Rockland Utilities,
Inc.
Agree
Although ORU agrees that each TO should be required to have a documented TVMP, we recommend
changing the wording in Sections 1.2 and 1.3.2.In Section 1.2, ORU recommends the wording to read,
‘Specify a Vegetation Inspection of at least once per calendar year.’ The additional wording regarding local
and environmental factors may cause unnecessary confusion for some. In Section 1.3.2, the phrase ‘...and
methods to be used...’ should be changed to read, ‘...and methods that may be used....’ to be consistent with
the wording in Section 1.1. Also, the terms ‘operating range’ and ‘rated conditions’ in R1.6 should be clearly
defined in the Standard and added to the NERC Glossary to avoid confusion.
Southern California Edison
Company
Agree
Comments: SCE appreciates and agrees with the Drafting Team’s efforts and approach to revising R1. We
agree with the assignment of a Violation Risk Factor of “Lower.” However, we would like to suggest certain
revisions (included below) for the sake of clarity.R1. Each Transmission Owner shall institute a documented
transmission vegetation management program that describes how it conducts work on its Active Transmission
Line Rights of Way to prevent Sustained Outages due to vegetation, considering all possible locations the
conductor may occupy under the effects of sag and sway throughout its operating range under rated
conditions. The transmission vegetation management program shall specify: [Violation Risk Factor Lower][Time Horizon -Long-term planning]1.1. The methodologies methods that the Transmission Owner may
use to control vegetation.1.2. A Vegetation Inspection frequency of at least once per calendar year that takes
into account local and environmental factors.1.3. An annual work plan that identifies:1.3.1. The applicable
lines to be maintained.1.3.2. The work to be performed and methods to be used.1.3.3. Sufficient flexibility to
adjust to changing conditions and to findings from Vegetation Inspections. Adjustments to the plan within the
year are permissible. 1.3.4. Necessary permitting and scheduling requirements from landowners or regulatory
authorities. 1.4. A process or procedure for responding to an imminent threat of a vegetation related
Sustained Outage. The process or procedure shall specify actions that include communication of the threat to
the responsible control center.1.5. An interim corrective action process for use when the Transmission Owner
is constrained from performing planned vegetation maintenance. 1.6. The maintenance strategies used (such
as minimum vegetation-to- conductor distance or maximum vegetation height) to ensure that Table 1
clearances in Attachment 1 are never violated. The maintenance strategies shall consider the sag and sway
of the conductor throughout its operating range under rated conditions.
Edison Electric Institute
Agree
EEI generally agrees with changes to draft revised R1. In addition, EEI recommends that the SDT consider
an alternative structure for the wording of R 1.6, where the current wording states ‘...specify...maintenance
strategies ... to ensure that Table 1 clearances are never violated.’ To improve clarity and better reflect the
intent for this requirement as stated in the Technical Paper, EEI suggests consideration of the language
directly from the Technical Paper (p. 24). Thus, the requirement could be edited to state: “Maintenance
strategies must be designed to a) meet the Table 1 clearances in Attachment 1 and b) consider all possible
15
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
locations of the conductor for rated design conditions.” Companion M 1.6 could be revised to state:
“Transmission Owner has evidence of its consideration of the range of all possible positions of conductors
and line loading variables.”FERC Order No. 693 does not direct NERC to establish minimum inspection
cycles. Rather, FERC stated a goal for the Standard to ‘...assure that transmission owners conduct
inspections at reasonable intervals.’ (Order 693, P. 720) EEI recommends the SDT consider an alternative
to the proposed annual inspection minimum requirement. In some regions of North America for some
companies, or for parts of service territories for some companies, inspections for vegetation issues are
irrelevant, or, needed significantly less frequently than an annual basis. At the other end of the spectrum, a
company-wide annual requirement could inadvertently ‘lower the bar.’ On either side of the spectrum, a ‘one
size fits all’ approach may have unintended consequences that challenge the ability for companies to maintain
realistic inspection cycles. Therefore, EEI recommends that the SDT consider an alternative to R 1.2 to state
that descriptions of inspection cycle frequencies should be included in the vegetation management program
annual plan under R 1.3, including reasoning for inspection frequency basis. Should the SDT choose to not
revise this requirement, EEI notes that provisions of the Standards Development Procedures manual, both for
entity variance and regional variance for an area less than an Interconnection in size (Standards
Development Procedures, p. 27), may be an alternative to the extent that vegetation issues within a company
service territory, or a geographic area that includes parts of several company service territories, reflect
conditions that do not require performance at the level stated within a requirement.Revised draft R 1.6 states
that maintenance strategies in companies’ vegetation management programs must consider ‘sag and sway of
the conductor throughout its operating range under rated conditions.’Since neither ‘operating range’ nor ‘rated
conditions’ are defined NERC terms, this requirement could be open to broad interpretation. As a result, EEI
recommends that the SDT consider alternatives that will reduce potential ambiguity. FAC-003 currently
requires Clearance 2 to be maintained for ‘all rated electrical operating conditions.’ This suggests to EEI that
vegetation clearances should be set in a manner such that required clearances will be maintained for
conditions that include line loadings at both Normal and Emergency Ratings. EEI recommends that the SDT
consider additional specificity. If the term ‘operating range under rated conditions’ is retained, it should be
clearly defined. For example, the Requirement could include explicit references to Normal Ratings and
Emergency Ratings used in other FAC -class Standards, coupled with a Measurement that a Registered
Entity can demonstrate that Ratings applied to FAC-003 are the same as those used elsewhere.
National Grid
Agree
National Grid encourages the drafting team to leave the reference to A.N.S.I. A300 in the standard.
PacifiCorp
Agree
PacifiCorp thinks it is very important for improved reliability to directly reference ANSI A300, rather than
relegate it to a footnote. ANSI A300 is science-based, and proven to be effective. Directly referencing
adherence to A300 will encourage uniform compliance with FAC-003 across North America. Without this
reference, PacifiCorp fears grid stability could be threatened by ineffective practices applied by utilities that
lack sufficient expertise to manage their systems. PacifiCorp believes that those utilities could create future
16
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
blackouts due simply to a lack of understanding about proper utility vegetation management practices.
Consequently, PacifiCorp urges direct reference to A300 within the standard. PacifiCorp believes eliminating
clearance 1 will be detrimental to reliability. Clearance 1 is important for utilities to account for the dynamics of
conductor movement and vegetative growth. This required analysis should lead to development of a more
informed vegetation management program. Clearance 1 also gives utilities leverage with landowners,
governmental agencies and local regulators to achieve the necessary operational clearances. If the only
required clearance is the R4 Minimum Vegetation Clearance Distance, landowners and local regulators will
push the utility to maintain a little more than those clearances rather than properly taking tree growth into
account.
Pepco Holdings, Inc - Affiliates
(PHI)
Xcel Energy
Agree
PHI understands that the SDT was responding to FERC Order 693, but feels there has been a one-size-fitsall approach. An approach as taken in PRC-005 could be used whereby the Transmission Owner could state
its basis for vegetation maintenance cycles.Neither -operating range- nor -rated conditions- are defined NERC
terms; this requirement could be open to broad interpretation. As a result, PHI recommends that the SDT
consider alternatives that will reduce potential ambiguity. FAC-003 currently requires Clearance 2 to be
maintained for -all rated electrical operating conditions-. This suggests that vegetation clearances should be
set in a manner such that required clearances will be maintained for conditions that include line loadings at
both Normal and Emergency Ratings. PHI recommends that the SDT consider additional specificity.
Disagree
(a) The requirement in R1.2 that mandates an annual inspection is too onerous. Xcel Energy urges the
retention of the provision in the existing standard that allows the Transmission Owner to set the frequency of
inspection. In some areas of the country, annual inspections may not be adequate. Yet in other areas, a
longer inspection frequency may be perfectly reasonable and practical. Our point is that inspection frequency
should not be treated as if it were “one size fits all”. If treated this way, we feel this could pose a risk to
reliability and is not likely to be cost-effective. The Transmission Owner should be allowed some flexibility.
However, if the drafting team disagrees and determines that an annual inspection is to be mandated, Xcel
Energy believes that an exception to the annual inspection is appropriate when a non-subjective advanced
technology such as LIDAR is utilized to achieve actual clearance distances. This places the Transmission
Owner in a situation where it can rationally determine that the objectively measured distances result in a
situation where an inspection need not be performed within the next year. It is suggested that R1.2 be
revised to read as follows: Specify a Vegetation Inspection frequency of at least once per calendar year that
takes into account local and environmental factors, unless the Transmission Owner, based on a nonsubjective advanced technology, such as LIDAR, determines that a longer inspection period is appropriate.(b)
R1.5: the word “temporarily” needs to be removed. Some constraints are not of a temporary nature. One
example would be the U.S. Forest Service’s refusal to allow trimming or removal in accordance with the
Transmission Owner’s vegetation management guidelines; another exists in the case where the easement or
other instrument allowing the Transmission Owner to occupy the land does not allow vegetation management
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
in accordance with the Transmission Owner guidelines. In such situations, an interim corrective action
process is appropriate but the word “temporarily” is not.(c) Section R1.6 should be reworded. The existing
language is troublesome and confusing. A better alternative would be: "Maintenance strategies must be
designed to (a) meet the table 1 clearances in attachment 1, and (b) consider all possible locations of the
conductor for rated design conditions."
MRO NERC Standards Review
Subcommittee
Disagree
A. The requirement in R1.2 that mandates an annual inspection is too onerous. The MRO NSRS urges the
retention of the provision in the existing standard that allows the Transmission Owner to set the frequency of
inspection. In some areas of the country, annual inspections may not be adequate. Yet in other areas, a
longer inspection frequency may be perfectly reasonable and practical. Our point is that inspection frequency
should not be treated as if it were “one size fits all”. If treated this way, the MRO NSRS feels this could pose
a risk to reliability and is not likely to be cost-effective. The Transmission Owner should be allowed some
flexibility. However, if the drafting team disagrees and determines that an annual inspection is to be
mandated, the MRO NSRS believes that an exception to the annual inspection is appropriate when a nonsubjective advanced technology such as LIDAR is utilized to achieve actual clearance distances. This places
the Transmission Owner in a situation where it can rationally determine that the objectively measured
distances result in a situation where an inspection need not be performed within the next year. Additionally,
the MRO NSRS feels “that takes into account local and environmental factors” is explanatory text and is
inappropriate for a requirement. It is suggested that R1.2 be revised to read as follows: Specify a Vegetation
Inspection frequency of at least once per calendar year, unless the Transmission Owner, based on a nonsubjective advanced technology, such as LIDAR, determines that a longer inspection period is appropriate.B.
R1.5: the word “temporarily” needs to be removed. Some constraints are not of a temporary nature. For
example, the U.S. Forest Service’s refusal to allow trimming or removal in accordance with the Transmission
Owner’s vegetation management guidelines, or in the case where the easement or other instrument allowing
the Transmission Owner to occupy the land does not allow vegetation management in accordance with the
Transmission Owner guidelines. In such a situation, an interim corrective action process is appropriate but
the word “temporarily” is not. What happens if it’s more than “temporarily”?C. R1.6 should be reworded. The
existing language is troublesome and confusing. A better alternative would be: "Maintenance strategies must
be designed to (a) meet the table 1 clearances in attachment 1, and (b) consider all possible locations of the
conductor for rated design conditions." D. R1.3.3 states that the annual work plan shall....”Be flexible to
adjust to changing conditions and to findings from Vegetation Inspections. Adjustments to the plan within the
year are permissible.” The MRO NSRS is concerned that the wording would not allow a situation where the
work plan is not entirely implemented “within the year”. There may be instances where you may be justified to
postpone the work planned at the end of the year and must be moved into early part of the following year.
We understand that this was the SDT’s intent; however, the text is not clear that it allows for such deferments.
We recommend modifying the requirement to read, “Be flexible to adjust to changing conditions and to
findings from Vegetation Inspections. Adjustments to the plan including work deferments into a subsequence
18
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
year’s work plan are permissible.” E. R1.4 states that a process or procedure for response to an imminent
threat of vegetation-related sustained outage is required. The MRO NSRS believes that the term “imminent
threat” should be a NERC defined term. F. (R1) Since neither “operating range” nor “rated conditions” are
defined NERC terms, this requirement R1 could be open to broad interpretation. As a result, the MRO NSRS
recommends that the SDT consider alternatives that will reduce potential ambiguity. FAC-003 currently
requires Clearance 2 to be maintained for ‘all rated electrical operating conditions.’ This suggests that
vegetation clearances should be set in a manner such that required clearances will be maintained for
conditions that include line loadings at both Normal and Emergency Ratings. The MRO NSRS recommends
that the SDT consider additional specificity. Or, we recommend these two terms (“operating range” and
“rated conditions”) be defined by the SDT.
Consolidated Edison Company of
New York Inc.
Disagree
Although CECONY agrees that each TO should be required to have a documented TVMP, we recommend
changing the wording in Sections 1.2 and 1.3.2.In Section 1.2, CECONY recommends the wording to read,
‘Specify a Vegetation Inspection of at least once per calendar year.’ The additional wording regarding local
and environmental factors may cause unnecessary confusion for some. In Section 1.3.2, the phrase ‘...and
methods to be used...’ should be changed to read, ‘...and methods that may be used....’ to be consistent with
the wording in Section 1.1. Also, the terms ‘operating range’ and ‘rated conditions’ in R1.6 should be clearly
defined in the Standard and added to the NERC Glossary.
FirstEnergy Corp
Disagree
Although we mostly agree with Req. R1, we offer the following suggestions for improvement:Main Req. R1 We suggest replacing the phrase "that describes how it conducts work" with "that describes vegetation control
methods on its Active Transmission Line Right Of Way". We feel our proposed change more accurately
describes the intent of the TVMP.Part 1.2 - We feel the phrase "local and environmental factors" is ambiguous
and open to varying interpretations. We suggest R1.2 read "Specify a Vegetation Inspection frequency of at
least once per calendar year." (Delete the remainder of the sentence).Part 1.3.3 - Regarding the second
sentence "Adjustments to the plan within the year are permissible", we feel it would be clearer if it was
changed to simply "Adjustments to the plan are permissible". There may be situations beyond the entity’s
control, where the work plan is not entirely implemented "within the year". These situations would justify the
work being postponed and completed in the early part of the following year. FE believes this change
maintains the intent of the drafting team based on the reference White Paper that permits deferral of work for
various reasons. Part 1.6 - FE believes that this sub-part of R1 is redundant and and suggests it be removed.
The primary R1 requirement text already references the need to consider all possible conductor locations and
the effects of swag and sway. Additionally, sub-parts 1.1 - 1.5 will achieve the outcome which 1.6 is seeking.
Parts 1.1 - 1.5 identify the strategies used to ensure that Table 1 clearances are not violated, which is
accomplished through specifying vegetation control methods, requiring an annual inspection, adjusting the
work plan to incorporate the inspection findings, allowing time for permitting and scheduling, having an
imminent threat procedure and requiring an interim corrective action process. Requiring the Transmission
19
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
Owner to meet 1.6 by either identifying vegetation to conductor clearance in addition to Table 1, removing all
trees on the active ROW, or managing vegetation at a maximum height, as the SDT has suggested, adds
specificity that is burdensome and may lead to greater potential for a Transmission Owner to violate its own
TVMP, in addition to the requirements already in place. If the SDT wants to merely assure that the TVMP
adheres to the clearances specified in Table 1, then we suggest removing Part 1.6, and adding the following
wording after "documented transmission vegetation management program" in the body of the text of main
Requirement R1: "that adheres to the minimum vegetation clearance distances specified in Table 1 of
Attachment 1".
Northern Indiana Public Service
Company
Disagree
As written, the definition of "Active Transmission Right of Way" leaves it up to each T.O. to determine what is
"active" and what is "inactive" R.O.W. The dimensions or physical description of these areas for any given
R.O.W. are not required to be defined or documented by the T.O. in the TVMP or anywhere else for that
matter. This creates the possibility for a T.O. to avoid violations of this standard or to inappropriately reduce
maintenance activities by simply declaring that any offending vegetation resides in an inactive area. For
Example: The T.O. typically maintains a R/W clear of trees 75 ft. to the side of the conductor. However, over
a period of time, the T.O. allows trees to encroach in from the sides in several spans so that there is only 50
ft. of side clearance. A tree 60 ft. to the side in this narrowed area falls into the conductors but the T.O.
declares the tree to have fallen from an inactive R.O.W. area since it wasn't actively being maintained. This is
a major loophole that needs to be addressed. Am in agreement with R1.1 through R1.4. Disagree with the
inclusion in R1.5 of the term "temporarily" when there are constraints on completing vegetation maintenance
work. It is unimportant whether or not a constraint is temporary or permanent. What is important is that work
cannot be completed as planned. When this happens, the T.O. needs to use a corrective process or
implement mitigation measures in response to the constraint. The Technical Reference provides examples of
permanent constraints such as "the discovery of easement stipulations which limit the T.O.'s rights" along with
temporary constraints. This acknowledges the fact that any constraint, regardless of duration, should be
addressed through a corrective action process or mitigation plan.
Oncor Electric Delivery
Disagree
Comments: Part 1.3.3. allows adjustments to the plan within the year but does not allow work to be deferred
until the next year. This deferral of work impacts 1.3.1, 1.3.2 (possibly 1.3.4) but does not impact the
reliability of the line. “Following the Annual Plan” should accommodate a TO responding to changing
conditions (to include permitting and scheduling) and should not necessarily place a TO out of compliance.
Are adjustments made outside of the plan year considered to be “missing” in Part 1.3.3 by definition of High
VSL for R1?Part 1.3.4 states a TO should consider permitting and scheduling requirements in developing
their annual plan. What if a TO took into consideration these requirements and the timing of these issues
took longer than anticipated? These types of variables may result in the deferral of some line work until the
next year. Requirement 1.3 should clarify what the compliance status of a TO if plan specified line work was
not implemented that year due to permitting and scheduling issues?Consider: Adjustments to the plan within
20
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
the year are permissible. This could be inserted at 1.3 to cover all parts or just 1.3.3 and 1.3.4. In its current
state, only 1.3.3 (Changes to conditions and Findings from Vegetation Inspections) is addressed.
Vegetation Management Team
Disagree
Comments: Disagree with R1.2 - Inspection Frequency. Very prescriptive. Please consider allowing TO’s to
select the frequency that best fits their requirements. BGE currently defines their inspection frequency as
annually during the non-growing season, October 1 to May 1. Under the proposed language scheduling would
be very challenging. Disagree with 1.3.3 which states that the annual work plan shall “Be flexible to adjust to
changing conditions and to findings from vegetation inspections. Adjustment to the plan within the year are
permissible.”This wording would not allow a situation where the work plan is not entirely implemented “within
the year”. There may be times where one may be justified to postpone work that is planned for the end of the
year to be moved to the first part of the following year. We suggest removing the words “within the year” from
R.1.3.3Disagree with R1.6 and M1.6 The purpose of the TVMP is to prevent vegetation related outages and
improve the reliability of the electric system. The imminent threat provision allows for a procedure to address
imminent threats before they become violations. (R1.4). Therefore, as long as the TO follows the imminent
threat procedure, then a violation will not result. A violation will result only if the TO does not have an
imminent threat procedure or fails to implement that procedure. Merely having an imminent threat is not a
violation. By comparison, the new draft states any observed encroachments are reportable violations
because the requirements do not permit a procedure to address encroachments. (See R1.6, R3. R4). The
better approach would be to require the remediation of encroachments according to a TVMP but not make
every found encroachment a violation. An encroachment is not necessarily “likely to cause a Sustained
Outage at any moment,” the level of severity required to be an imminent threat. (p.20). It is logical to
conclude that imminent threats are more severe than encroachments. In fact, the technical report states that
an encroachment due to operation of a transmission line beyond its recognized rating is beyond the scope of
R4, the requirement for prevention of encroachments. (p.31). If this is the case, just like the process by which
the TO is given the opportunity to address imminent threats, encroachments should also be addressed via a
pre-determined process before becoming a violation of the standard. Further the requirement as drafted is a
disincentive to deploy more sophisticated tools to identify threats to its system, such as software-enabled
LiDAR Therefore, we suggest the following changes to the requirements: R1.6: require a process or
procedure for response when any [REMOVE: specify the maintenance strategies used (such as minimum
vegetation-to-conductor distance or maximum vegetation height) to ensure that] Table 1 clearances in FAC003-2-Attachment 1 are never violated are encroached upon.M1.6: The Transmission Owner’s transmission
vegetation management program documentation specifies [REMOVE: the maintenance strategies used (such
as minimum vegetation-to-conductor distance or maximum vegetation height) to ensure that] an
encroachment process or procedure for responding if any Table 1 clearances in FAC-003-2-Attachment 1
[REMOVE: are never violated] are encroached upon. The maintenance strategies consider the sag and sway
of the conductor throughout its operating range under rated conditions.
21
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
Hydro-Quebec TransEnergie
(HQT)
Disagree
Each TO should be required to have a documented TVMP. Recommend changing the wording in Sections
1.2 and 1.3.2.In Section 1.2, recommend changing the wording to read, ‘Specify a Vegetation Inspection
frequency.’ The minimum frequecy should be left to the TO according to its system and environment
characteristics. also, the additional wording regarding local and environmental factors may cause
unnecessary confusion for some. In Section 1.3.2, the phrase ‘...and methods to be used...’ should be
changed to read, ‘...and methods that may be used....’ to be consistent with the wording in Section 1.1. Also,
the terms ‘operating range’ and ‘rated conditions’ in R1.6 should be clearly defined in the Standard and added
to the NERC Glossary to avoid confusion. There is an inconsistency between R1.2 and R3. R1.2 requires
the TO to carry out inspections at least once per calendar year. R3 requires the TO to carry out inspections
per the frequency defined in its vegetation management program. It is preferred that the TO be allowed to
specify the frequency and timing as stated in R3. Once per calendar year is not sensitive to local and
environmental factors. For example, facilities in the Northeast are located in an environment where there is a
long (7-8 month) dormant period -vegetation does not grow. Specify a frequency of one inspection per
dormant period. This inspection could take place between September and April annually. In one dormant
period we might inspect in November and inspect again 14 months later in January. We would meet the
inspection need per R3, but fail to have inspected in a calendar year, thus violating R1.2. Other TO’s may be
located in parts of the country with little or no vegetation and not need a once per calendar year inspection.
Thus, R1.2 should allow the TO to specify an inspection program that is sensitive to local and environmental
factors, not the calendar.
Independent Electricity System
Operator
Disagree
Each TO should be required to have a documented TVMP. Recommend changing the wording in Sections
1.2 and 1.3.2.In Section 1.3.2, the phrase ‘...and methods to be used...’ should be changed to read, ‘...and
methods that may be used....’ to be consistent with the wording in Section 1.1. Also, the terms ‘operating
range’ and ‘rated conditions’ in R1.6 should be clearly defined in the Standard and added to the NERC
Glossary to avoid confusion. There is an inconsistency between R1.2 and R3. R1.2 requires the TO to
carry out inspections at least once per calendar year. R3 requires the TO to carry out inspections per the
frequency defined in its vegetation management program. It is preferred that the TO be allowed to specify the
frequency and timing as stated in R3. Once per calendar year is not sensitive to local and environmental
factors. For example, facilities in the Northeast are located in an environment where there is a long (7-8
month) dormant period -vegetation does not grow. Specify a frequency of one inspection per dormant period.
This inspection could take place between September and April annually. In one dormant period we might
inspect in November and inspect again 14 months later in January. We would meet the inspection need per
R3, but fail to have inspected in a calendar year, thus violating R1.2. Other TO’s may be located in parts of
the country with little or no vegetation and not need a once per calendar year inspection. Thus, R1.2 should
allow the TO to specify an inspection program that is sensitive to local and environmental factors, not the
calendar.If the above suggestion is not accepted, recommend changing the wording in Section 1.2 to read,
22
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
‘Specify a Vegetation Inspection of at least once per calendar year.’ Also, the additional wording regarding
local and environmental factors may cause unnecessary confusion for some.
ISO New England Inc.
Disagree
Each TO should be required to have a documented TVMP. Recommend changing the wording in Sections
1.2 and 1.3.2.In Section 1.2, recommend changing the wording to read, ‘Specify a Vegetation Inspection of at
least once per calendar year.’ The additional wording regarding local and environmental factors may cause
unnecessary confusion for some. In Section 1.3.2, the phrase ‘...and methods to be used...’ should be
changed to read, ‘...and methods that may be used....’ to be consistent with the wording in Section 1.1. Also,
the terms ‘operating range’ and ‘rated conditions’ in R1.6 should be clearly defined in the Standard and added
to the NERC Glossary to avoid confusion. There is an inconsistency between R1.2 and R3. R1.2 requires
the TO to carry out inspections at least once per calendar year. R3 requires the TO to carry out inspections
per the frequency defined in its vegetation management program. It is preferred that the TO be allowed to
specify the frequency and timing as stated in R3. Once per calendar year is not sensitive to local and
environmental factors. For example, facilities in the Northeast are located in an environment where there is a
long (7-8 month) dormant period -vegetation does not grow. Specify a frequency of one inspection per
dormant period. This inspection could take place between September and April annually. In one dormant
period we might inspect in November and inspect again 14 months later in January. We would meet the
inspection need per R3, but fail to have inspected in a calendar year, thus violating R1.2. Other TO’s may be
located in parts of the country with little or no vegetation and not need a once per calendar year inspection.
Thus, R1.2 should allow the TO to specify an inspection program that is sensitive to local and environmental
factors, not the calendar.
Northeast Power Coordinating
Council--RSC
Disagree
Each TO should be required to have a documented TVMP. Recommend changing the wording in Sections
1.2 and 1.3.2.In Section 1.2, recommend changing the wording to read, ‘Specify a Vegetation Inspection of at
least once per calendar year.’ The additional wording regarding local and environmental factors may cause
unnecessary confusion for some. In Section 1.3.2, the phrase ‘...and methods to be used...’ should be
changed to read, ‘...and methods that may be used....’ to be consistent with the wording in Section 1.1. Also,
the terms ‘operating range’ and ‘rated conditions’ in R1.6 should be clearly defined in the Standard and added
to the NERC Glossary to avoid confusion. There is an inconsistency between R1.2 and R3. R1.2 requires
the TO to carry out inspections at least once per calendar year. R3 requires the TO to carry out inspections
per the frequency defined in its vegetation management program. It is preferred that the TO be allowed to
specify the frequency and timing as stated in R3. Once per calendar year is not sensitive to local and
environmental factors. For example, facilities in the Northeast are located in an environment where there is a
long (7-8 month) dormant period -vegetation does not grow. Specify a frequency of one inspection per
dormant period. This inspection could take place between September and April annually. In one dormant
period we might inspect in November and inspect again 14 months later in January. We would meet the
inspection need per R3, but fail to have inspected in a calendar year, thus violating R1.2. Other TO’s may be
23
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
located in parts of the country with little or no vegetation and not need a once per calendar year inspection.
Thus, R1.2 should allow the TO to specify an inspection program that is sensitive to local and environmental
factors, not the calendar.
American Transmission
Company
Disagree
FERC Order No. 693 does not direct NERC to establish minimum inspection cycles. Rather, FERC stated a
goal for the Standard to ‘...assure that transmission owners conduct inspections at reasonable intervals.’
(Order 693, P. 720)ATC recommends that that the SDT drop the “once per year” language from the
requirement and replace it with the following language:”Document a Vegetation Inspection frequency that
considers local and environmental factors.” ATC believes that this language is in alignment with
Commission’s Order 693 and responsive to maintaining system reliability.The current language a) limits the
ability of an entity to set a longer inspection cycle if its local / environmental and b) requires entities to justify
the once per year cycle. ATC believes that the SDT needs to address this concern by making modifications
to the requirement in order to prevent entities from allocate funds on efforts that do not benefit the BPS. R
1.3.3 states that the annual work plan shall....”Be flexible to adjust to changing conditions and to findings from
Vegetation Inspections. Adjustments to the plan within the year are permissible.”ATC is concerned that the
wording would not allow a situation where the work plan is not entirely implemented “within the year”. There
may be instances where you may be justified to postpone the work planned at the end of the year and must
be moved into early part of the following year. ATC recommends removing the words “within the year “in
R1.3.3.R 1.4 states that a process or procedure for response to an imminent threat of vegetation-related
sustained outage is required. ATC believes that the term “imminent threat” should be a NERC defined term.
An alternate option is to include the following language “imminent threat as defined by the entity”. This makes
it clear that the entity is allowed to define the term. ATC recommends that the SDT consider an alternative
structure for the wording of R 1.6, where the current wording states ‘...specify...maintenance strategies ... to
ensure that Table 1 clearances are never violated.’To improve clarity and better reflect the intent for this
requirement as stated in the Technical Paper, ATC suggests consideration of the language directly from the
Technical Paper (p. 24). Thus, the requirement could be edited to state: “Maintenance strategies must be
designed to a) meet the Table 1 clearances in Attachment 1 and b) consider all possible locations of the
conductor for rated design conditions.”R 1.6 states that maintenance strategies in companies’ vegetation
management programs must consider ‘sag and sway of the conductor throughout its operating range under
rated conditions.’ Since neither ‘operating range’ nor ‘rated conditions’ are defined NERC terms, this
requirement could be open to broad interpretation. As a result, ATC recommends that the SDT consider
alternatives that will reduce potential ambiguity. FAC-003 currently requires Clearance 2 to be maintained for
‘all rated electrical operating conditions.’ This suggests that vegetation clearances should be set in a manner
such that required clearances will be maintained for conditions that include line loadings at both Normal and
Emergency Ratings. ATC recommends that the SDT consider additional specificity.
24
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
JEA
Disagree
Please review the work being done by the ad hoc committee headed by Gerry Cauley that is attempting to
guide standard development towards results or performance based requirements. It seems that vegetation
management can be handled by this approach and that the paperwork requirement for a documented policy
produces a heavy paperwork burden without requisite benefit to reliability added. However, the requirement
for a documented procedure for "Imminent Threats" is appropriate as this is in essense an emergency
response planning requirement. The requirement for an annual work plan is also appropriate as it is a
requirement to demonstrate that appropriate planning is being done to meet the objectives of this standard.
Public Service Co. of New
Mexico
Disagree
PNM prefers the Clearance 1/Clearance 2 setup. PNM does not like the MVCD classification as it implies - to
the general public - that the MVCD is the only clearance needed. The distances are extremely small. We as
a utility company realize this is only the "minimum" distance however it will not be interpreted that way by
others outside our industry. Either go back to the Clearance 1 & 2 designation or change the MVCD name to
illustrate the criticality of these clearances. Suggestions: Critical Vegetation Clearance Distance or Imminent
Threat Vegetation Clearance Distance.Secondly, PNM believes there needs to be some sort of minimum
qualifications for those individuals responsible for development and implementation of TVMP.
Manitoba Hydro
Disagree
R 1.2 states that the TVMP shall “Specify a Vegetation Inspection frequency of at least once per calendar
year that takes into account local3 and environmental factors.”R 1.2 should read: “Specify a Vegetation
Inspection frequency of at least once per calendar year.” (and remove the balance of the sentence)R 1.3.3
states that the annual work plan shall....”Be flexible to adjust to changing conditions and to findings from
Vegetation Inspections. Adjustments to the plan within the year are permissible.”The wording would not allow
a situation where the work plan is not entirely implemented “within the year”. There may be instances where
you may be justified to postpone the work planned at the end of the year and must be moved into the
following year, or an alternative strategy assigned, pushing the work even further out. Remove the words
“within the year “in R1.3.3.R 1.4 states that a process or procedure for response to an imminent threat of
vegetation-related sustained outage is required. The term “imminent threat” should be a NERC defined term.
The SDT should consider an alternative structure for the wording of R 1.6, where the current wording states
‘...specify...maintenance strategies ... to ensure that Table 1 clearances are never violated.’To improve clarity
and better reflect the intent for this requirement as stated in the Technical Paper, consider the language
directly from the Technical Paper (p. 24). Thus, the requirement could be edited to state: “Maintenance
strategies must be designed to a) meet the Table 1 clearances in Attachment 1 and b) consider all possible
locations of the conductor for rated design conditions.”R 1.6 states that maintenance strategies in companies’
vegetation management programs must consider ‘sag and sway of the conductor throughout its operating
range under rated conditions.’ Since neither ‘operating range’ nor ‘rated conditions’ are defined NERC terms,
this requirement could be open to broad interpretation. As a result, the SDT should consider alternatives that
will reduce potential ambiguity. FAC-003 currently requires Clearance 2 to be maintained for ‘all rated
25
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
electrical operating conditions.’ This suggests that vegetation clearances should be set in a manner such that
required clearances will be maintained for conditions that include line loadings at both Normal and Emergency
Ratings. The SDT should consider additional specificity.
Progress Energy Carolinas, Inc.
Disagree
R 1.3.3 states that the annual work plan shall....”Be flexible to adjust to changing conditions and to findings
from Vegetation Inspections. Adjustments to the plan within the year are permissible.”The wording as
proposed would not allow situations where the “work plan” is not entirely implemented “within the year”, which
conflicts with the requirement to be flexible and adjust to changing conditions. To eliminate this conflict
between requirements, PEC recommends removing the words “within the year “in R1.3.3.
Lee County Electric Cooperative
Disagree
R1 1.5 - define 'temporarily'. Alternative: Define a maximum period of time. ex: beyond one inspection cycle,
or based on environmental conditions, one growth cycle; or based on when access was restricted - when the
last or next inspection occurred or is scheduled to occur.
CenterPoint Energy
Disagree
R1 refers to “Active Transmission Line Rights of Way” which are not defined as to their limits within the
Standard. The SDT has indicated in its response to 1st Draft Comments from CenterPoint Energy that the
“...Transmission Owner is responsible for defining the Active Transmission Line Right of Way.” However, that
determination clause is not included in the current definition. CenterPoint Energy recommends deleting the
phrase “on its Active Transmission Line Rights of Way” from R1. The phrase, “...considering all possible
locations the conductor may occupy under the effects of sag and sway throughout is operating range and
under rated conditions” , by itself defines the airspace that must be maintained. R1.6 adds the MVCD
distance requirement to the sag and sway geometry further defining the airspace that must be maintained.
R1 requires no specific definition of a right of way.As written, R1 does not address how a utility conducts its
work to address the fall-in of trees into an adjacent transmission line. The determination of the limits of the
right of way are only necessary in the Standard for determining the reporting exceptions for certain Sustained
Outages in R8 (fall-in) as evidenced in measure M8 through self-certification reports.The Standard and the
Technical Reference provide no specific justification for defining a 1-year inspection frequency in R1.2. The
requirement itself does not take into account “local and environmental factors”, which may indicate a longer
inspection frequency is warranted. The Technical Reference states that the inspection frequency is required
to be “at least once per calendar year”. The SDT’s only justification for this determination is found in its
response to 1st Draft Comments, “...the consensus of the SDT is that inspection of any operating
transmission line should be done annually... “. This statement alone is not compelling. No further supporting
arguments have been provided. CenterPoint Energy believes that this minimum inspection frequency is
arbitrary and is not necessary or appropriate for all registered entities. Registered entities are in the best
position to determine appropriate inspection frequencies that take into account local and environmental
factors found in their service territories. CenterPoint Energy strongly recommends that R1.2 be revised to
allow the registered entity to determine the appropriate inspection frequency for their service territory. The
26
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
revised R1.2 would read “Specify a Vegetation Inspection frequency that takes into account local and
environmental factors to prevent Sustained Outages.”
Platte River Power Authority
Vegetation Management Group
Disagree
R1. currently says "...under rated conditions". It should say "...under Rated Electrical Operating Conditions" a
NERC defined term. Defined as: The specified or reasonably anticipated conditions under which the electrical
system or an individual electrical circuit is intend/designed to operate.Although we appreciate the SDT’s need
to address a minimum vegetation inspection frequency as ordered by FERC directive 693, we believe that
system conditions vary too widely from utility to utility and even within utilities to specify a Vegetation
Inspection (VI) frequency of at least once per calendar year in R1.2. We think the SDT should consider
making the minimum VI broader to cover different vegetation types and local factors. R1.3. Should be
consistent in wording with R1.1. and R1.2. as follows: 1.3. Specify an annual work plan that shall:We agree
with the SDT to remove the ‘fill in the blank’ requirement for personnel requirements in FAC-003-1.R1.3.2.
"Identify the work to be performed and methods to be used", is redundant as it is address in other requirement
in the standard. The work to be performed is included under R1. “...that describes how it conducts work” and
the methods to be used is included under R1.1. Specify the methods that the TO may use to control
vegetation. R1.3.3. Should read: Be flexible to adjust to changing conditions of the vegetation on the Active
Transmission Line ROW, emergencies, and other significant changing conditions found during Vegetation
Inspections. Adjustments to the plan within the year are permissible but must always ensure the reliability of
the electric transmission system.R1.4. Should be consistent in wording with R1.1. and R1.2. as follows:1.4.
Specify a process or procedure...We believe that mitigation measures in R1.4 of FAC-003-1 are better than
the new corrective action process in R1.5 of FAC-003-2. However, if it is decided to keep R1.5. the SDT
should remove the words “interim” and “temporarily” as they do not provide clarity. Some constraints are
permanent or long-term and it would be appropriate to have a corrective action process to address all
constraints. R1.6. currently says, "... under rated conditions". It should say, "... under Rated Electrical
Operating Conditions" a NERC defined term. We have some concern that the general public will misinterpret
the Table 1 clearances in Attachment 1 and expect constant maintenance in order to allow their vegetation to
be as close to line as possible at all times. The addition of a critical clearance distance to be achieved at the
time of work, similar to the Clearance 1 in FAC-003-1 may explain why you need more clearance distance.
Transmission Owner
Disagree
R1., 1.3.,1.3.2. Should read: Identify the work to be performed. The method does not contribute to reliability
and places an un-needed burden on auditor and Transmission Owner. R1., 1.4. The term Imminent Threat is
vague. FPL recommends that the Transmission Owner should be directed to define it based on its
construction and local environmental conditions.
Salt River Project
Disagree
R1.3: In “Require an annual work plan” recommend changing the word “require” to “define”. R1.5: This
appears to replace the old R1.4. Suggest changing back to how it was worded in R1.4, a better description.
27
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
As there was a need to replace “mitigation” and alternative would be to place with “corrective action”.
Puget Sound Energy
Disagree
Requirement 1.6, while a good theory statement, does not have the impact of Clearance 1 in the existing
standard. When agencies and reluctant landowners look at this standard, they will not see this requirement
the same way Clearance 1 is seen. Requirement 1.6 will be seen as a procedural, not a justification for
utilizing utility best management practices for vegetation management. R1.6 indicates that the maintenance
strategy used must be specified and then identifies “minimum vegetation to conductor distance” as an
example strategy. The minimum vegetation to conductor distance as table 1 is titled is the goal of the
strategy, but not a strategy. This creates confusion regarding the intention of this requirement. Modify R1.6
to read “Ensure Table 1 Attachment 1 clearances are never violated considering sag and sway of the
conductor throughout its operating range under rated conditions and local vegetation characteristics and
factors under non-storm weather variances.” Because the distances in Table 1 are so small, it could appear to
a non-familiar customer or local agency that the standard is becoming less stringent raising even more
opportunity for customer resistance and the need to create more unique interim corrective actions to manage.
The inability of an entity to follow a consistent plan raises the risk of non-compliance.
Central Maine Power an Energy
East Company
Disagree
Suggest that NERC define operating range and rated conditions.
Nebraska Public Power District
Disagree
The requirement in R1.2 should allow the Transmission Owner to set the frequency of inspection. The T.O.
should be able to determine what frequency based on their system. We also agree with Xcel on an exemption
if new technology such as LIDAR is used. This will allow the T.O. to determine objectively what vegetation
needs to be addressed and when.R1.4: “imminent threat” needs to be defined.R1.5: delete “temporarily” from
the requirement. This is a difficult word to define and provide guidance on.R1.6 should be reworded using
language from the Technical Paper (p. 24). “Maintenance strategies must be designed to (a) meet the table 1
clearances in attachment 1, and (b) consider all possible locations of the conductor for rated design
conditions.”
Utility Arborist Association
Disagree
The Utility Arborist Association (UAA) considers it imperative to include a requirement for transmission
operators to adopt the science-based, industry accepted practices in ANSI A300. ANSI A300 was designed to
ensure appropriate and effective practices are implemented, while allowing each utility the flexibility to
develop a program that considers site specific factors. The UAA recognizes that there are varying levels of
technical competency within the industry among individual utility vegetation management (UVM) programs.
While the majority of utilities currently apply A300 routinely, there are still those that do not. We believe that
utilities that have failed to implement A300 could potentially become involved in future incidents due to
insufficient understanding of effective utility vegetation management practices. The UAA thinks that FAC-00302 should ensure that all utilities have successful programs to mitigate tree and power line conflicts,
28
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
regardless of their size, budgets and other available resources. A specific requirement to adherence to A300
will ensure that compliance with FAC-003-02 across North America will be uniform and effective. Without this
requirement, we fear that utilities with less robust resources and knowledge may become the weakest link in
the electrical system. As such, the UAA strongly encourages the direct reference to A300 within the standard
rather than as a footnote.
E.ON U.S.
Disagree
This will add significant cost to vegetation management budgets. The MVCD concept will require the use of
LIDAR and will add approximately $250k per year to utility company expenses. These costs include
equipment, training, LIDAR survey and personnel costs.
Arizona Public Service
Disagree
Utilities should be held to following ANSI A-300 standards and BMP’s for best management practices. By
following these standards there wouldn’t be a need for the FAC-003 standard. There should not be a footnote
but a requirement. Personnel qualifications should be a requirement. There are certification programs through
the International Society of Arboriculture that certify a minimum level of competence to manage a vegetation
management program. This also requires ongoing training and education to keep up with the latest
technologies on UVM. NERC and FERC still need to be aware that federal land agencies are making
decisions without any education or knowledge on UVM activities which affect transmission reliability. There
needs to be a clearance 1 requirement in the standard. If utilities are required to follow this standard it gives
them leverage with dealing with these federal land agencies.
Idaho Power Company
Disagree
We agree with letting the Transmission Owner decide on methods to control vegetation management. We
believe personnel qualifications should be included but as determined by the Transmission Owner. We agree
that annual inspections should be required. However, we would prefer R1.3 to read as “Specify an annual
work plan...” rather than “Require an annual work plan...” to be consistent with the other subsections of the R1
requirements. We believe R1 should allow flexibility to integrate technology, in particular Lidar, as an
acceptable patrol.
Ameren
Disagree
Would suggest the term "normal" in front of "sag and sway throughout its operating range"...or " design of" to
address the exceptions for environmental conditions.
ISO/RTO Council
The SRC has no comment on this question.
29
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
2. As stated in the background information above, in response to industry comments, the Requirement for
implementation of Imminent Threat process/procedure (the new R2) is revised. Additionally the SDT assigned
Time Horizons, Violation Risk Factors, and Violation Severity Levels. Do you agree? If not, please explain and
propose an alternative.
Organization
Yes or No
Entegra Power Group LLC
Question 2 Comment
No comment
Ameren
Agree
American Electric Power
Agree
Associated Electric Cooperative,
Inc.
Agree
Bonneville Power Administration
Agree
CenterPoint Energy
Agree
Central Maine Power an Energy
East Company
Agree
Consolidated Edison Company of
New York Inc.
Agree
Duke Energy
Agree
Entergy Services, Inc
Agree
Georgia Transmission
Corporation
Agree
Hydro One Networks inc.
Agree
30
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Hydro-Quebec TransEnergie
(HQT)
Agree
Idaho Power Company
Agree
Independent Electricity System
Operator
Agree
ISO New England Inc.
Agree
JEA
Agree
Manitoba Hydro
Agree
National Grid
Agree
Nebraska Public Power District
Agree
New Brunswick Power
Transmission
Agree
North Carolina Electric
Membership Corporation
Agree
Northeast Power Coordinating
Council--RSC
Agree
Northeast Utilities
Agree
Northern Indiana Public Service
Company
Agree
Oncor Electric Delivery
Agree
Question 2 Comment
31
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Orange and Rockland Utilities,
Inc.
Agree
Pacific Gas and Electric Co.
Agree
Platte River Power Authority
Vegetation Management Group
Agree
Progress Energy Carolinas, Inc.
Agree
Public Service Co. of New
Mexico
Agree
Puget Sound Energy
Agree
ReliabilityFirst Corporation
Agree
SCE&G
Agree
SERC Vegetation Managment
Sub-committee (VMS)
Agree
Southern Company
Agree
Superintendent Transmission
Maintenance
Agree
Tampa Electric Company
Agree
Tenessee Valley Authority
Agree
Tennessee Valley Authority
Agree
Transmission Owner
Agree
Question 2 Comment
32
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
Tucson Electric Power Company
Agree
TVA
Agree
TVA
Agree
TVA
Agree
US Bureau of Reclamation
Agree
Vegetation Management Team
Agree
WECC RC
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Xcel Energy
Agree
Pepco Holdings, Inc - Affiliates
(PHI)
Agree
PHI agrees with the requirement but notes that Operating Process is a NERC defined term. The SDT should
review the definition and use capitalization for Glossary terms.
NERC Standards Review
Subcommittee
Agree
Prefer the distances specified in the current IEEE Standard as opposed to the Gallet equation.
Southern California Edison
Company
Agree
SCE generally agrees with the language of the requirement and the assignments. However, it is unclear why
the Violation Risk Factor is rated as "Medium," rather than "Lower."
Disagree
Although we mostly agree with Req. R2, we offer the following suggestion for improvement. The phrase
"actual knowledge" is ambiguous and could be difficult to measure. For instance, if the responsible entity
receives a voice mail or email regarding an imminent threat, then that would technically mean he has actual
knowledge of the alleged threat; however, only after the entity reviews and confirms the alleged situation can
it be judged a true imminent threat. Therefore, we suggest a change from "actual knowledge" to
FirstEnergy Corp
33
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
"confirmation".
E.ON U.S.
Disagree
E.ON U.S. believes that requirement to prove “no incident occurred” for an audit would be impossible to
accomplishE.ONU.S. believes that the SDT should clarify what is meant by “normal Operating Practices,”
specifically identifying what practices are necessary to ensure compliance with the standard.E.ON U.S.
believes that the proposed standard is in conflict with TOP-1 (the imminent threat procedure could require an
operator to take a line out of service thereby putting the grid at risk).
PacifiCorp
Disagree
PacifiCorp thinks it is very important for improved reliability to directly reference ANSI A300, rather than
relegate it to a footnote. ANSI A300 is science-based, and proven to be effective. Directly referencing
adherence to A300 will encourage uniform compliance with FAC-003 across North America. Without this
reference, PacifiCorp fears grid stability could be threatened by ineffective practices applied by utilities that
lack sufficient expertise to manage their systems. PacifiCorp believes that those utilities could create future
blackouts due simply to a lack of understanding about proper utility vegetation management practices.
Consequently, PacifiCorp urges direct reference to A300 within the standard. PacifiCorp believes eliminating
clearance 1 will be detrimental to reliability. Clearance 1 is important for utilities to account for the dynamics of
conductor movement and vegetative growth. This required analysis should lead to development of a more
informed vegetation management program. Clearance 1 also gives utilities leverage with landowners,
governmental agencies and local regulators to achieve the necessary operational clearances. If the only
required clearance is the R4 Minimum Vegetation Clearance Distance, landowners and local regulators will
push the utility to maintain a little more than those clearances rather than properly taking tree growth into
account.
Arizona Public Service
Disagree
The SDT needs to come up with a standardized format for the imminent threat process. All utilities need to be
audited the same way. This requirement is too vague since it has a VSL of severe. In the beginning of this
document it states the requirement will be clearer and in an unambiguous manner. Here each utility can
make up their process and will be audited differently.
BC Transmission Corporation
Disagree
The STD needs to specify a standardized format for the imminent threat process, this will allow for
consistency in the audit process which is important because the VSL is severe. If each utility specifies their
own process it will be up to the subjectivity of the auditors who often do not have a vegetation management
background to determine if the process is adequate.
Lee County Electric Cooperative
Disagree
This requirement seems redundant to R1. 1.4 The process or procedure required in R1. 1.4 includes
implementing the procedure. Steps taken to mitigate the threat would be documented and could be
considered as implementing the process/procedure. Alternative: either eliminate the new R2 or edit R. 1.4 to
34
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
include evidence.
ISO/RTO Council
The SRC has no comment on this question.
35
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
3. As stated in the background information above, in response to industry comments, the Requirement for
conducting Vegetation Inspections (the new R3) is revised. Additionally the SDT assigned Time Horizons,
Violation Risk Factors, and Violation Severity Levels. Do you agree? If not, please explain and propose an
alternative.
Organization
Yes or No
Entegra Power Group LLC
Question 3 Comment
No comment
Ameren
Agree
American Electric Power
Agree
Associated Electric Cooperative,
Inc.
Agree
Bonneville Power Administration
Agree
Consolidated Edison Company of
New York Inc.
Agree
Duke Energy
Agree
E.ON U.S.
Agree
Entergy Services, Inc
Agree
Georgia Transmission
Corporation
Agree
Lee County Electric Cooperative
Agree
Manitoba Hydro
Agree
36
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Nebraska Public Power District
Agree
New Brunswick Power
Transmission
Agree
North Carolina Electric
Membership Corporation
Agree
Northeast Utilities
Agree
Oncor Electric Delivery
Agree
Pacific Gas and Electric Co.
Agree
PacifiCorp
Agree
Progress Energy Carolinas, Inc.
Agree
Public Service Co. of New
Mexico
Agree
Puget Sound Energy
Agree
SCE&G
Agree
SERC Vegetation Managment
Sub-committee (VMS)
Agree
Southern Company
Agree
Superintendent Transmission
Maintenance
Agree
Tampa Electric Company
Agree
Question 3 Comment
37
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
Tenessee Valley Authority
Agree
Tennessee Valley Authority
Agree
Transmission Owner
Agree
Tucson Electric Power Company
Agree
TVA
Agree
TVA
Agree
TVA
Agree
US Bureau of Reclamation
Agree
Vegetation Management Team
Agree
WECC RC
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
ReliabilityFirst Corporation
Agree
Do we need the parenthetical statement “as measured in line miles”?
Central Maine Power an Energy
East Company
Agree
Inspection frequency should be designed to meet the objective of this standard.
MRO NERC Standards Review
Subcommittee
Agree
MRO NSRS suggests that the referenced footnote 5 be modified to include “species epidemics,” such as bark
beetles; this footnote 5 should be referenced. Additionally, footnote 5 could be modified to include “species
epidemics” between “logging” and “animal severing tree.” R3 states that “Each Transmission Owner shall
conduct Vegetation Inspections of all applicable lines (as measured in line miles) in accordance with the
frequency specified in its transmission vegetation management program, the MRO NSRS recommends that
the phrase “of all applicable lines (as measured in line miles)” be removed from R3. This is understood by
38
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
Applicability section A4.2.
American Transmission
Company
Agree
R 3 states that “Each Transmission Owner shall conduct Vegetation Inspections of all applicable lines (as
measured in line miles) in accordance with the frequency specified in its transmission vegetation
management program,ATC recommends that the phrase “of all applicable lines (as measured in line miles)”
be removed from R 3. This is understood by Applicability section A 4.2.
Southern California Edison
Company
Agree
SCE generally agrees with the language of the requirement, but would suggest the following revision to
Footnote 4 in order to clarify the text:Examples include, but are not limited to, earthquakes, fires, tornados,
hurricanes, landslides, wind shear, fresh gale, ice storms, floods, and major storms as defined either by the
Transmission Owner or an applicable regulatory body.
Hydro One Networks inc.
Disagree
(a) As compared with the current version, the proposed draft is still excessively prescriptive. Depending on
local conditions, an annual inspection may not be necessary. The TO should have the ability to decide on the
frequency of the inspections as long as the reliability of the BES is not compromised. For example,
vegetation growth in Northeastern North America has long (7-8 months) dormant periods. (b) There seems to
be an inconsistency between R1.2 and R3. R1.2 requires the TO to carry out inspections at least once per
calendar year. R3 requires the TOs to carry out inspections per the frequency defined in its TVMP.
According to our comment in (a) above, the TO should have the prerogative of specifying the frequency and
timing as stated in R3. Once per calendar year is not sensitive to local and environmental factors. For
example, vegetation growth in North Eastern North America has a long (7-8 month) dormant period. The
entity should be able to specify a frequency of one inspection per dormant period. This inspection could take
place between September and April annually. In one dormant period there might be an inspection in
November, and an inspection again 14 months later in January. Accordingly, R3 is more appropriate. Other
TOs may be located in parts of the continent with little or no vegetation and not need a once per calendar
year inspection. Thus, R1.2 should allow the TOs to specify an inspection program that is sensitive to local
and environmental factors, not the calendar. (c) In addition, VRFs and VSLs are based on percent of “total
line miles specified by its TVMP”; this statement should be qualified by including something like “total
applicable line miles specified by its TVMP”, as there may be circuits included in a vegetation management
program that are not subject to the FAC-003 standard (sub-200kv, non-IROL lines). This also better aligns
with the text of R3 (“...shall conduct Vegetation Inspections of all applicable lines...”). Also, we would suggest
explicitly stating line kilometers as an acceptable measure for those using the metric system.
Idaho Power Company
Disagree
Include in the exceptions ‘unless constrained by federal and environmental restrictions’ along with natural
disasters. Federal agencies can and have prevented vegetation management measures due to
environmental, biological, and/or cultural concerns. In footnote 4, insect infestation should be added as a form
39
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
of natural disaster. Also, recommend changing ‘major storms’ to ‘major events’ in this footnote.
National Grid
Disagree
National Grid sees inconsistency between R1.2 and R3. R1.2 requires the TO to carry out inspections at
least once per calendar year. R3 requires the TO to carry out inspections per the frequency defined in its
vegetation management program. National Grid prefers that the TO be allowed to specify the frequency and
timing as stated in R3. Once per calendar year is not sensitive to local and environmental factors. For
example, National Grid facilities in the northeast are located in an environment where there is a long (7-8
month) dormant period - vegetation does not grow. National Grid would specify a frequency of one inspection
per dormant period. This inspection could take place between September and April annually. In one dormant
period we might inspect in November and inspect again 14 months later in January. We would meet the
inspection need per R3, but fail to have inspected in a calendar year, thus violating R1.2. Other TO’s may be
located in parts of the country with little or no vegetation and not need a once per calendar year inspection.
Thus, R1.2 should allow the TO to specify an inspection program that is sensitive to local and environmental
factors, not the calendar.
Pepco Holdings, Inc - Affiliates
(PHI)
Disagree
PHI appreciates the change, however, the SDT has designated the Regional Entity to provide alternate time
periods for inspections. This should be the PC or RC. The TO should submit a request for alternate periods
to the designated entity.
Salt River Project
Disagree
R1.2 specifies that vegetation inspections are to be conducted at least once per calendar year, yet in R3 it
states that the Transmission Owner shall conduct Vegetation Inspections of all applicable lines in accordance
with the frequency specified in the transmission vegetation management program. Although SRP conducts
its transmission inspections on an annual basis, the Transmission Owner should be allowed to define the
inspection frequency based on the operations of their utility company as best defined in their individual TVMP.
Whichever definition is approved it should be stated the same in both R1.2 and in R3.
Platte River Power Authority
Vegetation Management Group
Disagree
R3 says, "each TO shall conduct Vegetation Inspections of all applicable lines in accordance with the
frequency specified in its transmission vegetation management program". However, R1.2. says that the TO
shall specify a Vegetation Inspection frequency of at least once per calendar year. The two requirements
seem to be inconsistent. We assume that R3 was worded to accommodate a more frequent Vegetation
Inspection but it isn’t clear.
Hydro-Quebec TransEnergie
(HQT)
Disagree
Refer to the response to Question 1.
Independent Electricity System
Disagree
Refer to the response to Question 1.
40
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
Operator
ISO New England Inc.
Disagree
Refer to the response to Question 1.
Northeast Power Coordinating
Council--RSC
Disagree
Refer to the response to Question 1.
JEA
Disagree
The requirement should simply be that the entity will conduct a Vegetation Inspection at least once per
calendar year (per the push for results/performance based requirements). The caveats for natural disasters
seem reasonable.
CenterPoint Energy
Disagree
The term “line miles” is not a defined NERC term. The industry terms “structure miles” and “circuit miles” are
more common. The NERC Transmission Availability Data System (TADS) utilizes a defined term of “circuit
miles” which would be a better choice to avoid confusion and provide the same capability for determining a
percent complete status. Transmission Owners are already required to report the number of “circuit miles” of
their (greater than or equal to) 200kV transmission line assets annually to TADS.
BC Transmission Corporation
Disagree
The TO's should be required to inspect each line at least once a year. This is critical to eliminating outages
and would provide a definite measure for the audit process. The phrase as measured in line miles adds
confusion to the requirement. It should state that the applicable lines be inspected along the entire length.
Orange and Rockland Utilities,
Inc.
Disagree
There is an inconsistency between R1.2 and R3. R1.2 requires the TO to carry out inspections at least once
per calendar year. R3 requires the TO to carry out inspections per the frequency defined in its vegetation
management program. It is preferred that the TO be allowed to specify the frequency and timing as stated in
R3. Once per calendar year is not sensitive to local and environmental factors. For example, facilities in the
Northeast are located in an environment where there is a long (7-8 month) dormant period -vegetation does
not grow. Specify a frequency of one inspection per dormant period. This inspection could take place
between September and April annually. In one dormant period we might inspect in November and inspect
again 14 months later in January. We would meet the inspection need per R3, but fail to have inspected in a
calendar year, thus violating R1.2. Other TO’s may be located in parts of the country with little or no
vegetation and not need a once per calendar year inspection. Thus, R1.2 should allow the TO to specify an
inspection program that is sensitive to local and environmental factors, not the calendar.
Arizona Public Service
Disagree
TO’s should be required to inspected annually. This needs to be in R3 which is stated above. This standard
should be consistent so each utility is audited the same.
41
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
FirstEnergy Corp
Disagree
We do not agree with the parenthetical phrase "(as measured in line miles)". Entities may utilize other forms
of measurement such as “corridor miles”. The standard should allow the TO to define its own measurement
technique and then the VSL for this requirement would be based on a percentage of how much of the TO’s
transmission system was missed per the measurement technique defined by the TO. We suggest removing
the parenthetical phrase "of all applicable lines (as measured in line miles)" from Req. R3. and add a new
subpart of Req. R1 requiring the TO, in its TVMP, to document its method of measuring the applicable lines to
be maintained. Corresponding changes to the VSLs are also needed per this proposed revision. The VLS
could be revised to read "... inspected greater than x% but less than y% of the Transmission Owner defined
measurement technique as defined in sub-part 1.x"
Northern Indiana Public Service
Company
Disagree
While I agree with the minimum interval of once a year for vegetation inspections, I have real concerns about
using line miles for determining violation severity levels. We conduct vegetation inspections by R.O.W.
corridor rather than by circuit or circuit line miles. Multiple circuits or segments of multiple circuits can exisit
within the same R.O.W. complicating any calculation of how many line miles are inspected versus not
inspected. How about using R.O.W. miles rather than circuit line miles for determining the V.S.L.?
Xcel Energy
Disagree
Xcel Energy does not disagree with the language of R3, however suggests that the referenced footnote 4 be
modified to include “species epidemics,” such as bark beetles. It is proposed that footnote 4 have the term
“species epidemics” inserted after “landslides” and before “wind shear.”
ISO/RTO Council
The SRC has no comment on this question.
42
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
4. As stated in the background information above, in response to industry comments, the Requirement for
preventing vegetation encroachments (the new R4) is revised. Additionally the SDT assigned Time Horizons,
Violation Risk Factors, and Violation Severity Levels. Do you agree? If not, please explain and propose an
alternative.
Organization
Yes or No
Entegra Power Group LLC
Question 4 Comment
No comment
American Electric Power
Agree
Arizona Public Service
Agree
Bonneville Power Administration
Agree
Central Maine Power an Energy
East Company
Agree
Georgia Transmission
Corporation
Agree
Hydro One Networks inc.
Agree
Lee County Electric Cooperative
Agree
National Grid
Agree
New Brunswick Power
Transmission
Agree
Northeast Utilities
Agree
Northern Indiana Public Service
Company
Agree
43
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Oncor Electric Delivery
Agree
ReliabilityFirst Corporation
Agree
Southern Company
Agree
Superintendent Transmission
Maintenance
Agree
Tampa Electric Company
Agree
Tenessee Valley Authority
Agree
Tennessee Valley Authority
Agree
Transmission Owner
Agree
TVA
Agree
TVA
Agree
TVA
Agree
WECC RC
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
FirstEnergy Corp
Agree
Question 4 Comment
Although we agree with this requirement, we want to point out a potential concern with double violations
between R4 and either R5, R6, R7, or R8. Technically if at any point in real-time you violate one of the
requirements R5 through R8, you have also violated R4. The SDT may want to consider adding a clarifying
statement in R4 to alleviate a double violation such as "This requirement is not applicable when either R5, R6,
R7, or R8 is violated".
44
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
ISO New England Inc.
Agree
Falling vegetation should be an exception to an encroachment but a clarification is needed to confirm that any
falling tree that gets lodged into another tree and violates the MVCD in real time is also included as part of the
falling vegetation exception. Also, if a line is operating beyond its Emergency Rating due to system
conditions, encroachments of the MVCD should not be considered a violation of R6. Request that additional
clarification be made between the relationship of R1.6 and R4. R1.6 is a documentation requirement that
requires that the TVMP specify strategies to ensure that the MVCD clearances are never violated under all
operating/rated conditions. R4 is an implementation requirement that makes it a violation to encroach upon
the MVCD in real time only. So if we had a situation where there would have been an MVCD encroachment if
the conductor was at its lowest position (maximum sag) but, at the time of the observation, the conductor was
at a higher position (not at maximum sag), our understanding is that there would be no violation of either R1.6
or R4 since the real time observation determined that the vegetation clearance was greater than the MVCD.
This assumes that the strategies required under R1.6 are included in the TVMP.Clarification is needed for
what is meant by “...as observed in real-time operating between no-load and their Rating.”
Orange and Rockland Utilities,
Inc.
Agree
ORU agrees that falling vegetation should be an exception to an encroachment but would like clarification to
confirm that any falling tree that gets lodged into another tree and violates the MVCD in real time is also
included as part of the falling vegetation exception. Also, if a line is operating beyond its Emergency Rating
due to system conditions, encroachments of the MVCD should not be considered a violation of R6. ORU is
requesting that additional clarification be made between the relationship of R1.6 and R4. R1.6 is a
documentation requirement that requires that the TVMP specify strategies to ensure that the MVCD
clearances are never violated under all operating/rated conditions. R4 is an implementation requirement that
makes it a violation to encroach upon the MVCD in real time only. So if we had a situation where there would
have been an MVCD encroachment if the conductor was at its lowest position (maximum sag) but, at the time
of the observation, the conductor was at a higher position (not at maximum sag), our understanding is that
there would be no violation of either R1.6 or R4 since the real time observation determined that the vegetation
position was greater than the MVCD. This assumes that the strategies required under R1.6 are included in
the TVMP.
PacifiCorp
Agree
PacifiCorp suggests inserting “by a qualified observer” after “observed.” Otherwise, utilities could be held
accountable to train all their workers who might casually encounter vegetation conditions in their work or
commutes.
Southern California Edison
Company
Agree
SCE generally agrees with the language of the requirement, but believes that the appropriate Violation Risk
Factor is "Lower," rather than “Medium.” SCE believes that an encroachment, in and of itself, does not
necessarily rise to a level of significance that should require self-reporting, nor should such an occurrence
necessarily subject the utility to an investigation with potential adverse findings and penalties. Considering the
45
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
purpose of the standard and the imprecise nature of vegetation management activities, the standard may be
overly strict. Further, due to the resistance of certain land owners and/or agency officials to allowing utilities
to prune beyond the prescribed minimum tree-to-line clearances, SCE asks the Drafting Team consider
changing the term “Minimum Vegetation Clearance Distances” to “Critical Vegetation Clearance Distances".
Xcel Energy
Disagree
(a) Xcel Energy incorporates its response to number 3 above regarding footnote 4, alternatively, footnote 5
could be modified in a similar fashion to include “species epidemics” between “logging” and “animal severing
tree.” (b) Xcel Energy suggests that the phrase “Minimum Vegetation Clearance Distances” (MVCD) be
changed to “Critical Clearance Distance.” The use of the word “minimum” creates problems for Transmission
Owners when dealing with land owners regarding the necessary vegetation management which is to take
place on the subject property. “Minimum” creates difficulties in explaining to a land owner why any additional
clearance need be obtained. That difficulty would be substantially lessened with the use of a term such as
“critical,” which more readily lends itself to an additional distance such that the vegetation never approaches
the critical distance.(c) Xcel Energy urges the insertion of “by a qualified observer” after “observed.”
Otherwise, a Transmission Owner could have a violation as a result of a drive-by glance by an office clerical
worker.
MRO NERC Standards Review
Subcommittee
Disagree
A. The MRO NSRS suggests that the phrase “Minimum Vegetation Clearance Distances” (MVCD) be
changed to “Critical Clearance Distance.” The use of the word “minimum” creates problems for Transmission
Owners when dealing with land owners regarding the necessary vegetation management which is to take
place on its easements. “Minimum” creates difficulties in explaining to a land owner why any additional
clearance needs to be obtained. That difficulty would be substantially lessened with the use of a term such as
“critical”, which more readily lends itself to an additional distance such that the vegetation never approaches
the critical distance.B. The MRO NSRS agrees with the intent of including events that would define
exceptions for requirements to comply with FAC-003. As an alternative to the approach in the draft Standard
of using footnotes, the MRO NSRS recommends that the SDT consider adding a generic “force majeure”
statement in the applicability section more specifically stating that companies will not be subject to compliance
requirements to the extent that events or circumstances beyond their control limit or prevent their abilities to
perform. Here’s an example:Compliance with this standard will not apply should there exist an occurrence,
non-occurrence, or other set of circumstances that are beyond the reasonable control of a Registered Entity
subject to this Reliability Standard, and are not caused by the fault or negligence of the Registered Entity,
including acts of God, strike, flood, drought, earthquake, storm, fire, hurricane, tornado, landslides, logging
activities, animals severing trees, lightning, epidemic, war, riot, civil disturbance, sabotage, vandalism,
terrorism, or action or inaction by any Governmental Authority or individual that restricts or prevents
performance to comply with this Reliability Standard.C. R4 states that “Each Transmission Owner shall
prevent encroachment of vegetation into the Minimum Vegetation Clearance Distances (MVCD) listed in FAC003-2 - Attachment 1........” The MRO NSRS requests the Standard clarify how MVCDs will be interpolated for
46
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
altitudes not specifically defined in Table 1.
Salt River Project
Disagree
Although the replacement of the Critical Clearance Zone (CCZ) in R4 is an improvement, we still question the
use of the Gallet Equation. Although the Gallet Equation is more definitive than using IEEE 516 as identified
in the current standard, we question from an engineering perspective as to how and why this method was
chosen for vegetation management. The Gallet Equation is a well known method of computing the required
strike distance for proper insulation coordination. It is our understanding that the purpose is for designing
towers, to define the “tower window” or opening inside of a tower under normal conditions. Because this is
not a method designed specifically for vegetation management, there is no basis for applying this to
vegetation management. It is recommended that testing be done to justify this method to be used for
vegetation management. We would find it definitive to substantiate the calculated equation assertions with
test data from actual energized flashover distances to vegetation. The testing ought to include dry and
misting conditions at 200+ kilovolt levels on a sampling of fresh cut common vegetation types. Reputable
EHV testing facilities where such tests can be performed exist within the United States and Canada.
Platte River Power Authority
Vegetation Management Group
Disagree
As the requirement is written it is a violation of the requirement when a possible encroachment of the MVCD
is discovered through inspections and such an encroachment should be self-reported to the RE. This is
inconsistent with the purpose of the standard to prevent vegetation-related outages that can result in
Cascading. We would suggest that appropriate action be taken to correct encroachment of the MVCD but that
it wouldn’t be a violation of the requirement until a Sustained Outage has occurred or the imminent treat
process has been implemented. R4 refers to observation in real-time. This actual field observation of the
MVCD between no-load and its Rating is too subjective and lends itself to too much interpretation by the
inspector especially in light of the fact that it could be a self-reported violation if the MVCD is encroached.
Associated Electric Cooperative,
Inc.
Disagree
Associated Electric Cooperative Inc. suggests the third exception bullet under R4 is unclear. Is the exception
meant to address vegetation from either inside or outside the ROW that: 1) may pass through the MVCD
while falling; or, 2) has fallen and may now encroach into the MVCD from its new steady state position?
American Transmission
Company
Disagree
ATC agrees with the intent of including events that would define exceptions for requirements to comply with
FAC-003. As an alternative to the approach in the draft Standard of using footnotes, ATC recommends that
the SDT consider adding a generic force majeure statement in the applicability section more specifically
stating that companies will not be subject to compliance requirements to the extent that events or
circumstances beyond their control limit or prevent their abilities to perform. Here’s an example:Compliance
with this standard will not apply should there exist an occurrence, non-occurrence, or other set of
circumstances that are beyond the reasonable control of a Registered Entity subject to this Reliability
Standard, and are not caused by the fault or negligence of the Registered Entity, including acts of God, strike,
flood, drought, earthquake, storm, fire, hurricane, tornado, landslides, logging activities, animals severing
47
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
trees, lightning, epidemic, war, riot, civil disturbance, sabotage, vandalism, terrorism, or action or inaction by
any Governmental Authority or individual that restricts or prevents performance to comply with this Reliability
Standard.Also, R 4 states that “Each Transmission Owner shall prevent encroachment of vegetation into the
Minimum Vegetation Clearance Distances (MVCD) listed in FAC-003-2 - Attachment 1........”ATC requests the
Standard clarify how MVCDs will be interpolated for altitudes not specifically defined in Table 1.
Consolidated Edison Company of
New York Inc.
Disagree
CECONY agrees that falling vegetation should be an exception to an encroachment but would like
clarification to confirm that any falling tree that gets lodged into a stable tree and pushes the stable tree
beyond the MVCD in real time is also included as part of the falling vegetation exception. CECONY is
requesting that additional clarification be made between the relationship of R1.6 and R4. R1.6 is a
documentation requirement that requires that the TVMP specify strategies to ensure that the MVCD
clearances are never violated under all operating/rated conditions. R4 is an implementation requirement that
makes it a violation to encroach upon the MVCD in real time only. So if we had a situation where there would
have been an MVCD encroachment if the conductor was at its lowest position (maximum sag) but, at the time
of the observation, the conductor was at a higher position (not at maximum sag), our understanding is that
there would be no violation of either R1.6 or R4 since the real time observation determined that the vegetation
position was greater than the MVCD. This assumes that the strategies required under R1.6 are included in
the TVMP.
Idaho Power Company
Disagree
Change the Minimum Vegetation Clearance Distance (MVCD) to Critical Vegetation Clearance Distance
(CVCD) to indicate a higher level of importance when dealing with federal agencies and reluctant property
owners. Provide a better definition for the term ‘Real Time’. Include in this definition the use of technology to
determine if an imminent threat exists to help minimize real time patrols. In footnote 5 provide more
information on what agricultural activities includes.
Vegetation Management Team
Disagree
Disagree with R4 and M4. As explained in the comment for R1, encroachments should also be addressed via
a pre-determined process before becoming a violation of the standard. Therefore, we suggest the following
changes be made to the requirements: R4: Each Transmission Owner shall [REMOVE: prevent
encroachment of vegetation into the] implement its vegetation encroachment response process or procedure
when the Transmission Owner has actual knowledge of such an encroachment on any Minimum Vegetation
Clearance Distances (MVCD) listed in FAC-003-2-Attachment 1 [REMOVE: for its applicable lines as
observed in real-time operating between no-load and their Rating.], obtained through implementation of the
annual work plan and the TVMP. M4: The Transmission Owner has evidence [REMOVE: from inspections
that indicate there was no vegetation encroachment into the Minimum Vegetation Clearance Distances listed
in FAC-003-2-Attachment 1 for its applicable lines as observed in real-time operating between no-load and
their Rating, considering exceptions.] of the implementation of its vegetation encroachment process or
procedure showing actions taken and dates of performance.Likewise, we suggest the following be made to
48
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
the Violation Severity Levels chart: Severe: [REMOVE: The Transmission Owner has failed to prevent
vegetation from encroaching into the minimum vegetation clearance distance.] The Transmission Owner did
not implement its vegetation encroachment response process or procedure when the Transmission Owner
had actual knowledge of such an encroachment on any Minimum Vegetation Clearance Distances (MVCD)
listed in FAC-003-2-Attachment 1 obtained through normal operating practices.
Hydro-Quebec TransEnergie
(HQT)
Disagree
Falling vegetation should be an exception to an encroachment but a clarification is needed to confirm that any
falling tree that gets lodged into another tree and violates the MVCD in real time is also included as part of the
falling vegetation exception. Also, if a line is operating beyond its Emergency Rating due to system
conditions, encroachments of the MVCD should not be considered a violation of R6. Request that additional
clarification be made between the relationship of R1.6 and R4. R1.6 is a documentation requirement that
requires that the TVMP specify strategies to ensure that the MVCD clearances are never violated under all
operating/rated conditions. R4 is an implementation requirement that makes it a violation to encroach upon
the MVCD in real time only. So if we had a situation where there would have been an MVCD encroachment if
the conductor was at its lowest position (maximum sag) but, at the time of the observation, the conductor was
at a higher position (not at maximum sag), our understanding is that there would be no violation of either R1.6
or R4 since the real time observation determined that the vegetation clearance was greater than the MVCD.
This assumes that the strategies required under R1.6 are included in the TVMP.Clarification is needed for
what is meant by “...as observed in real-time operating between no-load and their Rating.”
Independent Electricity System
Operator
Disagree
Falling vegetation should be an exception to an encroachment but a clarification is needed to confirm that any
falling tree that gets lodged into another tree and violates the MVCD in real time is also included as part of the
falling vegetation exception. Also, if a line is operating beyond its Emergency Rating due to system
conditions, encroachments of the MVCD should not be considered a violation of R6. Request that additional
clarification be made between the relationship of R1.6 and R4. R1.6 is a documentation requirement that
requires that the TVMP specify strategies to ensure that the MVCD clearances are never violated under all
operating/rated conditions. R4 is an implementation requirement that makes it a violation to encroach upon
the MVCD in real time only. So if we had a situation where there would have been an MVCD encroachment if
the conductor was at its lowest position (maximum sag) but, at the time of the observation, the conductor was
at a higher position (not at maximum sag), our understanding is that there would be no violation of either R1.6
or R4 since the real time observation determined that the vegetation clearance was greater than the MVCD.
This assumes that the strategies required under R1.6 are included in the TVMP.Clarification is needed for
what is meant by “...as observed in real-time operating between no-load and their Rating.”
Northeast Power Coordinating
Council--RSC
Disagree
Falling vegetation should be an exception to an encroachment but a clarification is needed to confirm that any
falling tree that gets lodged into another tree and violates the MVCD in real time is also included as part of the
falling vegetation exception. Also, if a line is operating beyond its Emergency Rating due to system
49
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
conditions, encroachments of the MVCD should not be considered a violation of R6. Request that additional
clarification be made between the relationship of R1.6 and R4. R1.6 is a documentation requirement that
requires that the TVMP specify strategies to ensure that the MVCD clearances are never violated under all
operating/rated conditions. R4 is an implementation requirement that makes it a violation to encroach upon
the MVCD in real time only. So if we had a situation where there would have been an MVCD encroachment if
the conductor was at its lowest position (maximum sag) but, at the time of the observation, the conductor was
at a higher position (not at maximum sag), our understanding is that there would be no violation of either R1.6
or R4 since the real time observation determined that the vegetation clearance was greater than the MVCD.
This assumes that the strategies required under R1.6 are included in the TVMP.Clarification is needed for
what is meant by “...as observed in real-time operating between no-load and their Rating.”
JEA
Disagree
I object to the zero defect concept. I realize that there is pressure from FERC, however Section 215 of the
FPA specifically states "The Commission shall give due weight to the technical expertise of the Electric
Reliability Organization with respect to the content of a proposed standard or modification to a reliability
standard..." The technical feasibility of 0 defects is questionable. The industry should develop an aggressive
but acheivable performance level for preventing encroachments etc.
CenterPoint Energy
Disagree
It is not clear how R4’s last bullet, “Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting
from falling vegetation” is observable as an exception, and the Technical Reference does not clarify it either.
It would appear that if a tree branch (e.g. wind-blown or fallen branch debris) was observed hanging on the
conductor, but was not causing an outage, that it would be considered an exception. The bullet item should
be clarified or deleted.
US Bureau of Reclamation
Disagree
It is not clear why wind blown debris is not listed as an exception. It is also not clear why these exemptions
are needed as they are not vegeetation encroachments.
North Carolina Electric
Membership Corporation
Disagree
NCEMC has concerns about the enforcement of the requirement.There seems to be an issue with
enforcement of the third exemption if any vegetation falls and lodges to create a MVCD violation from inside
or outside the ROW.
Pacific Gas and Electric Co.
Disagree
PG&E agrees in principal with R5 but disagrees with the exception for human activity noted in footnote (5),
specifically aboriculture, horticulture or agricultural activities. This exception is overly broad and could be
interpreted as exempting certian activities (such as planting orchards, xmas tree farms, community tree
plantings, etc.) from the standard and will invite legal challenges to the TO’s right to perform vegetation
management. PG&E proposes alternative language to the exception as follows: Examples include, but are
not limited to, logging, animal severing tree, vehicle contact with tree, digging or removal of tree or new
50
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
plantings between inspection cycles where the TO does not have actual knowledge. As an alternative, add a
generic force majeure statement as described in Q18 #2.
Public Service Co. of New
Mexico
Disagree
PNM is not in favor of the current MVCD table 1. This will not provide clarity to the field personnel as to
clearance distances. It could cause increasing confusion as to how much clearance needs to be obtained at
the time of work. Clearance 1 and 2 were much clearer in that respect.
SCE&G
Disagree
SCE&G has concerns about the enforcement of the requirement. There seems to be an issue with
enforcement of the third exemption if any vegetation falls and lodges to create a MVCD violation from inside
or outside the ROW.
Duke Energy
Disagree
Since this standard already includes other requirements to implement a transmission vegetation management
program to maintain the defined clearances, as well as an imminent threat process or procedure to avoid
sustained outages, we believe that Requirement R4 provides no additional reliability benefit and should be
deleted. If it is decided that this requirement must be retained, then it needs to be re-written such that it is a
performance-based requirement with graduated VSLs. As currently written, this requirement is a binary
requirement which carries a single VSL which can only be “Severe”. Such a zero-tolerance approach to
preventing encroachments does not provide industry with a reasonable opportunity for success, absent the
establishment of overly-aggressive and costly vegetation management programs that carry minimal additional
reliability benefit. A performance-based requirement should be developed relative to some metric such as
line-mile exposure that will promote high quality vegetation management, optimization of the reliability
cost/benefit relationship and deliver the overall end result of improved reliability to the system. The
performance-based requirement should be structured for a graduated VSL. Due to this requirement being
focused on preventing encroachments rather than sustained outages, we believe that a zero tolerance
approach is not warranted to improve reliability.In addition, the third exemption is not clear as it relates to
falling vegetation. For example, how would an event be viewed if a tree lodges into another tree or hits
another tree causing it to lean such that it is within the MVCD?
Pepco Holdings, Inc - Affiliates
(PHI)
Disagree
The definition of Rating includes the word -limits- implying that Rating is a plural term. Does the SDT mean
the highest sustained limit (10 minutes? 30 minutes? 24 hours?...)?
Manitoba Hydro
Disagree
The phrase “Minimum Vegetation Clearance Distances” (MVCD) should be changed to “Critical Clearance
Distance.” The use of the word “minimum” creates problems for Transmission Owners when dealing with
land owners regarding the necessary vegetation management which is to take place on the subject property.
“Minimum” creates difficulties in explaining to a land owner why any additional clearance need be obtained.
That difficulty would be substantially lessened with the use of a term such as “critical,” which more readily
51
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
lends itself to an additional distance such that the vegetation never approaches the critical distance.Insert “by
a qualified observer” after “observed.” Otherwise, a Transmission Owner could have a violation as a result of
a drive-by glance by an office clerical worker.
E.ON U.S.
Disagree
The standard does not specify what is meant by “off/on ROW”.E.ON U.S. questions how NERC plans on
enforcing the third bullet
BC Transmission Corporation
Disagree
The standard should limit itself to the prevention of outages. If vegetation encroaches within the MVCD and
the TO effectively implements the imminent threat process to prevent an outage this should not be a violation.
Additionally this requirement will be very difficult to audit and enforce.
Puget Sound Energy
Disagree
The term, Minimum Vegetation Clearance Distance (MVCD) does not invoke the critical dangerous nature of
the close distance to the conductor. A more impactful term such as “critical” would be more appropriate.
Ameren
Disagree
The third bullet point on "falling vegetation" is unclear. Would like to see this clarify whether on ROW and/or
off ROW falling trees.
SERC Vegetation Managment
Sub-committee (VMS)
Disagree
The VMS has concerns about the enforcement of the requirement.There seems to be an issue with
enforcement of the third exemption if any vegetation falls and lodges to create a MVCD violation from inside
or outside the ROW.
Progress Energy Carolinas, Inc.
Disagree
There is an issue with the wording of the third exemption when any vegetation from outside the ROW falls
and lodges to create a MVCD violation. The wording as proposed could be interpreted as non-compliance
due to vegetation from outside of the ROW.
Entergy Services, Inc
Disagree
There may be an issue of the third exemption if vegetation falls and lodges to create a MVCD violation from
inside or outside the Right of Way.
Tucson Electric Power Company
Disagree
We feel that the use of the word “Minimum” in Minimum Vegetation Clearance Distance should be “Critical”.
Governing/Managing land agencies could use the word Minimum, as an allowable limit argument against the
utility and deny needed permissions work as long as there is more than the minimum clearance in on the line.
The use of the word critical would indicate the need for additional buffer distance to prevent vegetation
caused outages. Additionally is the exception to the rule about falling vegetation from inside or outside the
ROW/Easement?
52
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Nebraska Public Power District
ISO/RTO Council
Yes or No
Disagree
Question 4 Comment
Xcel Energy urges the insertion of “by a qualified observer” after “observed.” Otherwise, a Transmission
Owner could have a violation as a result of a drive-by glance by an office clerical worker.
The SRC has no comment on this question.
53
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
5. As stated in the background information above, in response to industry comments, the Requirement for
preventing Sustained Outages due to grow-ins on IROL or Major WECC Transfer Paths (the new R5) is
developed. Additionally the SDT assigned Time Horizons, Violation Risk Factors, and Violation Severity Levels.
Do you agree? If not, please explain and propose an alternative.
Organization
Yes or No
Entegra Power Group LLC
Question 5 Comment
No comment
Ameren
Agree
American Electric Power
Agree
Arizona Public Service
Agree
Associated Electric Cooperative,
Inc.
Agree
Bonneville Power Administration
Agree
CenterPoint Energy
Agree
Central Maine Power an Energy
East Company
Agree
Consolidated Edison Company of
New York Inc.
Agree
Duke Energy
Agree
E.ON U.S.
Agree
Entergy Services, Inc
Agree
Georgia Transmission
Corporation
Agree
54
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Hydro One Networks inc.
Agree
Idaho Power Company
Agree
Lee County Electric Cooperative
Agree
National Grid
Agree
Nebraska Public Power District
Agree
NERC Standards Review
Subcommittee
Agree
New Brunswick Power
Transmission
Agree
North Carolina Electric
Membership Corporation
Agree
Northeast Utilities
Agree
Northern Indiana Public Service
Company
Agree
Oncor Electric Delivery
Agree
PacifiCorp
Agree
Platte River Power Authority
Vegetation Management Group
Agree
Progress Energy Carolinas, Inc.
Agree
Public Service Co. of New
Agree
Question 5 Comment
55
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
Mexico
ReliabilityFirst Corporation
Agree
Salt River Project
Agree
SCE&G
Agree
SERC Vegetation Managment
Sub-committee (VMS)
Agree
Southern Company
Agree
Superintendent Transmission
Maintenance
Agree
Tenessee Valley Authority
Agree
Tennessee Valley Authority
Agree
Transmission Owner
Agree
TVA
Agree
TVA
Agree
TVA
Agree
Vegetation Management Team
Agree
WECC RC
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
56
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
Orange and Rockland Utilities,
Inc.
Agree
ORU agrees that, if a line is operating beyond its Emergency Rating due to system conditions,
encroachments of the MVCD should not be considered a violation of R5.
Southern California Edison
Company
Agree
SCE generally agrees with the assigned Violation Risk Factor for lines that are an element of an IROL or a
WECC transfer path. SCE believes that the bulleted exceptions listed in the new R5 are appropriate.
Tampa Electric Company
Agree
The white paper, on page 33, paragraph 4, defines a sustained outage as vegetation related event, if it occurs
within the specified rating of the facility. If the conductor is operating above its rating it states that this “would
not be classified as a vegetation related sustained outage under the standard.” If this is so it needs to be
stated and/or clarified in the standard itself.
American Transmission
Company
Disagree
ATC recommends that the SDT consider the statements in the Technical Paper on pgs. 32-34; i.e.
encroachment taking place while a line is operating beyond its rating is not a violation of this Requirement.
FirstEnergy Corp
Disagree
FE suggests a revision of Requirement R5.FE encourages the team to re-evaluate its approach to
requirements R5 through R7 and consider changes that would remove the binary aspect of the requirements
and permit a graded approach to the VSL structure for a non-compliance of the requirement. Our proposal is
to incorporate aspects of R7 (blow in) and R8 (fall in) into both requirements R5 (grow-in IROL) and R6 (growin Non-IROL) so that R5 and R6 establish requirements for grow-in, blow-in and fall-in. The proposed
requirement for R5 would read: "Each Transmission Owner shall prevent Sustained Outages of applicable
lines that are identified as an element of an Interconnection Reliability Operating Limit (IROL) (or Major
WECC Transfer Path) due to vegetation growing into a conductor operating between no-load and its Rating,
due to the blowing together of a conductor and vegetation rooted within an ActiveTransmission Line Right of
Way (operating within design blow-out conditions), or due to vegetation falling into a conductor with the
following exceptions:"Similarly, the proposed R6 would read:"Each Transmission Owner shall prevent
Sustained Outages of applicable lines that are not an element of an IROL (or major WECC Transfer Path)
due to vegetation growing into a conductor operating between no-load and its Rating, due to the blowing
together of a conductor and vegetation rooted within an Active Transmission Line Right of Way (operating
within design blow-out conditions), or due to vegetation falling into a conductor with the following
exceptions:"These requirement changes provide the flexibility needed to establish graded VSLs. FE’s
proposed VSL levels are consistent with the reporting categories established in section D 1.5. The root of the
requirement is "shall prevent Sustained Outages" and the VSL gauge of how much a VM program missed the
mark would then be reflected in the type of vegetation contact. Therefore, we propose VSL levels for both
Req. R5 and R6 as follows: grow-in (SEVERE VSL), a fall-in (MODERATE VSL),a blow-in (LOWER VSL).No
changes to the Violation Risk Factors or Time Horizons for requirements R5 or R6 are proposed.If the
proposal is accepted, conforming changes to the Measures are required.
57
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
WECC
Disagree
I agree with the requiring the prevention of sustained outages due to grow-ins on an identified subsed of all
transmission facilities. However, I am concerned over the use of the capitalized term Major WECC Transfer
Paths. Because this is not a defined term in the NERC Glossary and is not the complete name of any WECC
listing,I suggest the phrase (or Major WECC Transfer Paths)be changed to (or major transfer paths in the
Western Interconnection as identified by WECC). In the alternative, the full name of the dcoument known as
Table 2 that is referred to in the second draft is "Major WECC Transfer Paths in the Bulk Electric System". Is
there going to be a problem with the capitalized term if a definition is not developed, knowing that the
capitalized term refers to an existing document?
Tucson Electric Power Company
Disagree
In the footnote examples of human activities, there is an exemption for agricultural activities. The planting of
and maintenance of orchards is an agricultural activity that should specifically address as not applying in this
exemption.
US Bureau of Reclamation
Disagree
It is not clear what Natural disasters or human activity have to do with growing vegetation. Also it is not clear
why falling vegetation or wind blown debris are not listed as exemptions.
Pacific Gas and Electric Co.
Disagree
PG&E agrees in principal with R5 but disagrees with the exception for human activity noted in footnote (5),
specifically aboriculture, horticulture or agricultural activities. This exception is overly broad and could be
interpreted as exempting certian activities (such as planting orchards) from the standard and will invite legal
challenges to the TO’s right to perform vegetation management. PG&E proposes alternative language to the
exception as follows: Examples include, but are not limited to, logging, animal severing tree, vehicle contact
with tree, digging or removal of tree or new plantings between inspection cycles where the TO does not have
actual knowledge. As an alternative, add a generic force majeure statement as described in Q18 #2.
Xcel Energy
Disagree
Please see our comments above concerning footnotes 4 & 5.
JEA
Disagree
Please see the comment to question 4.
Pepco Holdings, Inc - Affiliates
(PHI)
Disagree
R5 also uses the term Rating. See comment to Q4.
Puget Sound Energy
Disagree
Regional differences should be addressed through regional standards. The reference to Major WECC
Transfer Paths should be removed and allow the region to determine whether to expand the implication of the
standard.
58
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
Hydro-Quebec TransEnergie
(HQT)
Disagree
The introduction of IROL introduces an unnecessary level of complexity in the standard. The facilities being
addressed in the standard impact the Bulk Electric System, and the additional “drilling down” is not needed.
R5 and R6 seems to have been introduced just to have different violation risk factor for different types of lines.
Delete R5 or R6 after removing the IROL concept.
Independent Electricity System
Operator
Disagree
The introduction of IROL introduces an unnecessary level of complexity in the standard. The facilities being
addressed in the standard impact the Bulk Electric System, and the additional “drilling down” is not needed.
ISO New England Inc.
Disagree
The introduction of IROL introduces an unnecessary level of complexity in the standard. The facilities being
addressed in the standard impact the Bulk Electric System, and the additional “drilling down” is not needed.
Northeast Power Coordinating
Council--RSC
Disagree
The introduction of IROL introduces an unnecessary level of complexity in the standard. The facilities being
addressed in the standard impact the Bulk Electric System, and the additional “drilling down” is not needed.
BC Transmission Corporation
Disagree
The IROL is not properly defined in this standard it is hard to agree with this requirement if we do not know
exactly what this means. Please put foot note #7 back into the document. Why single out WECC and not
other reliability councils.
Manitoba Hydro
Disagree
The SDT should consider the statements in the Technical Paper on pgs. 32-34 that encroachment taking
place if a line is operating beyond its rating would not be a violation of the Requirement.
ISO/RTO Council
The SRC has no comment on this question.
59
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
6. As stated in the background information above, in response to industry comments, the Requirement for
preventing Sustained Outages due to grow-ins on non-IROL or Major WECC Transfer Paths (the new R6) is
developed. Additionally the SDT assigned Time Horizons, Violation Risk Factors, and Violation Severity Levels.
Do you agree? If not, please explain and propose an alternative.
Organization
Yes or No
Entegra Power Group LLC
Question 6 Comment
No comment
Ameren
Agree
American Electric Power
Agree
Arizona Public Service
Agree
Associated Electric Cooperative,
Inc.
Agree
BC Transmission Corporation
Agree
Bonneville Power Administration
Agree
CenterPoint Energy
Agree
Central Maine Power an Energy
East Company
Agree
Consolidated Edison Company of
New York Inc.
Agree
E.ON U.S.
Agree
Entergy Services, Inc
Agree
60
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Georgia Transmission
Corporation
Agree
Hydro One Networks inc.
Agree
Idaho Power Company
Agree
Lee County Electric Cooperative
Agree
National Grid
Agree
Nebraska Public Power District
Agree
NERC Standards Review
Subcommittee
Agree
New Brunswick Power
Transmission
Agree
North Carolina Electric
Membership Corporation
Agree
Northeast Utilities
Agree
Northern Indiana Public Service
Company
Agree
Oncor Electric Delivery
Agree
Orange and Rockland Utilities,
Inc.
Agree
PacifiCorp
Agree
Question 6 Comment
61
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Pepco Holdings, Inc - Affiliates
(PHI)
Agree
Platte River Power Authority
Vegetation Management Group
Agree
Progress Energy Carolinas, Inc.
Agree
Public Service Co. of New
Mexico
Agree
Puget Sound Energy
Agree
Salt River Project
Agree
SCE&G
Agree
SERC Vegetation Managment
Sub-committee (VMS)
Agree
Southern Company
Agree
Superintendent Transmission
Maintenance
Agree
Tenessee Valley Authority
Agree
Tennessee Valley Authority
Agree
Transmission Owner
Agree
Tucson Electric Power Company
Agree
TVA
Agree
Question 6 Comment
62
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
TVA
Agree
TVA
Agree
Vegetation Management Team
Agree
WECC RC
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
ReliabilityFirst Corporation
Agree
Do we need R5 and R6? The requirements are same whether the line is an IROL or not.
ISO New England Inc.
Agree
Refer to the response to Question 5.
Tampa Electric Company
Agree
Same response as question 5.
Southern California Edison
Company
Agree
SCE generally agrees with the assigned Violation Risk Factor for lines that are not an element of an IROL or
a WECC transfer path. SCE believes that the bulleted exceptions listed in the new R6 are appropriate.
American Transmission
Company
Disagree
ATC recommends that the SDT consider the statements in the Technical Paper on pgs. 32-34; i.e.
encroachment taking place while a line is operating beyond its rating is not a violation of this Requirement.
FirstEnergy Corp
Disagree
FE suggests a revision of R6. See our response to Question 5 for further information.
US Bureau of Reclamation
Disagree
It is not clear what Natural disasters or wind blown debris have to do with growing vegetation. Also it is not
clear why human or animal activity or falling vegetation are not listed as exceptions.
Pacific Gas and Electric Co.
Disagree
PG&E agrees in principal with R5 but disagrees with the exception for human activity noted in footnote (5),
specifically aboriculture, horticulture or agricultural activities. This exception is overly broad and could be
interpreted as exempting certian activities (such as planting orchards) from the standard and will invite legal
challenges to the TO’s right to perform vegetation management. PG&E proposes alternative language to the
exception as follows: Examples include, but are not limited to, logging, animal severing tree, vehicle contact
with tree, digging or removal of tree or new plantings between inspection cycles where the TO does not have
63
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
actual knowledge. As an alternative, add a generic force majeure statement as described in Q18 #2.
Xcel Energy
Disagree
Please see our comments above concerning footnotes 4 & 5.
JEA
Disagree
Please see the comment to question 4.
Independent Electricity System
Operator
Disagree
Refer to the response to Question 5.
Northeast Power Coordinating
Council--RSC
Disagree
Refer to the response to Question 5.
WECC
Disagree
same comment as for question 5. Agree with the concept, but concern over the term major WECC Transfer
Paths (note that the word major is not capitalized in R6 but it is in R5. Suggest replaceing with the phrase (or
major transfer paths in the Western Interconnection as identified by WECC)
Hydro-Quebec TransEnergie
(HQT)
Disagree
See answer to Q5.
Manitoba Hydro
Disagree
The SDT should consider the statements in the Technical Paper on pgs. 32-34 that encroachment taking
place if a line is operating beyond its rating would not be a violation of the Requirement.
Duke Energy
Disagree
This requirement needs to be re-written such that it is a performance-based requirement with graduated
VSLs. As currently written, this requirement is a binary requirement which carries a single VSL which can
only be “Severe”. This may drive overly-aggressive and costly vegetation management programs that carry
minimal additional reliability benefit. A performance-based requirement should be developed relative to some
metric such as line-mile exposure that will promote high quality vegetation management, optimization of the
reliability cost/benefit relationship and deliver the overall end result of improved reliability to the system. The
performance-based requirement may still be zero tolerance, but should be structured for a graduated VSL.
ISO/RTO Council
The SRC has no comment on this question.
64
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
7. As stated in the background information above, in response to industry comments, the Requirement for
preventing Sustained Outages due to blowing together of vegetation and transmission line conductors (the
new R7) is developed. Additionally the SDT assigned Time Horizons, Violation Risk Factors, and Violation
Severity Levels. Do you agree? If not, please explain and propose an alternative.
Organization
Yes or No
Entegra Power Group LLC
Question 7 Comment
No comment
Ameren
Agree
American Electric Power
Agree
BC Transmission Corporation
Agree
Bonneville Power Administration
Agree
Consolidated Edison Company of
New York Inc.
Agree
Georgia Transmission
Corporation
Agree
Hydro One Networks inc.
Agree
Hydro-Quebec TransEnergie
(HQT)
Agree
Idaho Power Company
Agree
Independent Electricity System
Operator
Agree
ISO New England Inc.
Agree
65
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Lee County Electric Cooperative
Agree
Manitoba Hydro
Agree
National Grid
Agree
Nebraska Public Power District
Agree
NERC Standards Review
Subcommittee
Agree
New Brunswick Power
Transmission
Agree
Northeast Power Coordinating
Council--RSC
Agree
Northeast Utilities
Agree
Oncor Electric Delivery
Agree
Orange and Rockland Utilities,
Inc.
Agree
Pacific Gas and Electric Co.
Agree
PacifiCorp
Agree
Pepco Holdings, Inc - Affiliates
(PHI)
Agree
Platte River Power Authority
Vegetation Management Group
Agree
Question 7 Comment
66
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Public Service Co. of New
Mexico
Agree
Puget Sound Energy
Agree
ReliabilityFirst Corporation
Agree
Salt River Project
Agree
Southern Company
Agree
Superintendent Transmission
Maintenance
Agree
Tenessee Valley Authority
Agree
Tennessee Valley Authority
Agree
Tucson Electric Power Company
Agree
TVA
Agree
TVA
Agree
TVA
Agree
WECC RC
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Vegetation Management Team
Agree
Question 7 Comment
Concerned about the term “design blow-out conditions”. Some natural disasters (hurricanes, wind shear, fresh
gale, etc.) may have a lower threshold than “design blow-out.
67
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
Northern Indiana Public Service
Company
Agree
Have concerns about T.O.'s determining what is "active" and "inactive" R.O.W. which are explained in
Question 1 comments.
Southern California Edison
Company
Agree
SCE generally agrees with the content of the new R7, but believes it could be combined with the new R8 into
a single requirement (a revised new R7). It appears to SCE that both bulleted exceptions listed in the new R8
can also be applied to the new R7. Please see SCE's response to Question 8 below.
E.ON U.S.
Disagree
: E.ON U.S. requests that the SDT add language specifically excluding vegetation outside of an active ROW
that could potentially blow into the conductor
North Carolina Electric
Membership Corporation
Disagree
An issue exists, as currently worded, in that it does not exclude vegetation entirely off the ROW, under normal
weather conditions, that could be blown into the conductor.
SCE&G
Disagree
An issue exists, as currently worded, in that it does not exclude vegetation entirely off the ROW, under normal
weather conditions, that could be blown into the conductor.
SERC Vegetation Managment
Sub-committee (VMS)
Disagree
An issue exists, as currently worded, in that it does not exclude vegetation entirely off the ROW, under normal
weather conditions, that could be blown into the conductor.
Entergy Services, Inc
Disagree
As currently written, the Standard does not exclude vegetation entirely off the Right of Way, under normal
weather conditions, that could be blown into the conductor.
Associated Electric Cooperative,
Inc.
Disagree
Associated Electric Cooperative Inc agrees with the intent of R7. Perhaps the clarity could be improved by
rewording, such as: “Each Transmission Owner shall prevent Sustained Outages6 of applicable lines due to
the blowing together of a conductor and vegetation from within an Active Transmission Line Right of Way
(operating within design blow-out conditions) with the following exception: [Violation Risk Factor Medium][Time Horizon - Real Time]o Sustained Outages of applicable lines that result from natural disasters4
or wind-blown debris.
American Transmission
Company
Disagree
ATC requests the SDT to clarify “wind-blown debris”. ATC believes the definition should include branches
and/or trunks partially severed from the tree.
FirstEnergy Corp
Disagree
FE suggests a removal of R7. See our response to Question 5 for further information.
Tampa Electric Company
Disagree
In the white paper, page 35, paragraph 2, it states that if the conductor is operating above its rating it” would
68
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
not be classified as vegetation related sustained outage under the standard.” If this is so it needs to be stated
and/or clarified in the standard itself. In addition, on page 35, 3rd paragraph, last sentence of the white paper
it states,” Additionally, sustained outages due to wind-blown debris, such as large limbs and branches,
separated tree tops, etc., are exempt from this standard.” Again if this is so it needs to be stated in the
standard. Question for clarification: If the debris that falls is from a tree within the active transmission line
ROW is it a violation?
US Bureau of Reclamation
Disagree
It is not clear why Natural disasters or wind blown debris have to do with vegetation blowing together with
transmission lines. Also it is not clear why human or animal activity or falling vegetation are not listed as
exemptions.
Central Maine Power an Energy
East Company
Disagree
Note that R7 applies only to trees growing within the active right of way. Suggest that the standard clearly
explain this concept.
Progress Energy Carolinas, Inc.
Disagree
Off ROW vegetation blowing into conductors is nothing more than off ROW vegetation “falling into the line”
without permanent deformation of the vegetation (i.e., breaking/uprooting). Since the original design of the
line did not require the off ROW vegetation to be removed, off ROW vegetation should not be included in the
requirement.R8 as it is currently worded, “Each Transmission Owner shall prevent Sustained Outages of
applicable lines due to the blowing together of vegetation and a conductor within an Active Transmission Line
Right of Way (operating within design blow-out conditions) with the following exception:” should be reworded
as follows... “...due to the blowing together of a conductor and vegetation rooted within the Active
Transmission Line Right of Way...)
Xcel Energy
Disagree
Please see our comments above concerning footnotes 4 & 5.
JEA
Disagree
Please see the comment to question 4.
CenterPoint Energy
Disagree
R7 refers to “Active Transmission Line Right of Way” which is not defined as to its limits within the Standard.
The SDT has indicated in its response to 1st Draft Comments from CenterPoint Energy that the
“...Transmission Owner is responsible for defining the Active Transmission Line Right of Way.” However, that
defining clause is not included in the current definition. CenterPoint Energy recommends deleting the
phrase, “within an Active Transmission Line Right of Way”, deleting the phrase, “operating within design blowout conditions”, and revising R7 to read, “Each Transmission Owner shall prevent Sustained Outages of
applicable lines due to the blowing together of vegetation and a conductor operating within its designed sway
under rated conditions with the following exceptions...”. The terms used in R1 of “sag” and “sway” should be
used consistently. R1.6 already requires that maintenance strategies ensure that the MVCD is never violated
69
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
and “consider the sag and sway of the conductor throughout is operating range and under rated conditions”.
This requirement by itself defines the airspace that must be maintained to prevent a Sustained Outage. R7
requires no specific definition of a right of way because R1 already defines the necessary minimum clearance
to be maintained at all times.
Transmission Owner
Disagree
This requirement is not congruent with the purpose of this standard. The standard was enacted as a result of
the North East Blackout and a history of grid blackouts in which the growth of trees below conductors under
load contributed to the situation. Trees blowing into the conductor create no more risk to cascading than
causes such as lightning or foreign interference. This requirement should be removed from the standard.
Arizona Public Service
Disagree
This requirement is too vague and needs more clarity. Vegetation in the easement width or permitted ROW
shall not blow into the conductors resulting in an outage. If a utility has rights to maintain vegetation there
shouldn’t be any outages due to vegetation from blowing into the conductors. There active ROW should be
wide enough to prevent these types of outages.
Duke Energy
Disagree
This requirement needs to be re-written such that it is a performance-based requirement with graduated
VSLs. As currently written, this requirement is a binary requirement which carries a single VSL which can
only be “Severe”. This may drive overly-aggressive and costly vegetation management programs that carry
minimal additional reliability benefit. A performance-based requirement should be developed relative to some
metric such as line-mile exposure that will promote high quality vegetation management, optimization of the
reliability cost/benefit relationship and deliver the overall end result of improved reliability to the system. The
performance-based requirement may still be zero tolerance, but should be structured for a graduated VSL.
ISO/RTO Council
The SRC has no comment on this question.
70
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
8. As stated in the background information above, in response to industry comments, the Requirement for
preventing Sustained Outages due to fall-ins of vegetation (the new R8) is developed. Additionally the SDT
assigned Time Horizons, Violation Risk Factors, and Violation Severity Levels. Do you agree? If not, please
explain and propose an alternative.
Organization
Yes or No
Entegra Power Group LLC
Question 8 Comment
No comment
Ameren
Agree
American Electric Power
Agree
Associated Electric Cooperative,
Inc.
Agree
Bonneville Power Administration
Agree
Consolidated Edison Company of
New York Inc.
Agree
Entergy Services, Inc
Agree
Georgia Transmission
Corporation
Agree
Hydro One Networks inc.
Agree
Hydro-Quebec TransEnergie
(HQT)
Agree
Idaho Power Company
Agree
Independent Electricity System
Agree
71
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
Operator
ISO New England Inc.
Agree
Lee County Electric Cooperative
Agree
Manitoba Hydro
Agree
National Grid
Agree
Nebraska Public Power District
Agree
NERC Standards Review
Subcommittee
Agree
New Brunswick Power
Transmission
Agree
North Carolina Electric
Membership Corporation
Agree
Northeast Power Coordinating
Council--RSC
Agree
Northeast Utilities
Agree
Oncor Electric Delivery
Agree
Orange and Rockland Utilities,
Inc.
Agree
Pepco Holdings, Inc - Affiliates
(PHI)
Agree
Platte River Power Authority
Agree
72
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
Vegetation Management Group
Progress Energy Carolinas, Inc.
Agree
Public Service Co. of New
Mexico
Agree
Puget Sound Energy
Agree
ReliabilityFirst Corporation
Agree
Salt River Project
Agree
SCE&G
Agree
SERC Vegetation Managment
Sub-committee (VMS)
Agree
Southern Company
Agree
Superintendent Transmission
Maintenance
Agree
Tenessee Valley Authority
Agree
Tennessee Valley Authority
Agree
Tucson Electric Power Company
Agree
TVA
Agree
TVA
Agree
TVA
Agree
73
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
Vegetation Management Team
Agree
WECC RC
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Central Maine Power an Energy
East Company
Agree
Active right of way is an important component to R8.
Northern Indiana Public Service
Company
Agree
Have concerns about T.O.'s determining what is "active" and "inactive" R.O.W. which are explained in
Question 1 comments.
Southern California Edison
Company
Agree
SCE agrees with the content of the new R8, but believes that R8 should be combined with the new R7 into a
single requirement (a revised new R7). It appears to SCE that both bulleted exceptions listed in new R8 can
be applied to a revised new R7 which would then read: NEW R7. Each Transmission Owner shall prevent
Sustained Outages of applicable lines due to the blowing together of vegetation and a conductor, or,
vegetation falling into a conductor from within an Active Transmission Line Right of Way, with the following
exceptions: [Violation Risk Factor - Medium] [Time Horizon - Real Time]o Sustained Outages of applicable
lines that result from natural disasters or wind-blown debris.o Sustained Outages of applicable lines that result
from human or animal activity.
Tampa Electric Company
Agree
The white paper again states that the conductor is operating within its normal rating. If, when it is operating
above its normal rating it is not classified as a vegetation related outage under the Standard, this needs to be
clarified in the standard itself.
Arizona Public Service
Disagree
APS understand the concept of active ROW but the SDT needs to clarify trees within the easement or
permitted ROW and those outside the ROW. Utilities have a responsibility to maintain those within and shall
be held accountable.
American Transmission
Company
Disagree
ATC requests the SDT to clarify whether this includes branches partially severed from the tree falling into a
conductor from within the active ROW.
FirstEnergy Corp
Disagree
FE suggests a removal of R8. See our response to Question 5 for further information.
74
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
BC Transmission Corporation
Disagree
I strongly recommend that this be changed from “shall prevent sustained outages” to “shall minimize
sustained outages due to fall ins. It is operationally almost impossible to know precisely where the edge of the
ROW is in all situations under all conditions. This could lead to an incident where utilities are charged
unreasonably - for example, for an outage from a tree that was one foot within the active ROW line. We
should not be held liable when reasonable due diligence is practiced. Further, it is not economically feasible
for utilities to survey every ROW in the U.S. and Canada to determine precise clearance zones.
US Bureau of Reclamation
Disagree
It is not clear why Natural disasters or human or animal activity or wind blown debris have to do with
vegetation fall-ins and why they would need to be exempted.
PacifiCorp
Disagree
PacifiCorp suggests inserting “by a qualified observer” after “observed.” Otherwise, utilities could be held
accountable to train all their workers who might casually encounter vegetation conditions in their work or
commutes.
Pacific Gas and Electric Co.
Disagree
PG&E agrees in principal with R5 but disagrees with the exception for human activity noted in footnote (5),
specifically aboriculture, horticulture or agricultural activities. This exception is overly broad and could be
interpreted as exempting certian activities (such as planting orchards) from the standard and will invite legal
challenges to the TO’s right to perform vegetation management. PG&E proposes alternative language to the
exception as follows: Examples include, but are not limited to, logging, animal severing tree, vehicle contact
with tree, digging or removal of tree or new plantings between inspection cycles where the TO does not have
actual knowledge. As an alternative, add a generic force majeure statement as described in Q18 #2.
Xcel Energy
Disagree
Please see our comments above concerning footnotes 4 & 5.
JEA
Disagree
Please see the comment to question 4.
CenterPoint Energy
Disagree
R8 refers to “Active Transmission Line Right of Way” which is not defined as to its limits within the Standard.
The SDT has indicated in its response to 1st Draft Comments from CenterPoint Energy that the
“...Transmission Owner is responsible for defining the Active Transmission Line Right of Way.” However, that
defining clause is not included in the current definition. CenterPoint Energy recommends deleting the
phrase, “within an Active Transmission Line Right of Way”, and revising R8 to read, “Each Transmission
Owner shall prevent Sustained Outages of applicable lines due to vegetation falling into a conductor where
the Transmission Owner had the legal right or prior permission to remove the vegetation.”Since R1 in the
Standard does not address how a Transmission Owner conducts its work to address the fall-in of trees into an
adjacent transmission line, R8 may not be needed in the Standard. In the Technical Reference under the
Applicability of the Standard, the SDT states that “On the other hand, most other outage causes (such as
75
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
trees falling into lines....) are statistically intermittent. The probability of occurrence of these events is not
dependent on heavy loads. There is no cause-effect relationship which creates the probability of
simultaneous occurrence of other such events. Therefore these types of events are highly unlikely to cause
large-scale grid failures.” This observation made by the SDT would support the removal of R8 from the
Standard. R8 appears to be a major driving cause for introducing the new term “Active Transmission Line
Right of Way”, and removing R8 would avoid the need to introduce this ambiguously defined term and simplify
the Standard without significant impact on its intended purpose. The impact of R8 is also diminished by the
fact that the majority of fall-ins occur as a result of the exceptions currently stated in the rule and are typically
from outside the maintained boundary of the right of way.
E.ON U.S.
Disagree
The standard must be consistent with R4
Transmission Owner
Disagree
This requirement is not congruent with the purpose of this standard. The standard was enacted as a result of
the North East Blackout and a history of grid blackouts in which the growth of trees below conductors under
load contributed to the situation. Trees falling into the conductor create no more risk to cascading than causes
such as lightning or foreign interference. This requirement should be removed from the standard.
Duke Energy
Disagree
This requirement needs to be re-written such that it is a performance-based requirement with graduated
VSLs. As currently written, this requirement is a binary requirement which carries a single VSL which can
only be “Severe”. This may drive overly-aggressive and costly vegetation management programs that carry
minimal additional reliability benefit. A performance-based requirement should be developed relative to some
metric such as line-mile exposure that will promote high quality vegetation management, optimization of the
reliability cost/benefit relationship and deliver the overall end result of improved reliability to the system. The
performance-based requirement may still be zero tolerance, but should be structured for a graduated VSL.
ISO/RTO Council
The SRC has no comment on this question.
76
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
9. As stated in the background information above, in response to industry comments, the Requirement for
implementation of annual work plan (the new R9) is developed. Additionally the SDT assigned Time Horizons,
Violation Risk Factors, and Violation Severity Levels. Do you agree? If not, please explain and propose an
alternative.
Organization
Yes or No
Entegra Power Group LLC
Question 9 Comment
No comment
Ameren
Agree
American Electric Power
Agree
Associated Electric Cooperative,
Inc.
Agree
BC Transmission Corporation
Agree
Bonneville Power Administration
Agree
CenterPoint Energy
Agree
Consolidated Edison Company of
New York Inc.
Agree
Duke Energy
Agree
E.ON U.S.
Agree
Entergy Services, Inc
Agree
Georgia Transmission
Corporation
Agree
77
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Hydro One Networks inc.
Agree
Hydro-Quebec TransEnergie
(HQT)
Agree
Independent Electricity System
Operator
Agree
ISO New England Inc.
Agree
JEA
Agree
Lee County Electric Cooperative
Agree
National Grid
Agree
NERC Standards Review
Subcommittee
Agree
New Brunswick Power
Transmission
Agree
North Carolina Electric
Membership Corporation
Agree
Northeast Power Coordinating
Council--RSC
Agree
Northeast Utilities
Agree
Northern Indiana Public Service
Company
Agree
Orange and Rockland Utilities,
Agree
Question 9 Comment
78
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 9 Comment
Inc.
Pacific Gas and Electric Co.
Agree
Pepco Holdings, Inc - Affiliates
(PHI)
Agree
Progress Energy Carolinas, Inc.
Agree
Public Service Co. of New
Mexico
Agree
Puget Sound Energy
Agree
ReliabilityFirst Corporation
Agree
SCE&G
Agree
SERC Vegetation Managment
Sub-committee (VMS)
Agree
Southern Company
Agree
Superintendent Transmission
Maintenance
Agree
Tampa Electric Company
Agree
Tenessee Valley Authority
Agree
Tennessee Valley Authority
Agree
Transmission Owner
Agree
Tucson Electric Power Company
Agree
79
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 9 Comment
TVA
Agree
TVA
Agree
TVA
Agree
US Bureau of Reclamation
Agree
Vegetation Management Team
Agree
WECC RC
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Southern California Edison
Company
Agree
SCE agrees with the content of the new R9, however, we suggest it be placed immediately after R1 and be
identified as the new R2. SCE suggests that the requirement be modified to read: R9(R2). Each Transmission
Owner shall implement its annual work plan for VegetationManagement.
Oncor Electric Delivery
Disagree
Comments: See response to Q.1 The VSL for R9 indicate “failure to implement” percentages of the annual
work plan for the different VSL levels. There is lack of clarity in how “percentage” is defined. Is percentage
based on 1) # of lines in the annual plan vs # lines not worked according to the annual plan or 2) miles of line
not implemented vs total miles in the annual plan?
Platte River Power Authority
Vegetation Management Group
Disagree
It seems apparent that if you have a work plan (R1.3.) you should implement that plan and M9 specifies the
evidence of such implementation is specific to the work plan. However, the requirement is ambiguous as we
interpret it to apply only to the work plan as outlined in R1.3. but the last sentence "...to accomplish the
purpose of this standard" makes us wonder if perhaps the implementation and documentation required is
boarder. We understand that the implementation of the work plan is separated into a separate requirement so
that different VRF and VSL can be assigned but it would provide more clarity if the requirement were as
follows: R9. Each Transmission Owner shall implement and document its annual work plan for vegetation
management to meet R1.3. In cases when the annual work plan is adjusted or not completely implemented as
originally planned, the reasons for the deferrals or changes and the expected completion date of the
postponed work should be documented as well.
80
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 9 Comment
Nebraska Public Power District
Disagree
NPPD agrees with the wording provided by Xcel Energy. Each Transmission Owner shall implement its
annual work plan for vegetation management to accomplish the purpose of this standard, subject to its legal
rights.
Central Maine Power an Energy
East Company
Disagree
Restore the phrase " within the extent of its easement and/or legal rights" found in FAC 003 1 .
Idaho Power Company
Disagree
Reword R9 to say ‘The TO shall implement its annual work plan for vegetation management within its legal
rights...’
American Transmission
Company
Disagree
Same response as in Question # 1 (addressing R1.3 and R1. 5) ATC believes that Requirement 9 should
allow for flexibility in the annual work plan to carry over implementation to the following calendar year.
Manitoba Hydro
Disagree
The annual work plan should allow for justification to carry over the implementation to the following calendar
year or years.
PacifiCorp
Disagree
The current language of the requirement places the sole burden for implementation of the annual work plan,
including the correction timeframe, on the Transmission Owner. This could be problematic on federal
property where local district offices have authority over whether or not to approve vegetation management
work. In order to implement their annual work plans, Transmission Owners must obtain approval from any
applicable federal agency through that agency’s approval process. There are occasions where authorization
from that agency may take many months or even years. The language of the requirement should be modified
to take this into account; if authorization from the applicable federal agency is not granted within six months,
the Transmission Owner should not be subject to penalties or sanctions because these would be associated
with actions beyond their control.
Arizona Public Service
Disagree
There should be a footnote that if federal or state agencies fail to approve annual work plans within 90 days of
submittal the utility will not be held accountable for not completing its annual work plan or taking into account
the time it takes to get approval. We have land agencies that give us approvals within 2 weeks and others
that have taken over a year. Utilities are at their mercy on the approval process. If there is turn-over in the
land agency the approval process changes again and it is impossible to determine the anticipated timeline by
state, tribal and federal agencies.
Salt River Project
Disagree
There should be an additional statement to include “subject to the Transmission Owner’s legal rights”. This
requirement should acknowledge the difficulties Transmission Owner’s have working with federal and state
81
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 9 Comment
agencies that do not approve work plans in a timely manner.
FirstEnergy Corp
Disagree
We agree with this requirement except for the phrase "to accomplish the purpose of this standard". This
phrase is unnecessary and could lead to unintended interpretations. It is understood that every requirement in
each reliability standard is written to accomplish the purpose of its respective standard, and those words
should not be required in the text of the requirements.
Xcel Energy
Disagree
Xcel Energy strongly believes that the requirement that each Transmission Owner shall implement its annual
work plan for vegetation management must acknowledge that such vegetation management is subject to the
legal rights available to the Transmission Owner. Hence, it is suggested that R9 be revised to read: "Each
Transmission Owner shall implement its annual work plan for vegetation management to accomplish the
purpose of this standard, subject to its legal rights."
ISO/RTO Council
The SRC has no comment on this question.
82
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
10.
As stated in the background information above, in response to industry comments, the Requirement for the
preparation of list for sub 200kV transmission lines by the Planning Coordinator (the new R10) is developed.
Additionally the SDT assigned Time Horizons, Violation Risk Factors, and Violation Severity Levels. Do you
agree? If not, please explain and propose an alternative.
Organization
Yes or No
Question 10 Comment
Entegra Power Group LLC
No comment
Tampa Electric Company
We do not agree or disagree on this Requirement.
Ameren
Agree
American Electric Power
Agree
Arizona Public Service
Agree
Associated Electric Cooperative,
Inc.
Agree
BC Transmission Corporation
Agree
Bonneville Power Administration
Agree
CenterPoint Energy
Agree
Central Maine Power an Energy
East Company
Agree
Consolidated Edison Company of
New York Inc.
Agree
Duke Energy
Agree
83
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
E.ON U.S.
Agree
Entergy Services, Inc
Agree
Georgia Transmission
Corporation
Agree
Hydro One Networks inc.
Agree
Idaho Power Company
Agree
JEA
Agree
Lee County Electric Cooperative
Agree
Manitoba Hydro
Agree
National Grid
Agree
Nebraska Public Power District
Agree
New Brunswick Power
Transmission
Agree
North Carolina Electric
Membership Corporation
Agree
Northeast Utilities
Agree
Northern Indiana Public Service
Company
Agree
Oncor Electric Delivery
Agree
Question 10 Comment
84
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Orange and Rockland Utilities,
Inc.
Agree
Pacific Gas and Electric Co.
Agree
PacifiCorp
Agree
Pepco Holdings, Inc - Affiliates
(PHI)
Agree
Progress Energy Carolinas, Inc.
Agree
Puget Sound Energy
Agree
ReliabilityFirst Corporation
Agree
Salt River Project
Agree
SCE&G
Agree
SERC Vegetation Managment
Sub-committee (VMS)
Agree
Southern Company
Agree
Tenessee Valley Authority
Agree
Tennessee Valley Authority
Agree
Transmission Owner
Agree
Tucson Electric Power Company
Agree
TVA
Agree
Question 10 Comment
85
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
TVA
Agree
TVA
Agree
Vegetation Management Team
Agree
WECC RC
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Xcel Energy
Agree
Superintendent Transmission
Maintenance
Agree
Agree with the requirements under R10, however, request further clarification on the source and qualifications
of the "Planning Coordinator".
Edison Electric Institute
Agree
First, EEI generally agrees with the draft revised applicability section. In addition and to help reduce
ambiguity in the text, EEI asks that the SDT consider additional language in R.10 and R. 11 (and M. 10 and
M. 11) that Planning Coordinators be required to include all facilities under 200 kv identified as IROL facilities
under FAC-014. For example, the language of the applicability of the Standard could be stated to include all
facilities under 200 kv identified under FAC-014 as IROL facilities. The corresponding requirement could be
stated as ‘Each Planning Coordinator will notify all Registered Entities under 200 kv for which this Reliability
Standard applies.’ EEI also believes that this change would be consistent with the discussion of the issue in
Order No. 693 (P. 706)Second, EEI recommends consideration for including in the applicability section of the
Standard the phrase from the technical paper, i.e., the Standard will not apply to line sections inside the
electric station fence or other boundary of an electric station, or underground lines. (Technical Paper, p. 8) If
included, this addition would add much-needed clarity for Registered Entities.In particular, EEI encourages
further consideration for lines from generation facilities to network substations. Some Generation Owners
have lines greater than a mile in length EEI asks the SDT consider whether to extend applicability of the
Standard for Generation Owners that own lines that meeting certain predefined criteria, or other approaches
that would clarify the treatment of lines owned by Generation Owners on the generator side of a network
substation. Finally, further clarification may be needed on whether the Standard will cover all facilities rated at
greater than 200 kv. For example, there may be 230 kv radial lines to distribution deemed exempt from a
BPS -defined set of assets. EEI understands that some confusion exists on whether the threshold BPS
86
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
definition governs applicability for all individual Standards.
Southern California Edison
Company
Agree
SCE generally agrees with the requirement, but is concerned about the new role for the Planning Coordinator
and the posibility that it will have shared compliance responsibilities for designated lines with the
Transmission Owner.
Hydro-Quebec TransEnergie
(HQT)
Disagree
NERC standards apply only to BES facilities and not necessarily at voltage level threshold. The standards
should not apply to facilities that are not BES. Within a standard there might be exceptions for cases where
the standard would apply only to a subset of the BES facilities. The only change between the current standard
and the proposed draft is who designates critical lines. In the current standard it was the RRO while in the
new standard it is the PC. The RRO (or the PC in the future version) can only designate critical lines among
those that are already classified as BES.Furthermore, the purpose of the standard should be changed to read
: 'To improve the reliability of the Bulk Electric System by preventing....' since the NERC Standards are
designed to be applicable to the BES, not the 'electric transmission system'; or is it the real intention of NERC
to have some standards for BES and some for 'electric transmission system'? We would appreciate to have
the SDT opinion on this.
Independent Electricity System
Operator
Disagree
NERC standards apply only to BES facilities, and not necessarily a voltage level threshold. The standards
should not apply to facilities that are not BES. Within a standard there might be exceptions for cases where
the standard would apply only to a subset of the BES facilities. This is the case of the FAC-003 current
standard and the new draft which both state that the standard applies only to transmission lines operated at
200 kV and above, and to any lower voltage lines designated as critical to the reliability of the electric system
in the region. The only change between the current standard and the proposed draft is who designates the
above critical lines. In the current standard it was the RRO while in the new standard it is the PC. The RRO
(or the PC in the future version) can only designate critical lines among those that are already classified as
BES.
Northeast Power Coordinating
Council--RSC
Disagree
NERC standards apply only to BES facilities, and not necessarily a voltage level threshold. The standards
should not apply to facilities that are not BES. Within a standard there might be exceptions for cases where
the standard would apply only to a subset of the BES facilities. This is the case of the FAC-003 current
standard and the new draft which both state that the standard applies only to transmission lines operated at
200 kV and above, and to any lower voltage lines designated as critical to the reliability of the electric system
in the region. The only change between the current standard and the proposed draft is who designates the
above critical lines. In the current standard it was the RRO while in the new standard it is the PC. The RRO
(or the PC in the future version) can only designate critical lines among those that are already classified as
BES.
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
ISO New England Inc.
Disagree
NERC standards apply only to BES facilities. The standards should not apply to facilities that are not BES.
Within a standard there might be exceptions for cases where the standard would apply only to a subset of the
BES facilities. This is the case of the FAC-003 current standard and the new draft which both state that the
standard applies only to transmission lines operated at 200 kV and above, and to any lower voltage lines
designated as critical to the reliability of the electric system in the region. The only change between the
current standard and the proposed draft is who designates the above critical lines. In the current standard it
was the RRO while in the new standard it is the PC. The RRO (or the PC in the future version) can only
designate critical lines among those that are already classified as BES.
Public Service Co. of New
Mexico
Disagree
PNM disagrees with the use of the "Planning Coordinator." There is no definition of this individual or group of
individuals anywhere in the proposed standard or white paper that is apparent. Clarification is needed.
MRO NERC Standards Review
Subcommittee
Disagree
R10 states that the PC “consult” with its TOs and neighboring PCs to obtain input for the list of qualifying
facilities operated below 200 kV. What does “consult” mean? It is a surrogate for “coordinate” which is being
removed from standards because of compliance implications - an entity might be held in violation if another
entity did not respond or act to “coordinate” the effort. Also, R11 uses the terms “reliability significance” and
“unacceptable risk of instability” which are undefined and not measurable. R11 is the lead requirement and
could be moved to new R1 location. Better wording would be “Each PC must develop and document a
methodology for determining a list of facilities in its area operated at less than 200 kV whose loss would
cause instability, separation or cascading failures on the BES. “ R10 follows directly and would become new
R2. Better wording would be “Each PC shall prepare and review annually a list of facilities in its area
operated at less than 200 kV which are subject to this standard. This list will be based on information
obtained from its TOs. Results will be provided to its TOs and neighboring PCs.”
American Transmission
Company
Disagree
See response to Question #11 below.
Platte River Power Authority
Vegetation Management Group
Disagree
The requirement is confusing as it infers that it relates to R11 but never states such. It might be clearer if it
followed R11, as we believe the correct process should be as stated in the FAC-003-2 Technical Reference:
"Planning Coordinators, using their methodologies described in R11, will need to conduct the necessary
studies and identify candidate sub-200kV transmission lines for potential applicability under the Standard. The
Planning Coordinators will next need to consult with its Transmission Owners and neighboring Planning
Coordinators to resolve any differences in the selection of the sub-200kV transmission lines of common
interest. Finally, the Planning Coordinator will need to finalize, adopt and issue the list of designated sub200kV lines". The way it is currently written the Planning Coordinator will need to finalize, adopt and issue the
list of designated sub-200kV lines first then consult with its Transmission Operators and neighboring Planning
88
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
Coordinators and last develop a methodology. We aren’t sure why R10 and R11 are separate requirements
as they seem to be related and both have the same VRF and time horizon. We believe the two requirements
should be combined and placed in sequential order.
US Bureau of Reclamation
Disagree
The role of the Planning Coordinator is inappropriately described in this requirement. The role of the Planning
Coordinator as related in the NERC Functional Model is to conduct assessments of transmisssion systems.
Planning Coordinators do not implement resource plans (NERC Functional Model Technical Document Page
12 last paragraph). The determination of criticality is an implementation action or operational determination
which is reserved for either the Transmission Planner or the Reliability Coordinator. The role of the Planning
coordinator is to develop methodologies which are used by others in ensuring reliable BES operation.
Specifically the "Planning Coordinator coordinates and evaluates and recommends reinforcement and
corrective plans resulting from studies and analysis of system performance and interconnection of facilities."
To require the Planning Coordinator to prepare a list of lines which are subject to this standard (critical to the
BES) is modifying the role of the Planning Coordinator and should be examined in the context of the role of
the Transmission Operator, Transmission Owner, Transmission Planner and Reliability Cooridnator under a
separate project.
FirstEnergy Corp
Disagree
We suggest the team consider changes to R10 and R11 to ensure consistency with standard FAC-014 for the
transmission facilities that are sub-200kV and deemed as having "reliability significance" and placing the grid
at risk for instability and Cascading. FE believes the appropriate set of sub-200kV lines are those identified
as being associated with an IROL condition. Utilizing an already established IROL methodology (FAC-010
and FAC-014) eliminates the need for the Planning Coordinator to coordinate with the Transmission Owner(s)
alleviating a level of tedious compliance evidence for the Planning Coordinator. Finally, presently missing
within the requirement is the need for the Planning Coordinator to submit a list of the reliability significant sub200kV facilities to the Transmission Owner(s).We propose that requirements R10 and R11 be replace with a
single new R10 requirement as follows:"R10 Each Planning Coordinator shall prepare and review annually, a
list of lines thatare operated below 200kV, if any, which are subject to this standard. 10.1 The list shall reflect
sub-200kV transmission facilities associated with an IROL condition as identified per NERC reliability
standard FAC-014. 10.2 The Planning Coordinator shall annually notify its Transmission Owner(s) of the sub200kV reliability significant facilities that are subject to this standard."No changes to the Violation Risk Factors
or Time Horizons for the proposed requirement. We support a VRF of Lower and Time-Horizon of Long-Term
Planning.If the proposal is accepted, conforming changes to the Measures are required.Lastly, the team
should consider asking NERC to add to its Standards Development issues database a need to revise
standard FAC-014 such that the Transmission Owner is notified of all IROL transmission facilities as part of
FAC-014. This would allow for changes in FAC-003 that could eliminate the Planning Coordinator as being
applicable to the FAC-003 standard.
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
ISO/RTO Council
Yes or No
Disagree
Question 10 Comment
We reiterate our comments submitted for Version 1 that the Planning Coordinators and Reliability
Coordinators do not have a role in this standard, and requirements R10 and R11 are not needed.
Facilities below 200KV are generally not critical on a wide area basis. There may be some facilities that are
critical for local service – most likely in metropolitan areas or a very rural system where they are wholly
dependent on sub 200KV facilities. Therefore, there is not a need for a wide area assessment by the Planning
Coordinator in this standard. Those facilities below 200KV that are vital for local service would already be
identified and included in the vegetation management program of the Transmission Owner. Further, facilities
that are associated with IROLs, regardless of voltage class, are already identified through the R5
requirements. We understand the SDT’s response to our initial comments that FERC expects this standard to
require the identification of relevant sub 200KV facilities, but for the reasons presented in these comments,
we believe that sub 200KV facilities relevant to wide area reliability are few and there should not be an
expectation or requirement for the PCs to identify significant portions of sub 200kv facilities for purposes of
this standard. Such facilities should be included only when the PC has documented a need.
90
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
11.
As stated in the background information above, in response to industry comments, the Requirement for the
Planning Coordinator to document method for identification of applicable sub-200kV transmission lines (the
new R11) is developed. Additionally the SDT assigned Time Horizons, Violation Risk Factors, and Violation
Severity Levels. Do you agree? If not, please explain and propose an alternative.
Organization
Yes or No
Question 11 Comment
Entegra Power Group LLC
No comment
Tampa Electric Company
We do not agree or disagree on this Requirement.
Ameren
Agree
American Electric Power
Agree
Arizona Public Service
Agree
Associated Electric Cooperative,
Inc.
Agree
BC Transmission Corporation
Agree
Bonneville Power Administration
Agree
CenterPoint Energy
Agree
Central Maine Power an Energy
East Company
Agree
Consolidated Edison Company of
New York Inc.
Agree
Duke Energy
Agree
91
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
E.ON U.S.
Agree
Entergy Services, Inc
Agree
Georgia Transmission
Corporation
Agree
Hydro One Networks inc.
Agree
Idaho Power Company
Agree
Lee County Electric Cooperative
Agree
Manitoba Hydro
Agree
National Grid
Agree
Nebraska Public Power District
Agree
New Brunswick Power
Transmission
Agree
North Carolina Electric
Membership Corporation
Agree
Northeast Utilities
Agree
Northern Indiana Public Service
Company
Agree
Oncor Electric Delivery
Agree
Orange and Rockland Utilities,
Inc.
Agree
Question 11 Comment
92
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Pacific Gas and Electric Co.
Agree
PacifiCorp
Agree
Pepco Holdings, Inc - Affiliates
(PHI)
Agree
Progress Energy Carolinas, Inc.
Agree
ReliabilityFirst Corporation
Agree
Salt River Project
Agree
SCE&G
Agree
SERC Vegetation Managment
Sub-committee (VMS)
Agree
Southern Company
Agree
Superintendent Transmission
Maintenance
Agree
Tenessee Valley Authority
Agree
Tennessee Valley Authority
Agree
Transmission Owner
Agree
Tucson Electric Power Company
Agree
TVA
Agree
TVA
Agree
Question 11 Comment
93
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 11 Comment
TVA
Agree
US Bureau of Reclamation
Agree
Vegetation Management Team
Agree
WECC RC
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Puget Sound Energy
Agree
Assuming the Planning Coordinator is approved through the functional model revisions and entities register
for it.
JEA
Agree
Might want to consider adding something along the lines of "for the purposes of vegetation management" at
the end to clarify the purpose of the list.
Southern California Edison
Company
Agree
SCE generally agrres with the requirement, but is concerned about the role identified for the Planning
Coordinator and the possibility that it will have shared compliance responsbilities with the Transmission
Owner for certain identified lines.
Public Service Co. of New
Mexico
Disagree
Again, see comment from Question 12 - no definition of the term "Planning Coordinator."
American Transmission
Company
Disagree
ATC proposes the following:Remove both R10 and R11 because the TPL-002 and TPL-003 standards
already require the Transmission Planner and the Planning Coordinator to ensure reliable system operation
for loss of single-element and multi-element contingencies. ATC recommends changing the appropriate text
in the first two items under A4.2, Facilities: to “. . . transmission lines operated below 200kv that are identified
as an element of an IROL or Major WECC Transfer Path”.In addition, TPL-002 and TPL-003 require the TP
and PC to identify IROL’s so that the applicability section of this document should use the outcome from those
approved Reliability Standards as an input for this standard. Structuring the standard in this way will makes
future enhancement efforts more efficient.If the R10 and R11 removal suggestion is rejected, then revise R11
to, “. . . its methodology for assessing which, if any, lines are subject to this standard. The methodology shall
describe the process for determining which lines, if any, below 200kV are expected to have an unacceptable
94
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 11 Comment
instability or cascading outcome due to TPL-002 and TPL-003 conditions.”
NERC Standards Review
Subcommittee
Disagree
See comments above in Question 10.
Platte River Power Authority
Vegetation Management Group
Disagree
The criteria for assessing the lines whose loss would place the gird at an unacceptable risk of instability,
separation, or cascading failures needs to be more clearly defined. We interpret R10 and R11 to mean that
any Category B contingency of a sub-200kV line that causes instability, separation, or cascading failure is
subject to FAC-003-2. Is this your desired level of assessment?
Hydro-Quebec TransEnergie
(HQT)
Disagree
This should apply to all BES transmission facilities. The use of 200kV as a threshold should be removed. See
also Q10 answer.
Independent Electricity System
Operator
Disagree
This should apply to all BES transmission facilities. The use of 200kV as a threshold should be removed.
ISO New England Inc.
Disagree
This should apply to all BES transmission facilities. The use of 200kV as a threshold should be removed.
Northeast Power Coordinating
Council--RSC
Disagree
This should apply to all BES transmission facilities. The use of 200kV as a threshold should be removed.
FirstEnergy Corp
Disagree
We propose the removal of requirement R11. See our response to Question 10 for further details.
ISO/RTO Council
The SRC has no comment on this question.
95
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
12.
The SDT received suggestions from commenters to re-sequence the requirements contained in the standard
to improve the logical flow of this document. The SDT submits for consideration a proposed alternative
sequence. Do you agree with the proposed alternative sequencing? If not, please recommend a suggested
sequence.
Organization
Yes or No
Question 12 Comment
Entegra Power Group LLC
No comment
Pepco Holdings, Inc - Affiliates
(PHI)
No preference. All standards must be considered in entirety for compliance.
Ameren
Agree
American Electric Power
Agree
Arizona Public Service
Agree
BC Transmission Corporation
Agree
Bonneville Power Administration
Agree
CenterPoint Energy
Agree
Consolidated Edison Company of
New York Inc.
Agree
Duke Energy
Agree
E.ON U.S.
Agree
Entergy Services, Inc
Agree
Georgia Transmission
Agree
96
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 12 Comment
Corporation
Hydro One Networks inc.
Agree
Idaho Power Company
Agree
Independent Electricity System
Operator
Agree
ISO New England Inc.
Agree
Lee County Electric Cooperative
Agree
Manitoba Hydro
Agree
National Grid
Agree
Nebraska Public Power District
Agree
North Carolina Electric
Membership Corporation
Agree
Northeast Power Coordinating
Council--RSC
Agree
Northeast Utilities
Agree
Oncor Electric Delivery
Agree
Orange and Rockland Utilities,
Inc.
Agree
Pacific Gas and Electric Co.
Agree
PacifiCorp
Agree
97
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Platte River Power Authority
Vegetation Management Group
Agree
Progress Energy Carolinas, Inc.
Agree
Public Service Co. of New
Mexico
Agree
Puget Sound Energy
Agree
Salt River Project
Agree
SCE&G
Agree
SERC Vegetation Managment
Sub-committee (VMS)
Agree
Southern California Edison
Company
Agree
Southern Company
Agree
Superintendent Transmission
Maintenance
Agree
Tampa Electric Company
Agree
Tenessee Valley Authority
Agree
Tennessee Valley Authority
Agree
Transmission Owner
Agree
Tucson Electric Power Company
Agree
Question 12 Comment
98
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 12 Comment
TVA
Agree
TVA
Agree
TVA
Agree
US Bureau of Reclamation
Agree
Vegetation Management Team
Agree
WECC RC
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Xcel Energy
Agree
Hydro-Quebec TransEnergie
(HQT)
Agree
As per our answer to Q5, R5 and R6 should be combined to R5 with the elimination of the IROL concept.
American Transmission
Company
Agree
ATC agrees generally with the rearrangement. We believe that the proposed requirements R11 and R10
should be removed because can be adequately covered in the applicability section of this document. The
remaining proposed reorder would then be okay.
MRO NERC Standards Review
Subcommittee
Agree
N/A
ReliabilityFirst Corporation
Agree
This proposed sequence flows better.
JEA
Agree
Would not the Vegetation Inspections be documented in the Work Plan? Perhaps those two should be
switched or combined. I'd move Implement Imminent Threat to the end.
Associated Electric Cooperative,
Disagree
Feel that R10 and R11 can be combined into one.
Associated Electric Cooperative Inc. believes the current requirements sequence is appropriate.
99
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 12 Comment
Inc.
Northern Indiana Public Service
Company
Disagree
Prefer current sequence except I have no objection to placing the PC requirements at the top of the list.
New Brunswick Power
Transmission
Disagree
Propose further revision of "alternate sequence" to R1-4, R6, R5, R7, R10, R11, R9, R8. Suggested proposal
reflects dealing with high priority issues first. That is imminent threats must be handled before planned work.
Similarly for prevention of outages grow-ins are the most critical, followed by blow-ins and fall-ins.
Central Maine Power an Energy
East Company
Disagree
Suggest reverse R4 with R5.
FirstEnergy Corp
Disagree
While we don't have a strong opinion on this, we believe the proposed sequence of R8, R9, R10 and R11 (old
R8, R7, R6 and R5) would be better placed in the following order using the teams designated proposed
numbering: R11, R10, R8 and R9. This order is suggested so that a greater emphasis on grow-in and IROL
is accomplished and that the standard addresses those items first.
ISO/RTO Council
The SRC has no comment on this question.
100
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
13.
The Implementation Plan proposes an effective date that gives entities at least a year to become fully
compliant. Do you agree with this implementation plan? If not, please indicate what should be changed and
indicate why.
Organization
Yes or No
Ameren
Agree
American Transmission
Company
Agree
Arizona Public Service
Agree
Associated Electric Cooperative,
Inc.
Agree
BC Transmission Corporation
Agree
Bonneville Power Administration
Agree
CenterPoint Energy
Agree
Central Maine Power an Energy
East Company
Agree
Consolidated Edison Company of
New York Inc.
Agree
Duke Energy
Agree
E.ON U.S.
Agree
Entegra Power Group LLC
Agree
Question 13 Comment
101
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
FirstEnergy Corp
Agree
Georgia Transmission
Corporation
Agree
Hydro One Networks inc.
Agree
Hydro-Quebec TransEnergie
(HQT)
Agree
Idaho Power Company
Agree
Independent Electricity System
Operator
Agree
ISO New England Inc.
Agree
JEA
Agree
Lee County Electric Cooperative
Agree
Manitoba Hydro
Agree
National Grid
Agree
Nebraska Public Power District
Agree
New Brunswick Power
Transmission
Agree
North Carolina Electric
Membership Corporation
Agree
Northeast Power Coordinating
Agree
Question 13 Comment
102
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
Council--RSC
Northeast Utilities
Agree
Northern Indiana Public Service
Company
Agree
Oncor Electric Delivery
Agree
Orange and Rockland Utilities,
Inc.
Agree
Pacific Gas and Electric Co.
Agree
PacifiCorp
Agree
Pepco Holdings, Inc - Affiliates
(PHI)
Agree
Platte River Power Authority
Vegetation Management Group
Agree
Progress Energy Carolinas, Inc.
Agree
Public Service Co. of New
Mexico
Agree
Puget Sound Energy
Agree
ReliabilityFirst Corporation
Agree
Salt River Project
Agree
Southern California Edison
Company
Agree
103
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Superintendent Transmission
Maintenance
Agree
Tampa Electric Company
Agree
Tenessee Valley Authority
Agree
Tennessee Valley Authority
Agree
Transmission Owner
Agree
Tucson Electric Power Company
Agree
TVA
Agree
TVA
Agree
TVA
Agree
US Bureau of Reclamation
Agree
Vegetation Management Team
Agree
WECC RC
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Xcel Energy
Agree
American Electric Power
Agree
Question 13 Comment
The one year should be adequate presuming that the Planning Coordinator does not designate significant
numbers of facilities below 200 kV. Should this become the case, a year would be insufficient to for
implementation.
104
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
MRO NERC Standards Review
Subcommittee
Disagree
MRO NSRS does not believe that current proposed implementation time in Facilities 4.2.2 is adequate. Given
the time required to conduct a survey to determine if a company's lines are maintained sufficiently to meet the
new requirements, in addition to the time and resources (both budgetary and labor) required to implement the
results of the survey, we believe that between 24 and 36 months may be required to implement this version of
the standard.
SCE&G
Disagree
SCE&G believes that this standard is superior to the existing standard and therefore requests that the
effective date be moved up. We also recommend that the new standard be started on a calendar year.
Southern Company
Disagree
SDT should consider a more rapid implementation plan because the new standard has significant
improvement over the existing standard. For example, Southern Company feels it could be implemented the
first calendar day of the first calendar quarter following approval by the NERC Board of Trustees.
SERC Vegetation Managment
Sub-committee (VMS)
Disagree
The VMS believes that this standard is superior to the existing standard and therefore requests that the
effective date be moved up. The VMS also recommends that the new standard be started on a calendar year.
Entergy Services, Inc
Disagree
This Standard should move forward prior to the current one year provided, it is far superior to the existing
Standard.
Agree
If this standard retains the need to identify sub 200KV facilities, then one year provides sufficient time for
Planning Coordinators to meet R10 and R11.
ISO/RTO Council
105
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
14.
Do you have further questions about the standard that the Technical Reference document (White Paper)
does not clear up? If so, please elaborate and propose additions.
Organization
Yes or No
Question 14 Comment
Xcel Energy
(a) To avoid confusion, the diagrams of the ROWs in the White Paper should not have tree-like objects in the
Active Transmission Right of Way. If any vegetation is to be shown in those areas, the vegetation should be
shrubbery.(b) The discussion on p. 24 indicates that the MVCD is the “spark-over zone.” The MVCD
(hopefully to be renamed) should not directly correlate to the spark-over zone. The spark-over zone should
be less than the MVCD.
Hydro One Networks inc.
(a) we suggest an illustration of R7 be added. R7 text states “... due to the blowing together of vegetation and
a conductor within an Active Transmission Line ROW.” These words could suggest that sustained outages
from vegetation (branches) extending within the active ROW, but originating from trees located outside the
active ROW, might not be considered a preventable outage. An illustration in the reference paper would
provide clarity.(b) Confusion still exists around the determination of the “active transmission line right-of-way”.
The diagrams shown in the white paper, though helpful, do not necessarily apply to all field conditions.
Specific questions include: Is it up to the Transmission Operator to determine the “active transmission line
right-of-way”, particularly in cases where the RoW may not be maintained to the legal boundary? Example 4
in the definition of “active transmission line right-of-way” (pg. 5) uses the words “deactivated” and “unavailable
for service”; these terms should be clearly defined, as there can be several degrees of de-activation and
entities may interpret them differently.
BC Transmission Corporation
Active ROW needs to be defined in more detail
Arizona Public Service
Active ROW needs to defined in more detail.
Consolidated Edison Company of
New York Inc.
CECONY recommends that an illustration of R7 be added to the Technical Reference document. R7 text
states “ ... due to the blowing together of vegetation and a conductor within an Active Transmission Line
ROW." These words could be interpreted to mean that sustained outages from vegetation (branches)
extending into the active ROW, but originating from trees located outside the active ROW, might not be
considered a preventable outage. An illustration in the reference paper would provide clarity.
Duke Energy
During the first comment period, it was noted that it was difficult to prove a negative. This will be the case with
some of the requirements proposed in this version. For example, it would be beneficial to note in the
Technical Reference Paper that documented vegetation inspections that do not identify an encroachment (R4
106
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 14 Comment
violation) would be proof of compliance. Other examples may exist that the team may consider including for
reference.
Entegra Power Group LLC
In some way address dealing with Generator Interconnection Facilities (GIF) which only have a few spans of
transmission interconnect. Will this be addressed in a future specific Standard, or as a separate requirement
under FAC-003-2? Entegra suggests a much simpler approach can be employed when under 4 spans worth
of vegetation can be visually inspected every 1-2 years and trimmed to prevent any possible vegetation
impact to subject lines/system.
Tampa Electric Company
In the white paper, page 35, paragraph 2, it states that if the conductor is operating above its rating it “would
not be classified as vegetation related sustained outage under the standard.” If this is so it needs to be stated
and/or clarified in the standard itself. In addition on page 35, 3rd paragraph, last sentence of the white paper
it states, “ Additionally, sustained outages due to wind-blown debris, such as large limbs and branches,
separated tree tops, etc., are exempt from this standard.” If this is so it needs to be stated in the standard.
Need clarification, if the debris is from trees within the active transmission ROW is it a violation?
Tucson Electric Power Company
In the white paper, the pictorial reference of the active right of way has no reference to show what the
minimum distance beyond the conductor envelope should be to establish the width of the active right of way.
US Bureau of Reclamation
It is not clear at what physical point in the BES the is standard would apply; such as from the first structure
outside of the substation/switchyard or other demarcation.
National Grid
National Grid suggests an illustration of R7 be added. R7 text states “ ... due to the blowing together of
vegetation and a conductor within an Active Transmission Line ROW”. These words could suggest that
sustained outages from vegetation (branches) extending within the active ROW, but originating from trees
located outside the active ROW, might not be considered a preventable outage. An illustration in the
reference paper would provide clarity that these sustained outages are a violation of R7.
ReliabilityFirst Corporation
No
TVA
no
WECC RC
NO
Associated Electric Cooperative,
No comments
107
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 14 Comment
Inc.
North Carolina Electric
Membership Corporation
None
SCE&G
None
SERC Vegetation Managment
Sub-committee (VMS)
None.
Southern Company
None.
Pepco Holdings, Inc - Affiliates
(PHI)
PHI has concerns that the reference document has many items that are critical to the determination of
compliance.
CenterPoint Energy
Questions are listed below:1. How does the Transmission Owner determine the geometric limits of an “Active
Transmission Line Right of Way” to determine how a Sustained Outage is reported under Category 1A,
Category 1B, Category 2, and Category 4.2. Why does an “Inactive R.O.W.” contain trees that are within
falling distance of an applicable transmission line? (Figure 1 has such a depiction.) Is the “Inactive R.O.W.
outside the legal limits of the Transmission Owners’ right of way?3. Why don’t Requirements 5, 6, 7 and 8,
and their corresponding Measures 5, 6, 7, and 8, and the Compliance 1.5 Sustained Outage Categories Category 1A, Category 1B, Category 4, and Category 2 all have the same exceptions listed? For example,
R5 has the exceptions for “Sustained Outages of applicable lines that result from natural disasters” and
Sustained Outages of applicable lines that result from human or animal activity.” M5 and Category 1A do not
contain those exceptions. Category 1A qualifies events to be reported as “inside and/or outside of the Active
Transmission Line ROW”, but R5 and M5 do not have such a reference. How will the reporting differentiate
between a Sustained Outage caused by improper vegetation management and those caused by natural
disasters? FAC-003-1 R3.2 did not require the reporting of certain sustained transmission line outages (e.g.
natural disasters, human activity, etc.). It is not clear what the current draft intends to have reported.
Nebraska Public Power District
Remove the tree-like objects from the diagrams of the ROWs in the White Paper. If any vegetation is to be
shown in those areas, the vegetation should only be shrubbery.
Entergy Services, Inc
See additional Entergy comments below.
108
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 14 Comment
Orange and Rockland Utilities,
Inc.
Suggest an illustration of R7 be added. R7 text states “ ... due to the blowing together of vegetation and a
conductor within an Active Transmission Line ROW”. These words could suggest that sustained outages
from vegetation (branches) extending within the active ROW, but originating from trees located outside the
active ROW, might not be considered a preventable outage. An illustration in the reference paper would
provide clarity.
Hydro-Quebec TransEnergie
(HQT)
Suggest an illustration of R7 be added. R7 text states “... due to the blowing together of vegetation and a
conductor within an Active Transmission Line ROW”. These words could suggest that sustained outages
from vegetation (branches) extending within the active ROW, but originating from trees located outside the
active ROW, might not be considered a preventable outage. An illustration in the reference paper would
provide clarity.Confusion still exists regarding the determination of the “active transmission line right-of-way”.
The diagrams shown in the white paper, though helpful, do not necessarily apply to all field conditions.
Specific questions include: is it up to the Transmission Operator to determine the “active transmission line
right-of-way”, particularly in cases where the ROW may not be maintained to the legal boundary? Example 4
in the definition of “active transmission line right-of-way” (pg. 5) uses the words “deactivated” and “unavailable
for service”. The terms active, deactivated, and unavailable for service should be clearly defined as they can
easily be interpreted different ways between different entities, and for different situations.
Independent Electricity System
Operator
Suggest an illustration of R7 be added. R7 text states “... due to the blowing together of vegetation and a
conductor within an Active Transmission Line ROW”. These words could suggest that sustained outages
from vegetation (branches) extending within the active ROW, but originating from trees located outside the
active ROW, might not be considered a preventable outage. An illustration in the reference paper would
provide clarity.Confusion still exists regarding the determination of the “active transmission line right-of-way”.
The diagrams shown in the white paper, though helpful, do not necessarily apply to all field conditions.
Specific questions include: is it up to the Transmission Operator to determine the “active transmission line
right-of-way”, particularly in cases where the ROW may not be maintained to the legal boundary? Example 4
in the definition of “active transmission line right-of-way” (pg. 5) uses the words “deactivated” and “unavailable
for service”. The terms active, deactivated, and unavailable for service should be clearly defined as they can
easily be interpreted different ways between different entities, and for different situations.
ISO New England Inc.
Suggest an illustration of R7 be added. R7 text states “... due to the blowing together of vegetation and a
conductor within an Active Transmission Line ROW”. These words could suggest that sustained outages
from vegetation (branches) extending within the active ROW, but originating from trees located outside the
active ROW, might not be considered a preventable outage. An illustration in the reference paper would
provide clarity.Confusion still exists regarding the determination of the “active transmission line right-of-way”.
The diagrams shown in the white paper, though helpful, do not necessarily apply to all field conditions.
109
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 14 Comment
Specific questions include: is it up to the Transmission Operator to determine the “active transmission line
right-of-way”, particularly in cases where the ROW may not be maintained to the legal boundary? Example 4
in the definition of “active transmission line right-of-way” (pg. 5) uses the words “deactivated” and “unavailable
for service”. The terms active, deactivated, and unavailable for service should be clearly defined as they can
easily be interpreted different ways between different entities, and for different situations.
Northeast Power Coordinating
Council--RSC
Suggest an illustration of R7 be added. R7 text states “... due to the blowing together of vegetation and a
conductor within an Active Transmission Line ROW”. These words could suggest that sustained outages
from vegetation (branches) extending within the active ROW, but originating from trees located outside the
active ROW, might not be considered a preventable outage. An illustration in the reference paper would
provide clarity.Confusion still exists regarding the determination of the “active transmission line right-of-way”.
The diagrams shown in the white paper, though helpful, do not necessarily apply to all field conditions.
Specific questions include: is it up to the Transmission Operator to determine the “active transmission line
right-of-way”, particularly in cases where the ROW may not be maintained to the legal boundary? Example 4
in the definition of “active transmission line right-of-way” (pg. 5) uses the words “deactivated” and “unavailable
for service”. The terms active, deactivated, and unavailable for service should be clearly defined as they can
easily be interpreted different ways between different entities, and for different situations.
Vegetation Management Team
The Active ROW definition should be expanded to exclude areas of the ROW that are currently being used for
other transmission facilities, such as 110 kV towers etc. As written, it only excludes unused portions of the
ROW, abandon lines and the side of structures that have no facilities. Perhaps use “A strip of land that is
occupied by applicable transmission facilities.The last paragraph on page 8 of the Technical Reference
indicates that the Standard is not applicable to “...line sections inside the electric station or other boundary...”
This is somewhat ambiguous on who has the responsibility of assure compliance “inside the fence or other
boundary”.
Salt River Project
The Active ROW should be defined in more detail.
Public Service Co. of New
Mexico
The Planning Coordinator is not defined. Please clarify who this person(s) are.Additionally there needs to be
more specific language regarding the importance of this reliability standard specifically for dealings with
Federal, State or Tribal authorities.
American Electric Power
The SDT has done a great job developing this version of the standards, responding to comments, and
enhancing the Technical Reference document. We have no other questions at this time.
Utility Arborist Association
The UAA commends the standards drafting team for covering ANSI A300, Part 7 and the International Society
110
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 14 Comment
of Arboriculture’s integrated vegetation management best management practices in the technical reference.
The UAA considers the treatment to be a reasonable representation of best practices to use in complying with
FAC-003-02. We remain convinced that best management practice implementation is the most effective way
to improve reliability. The A300 section in the technical reference is an important contribution in that regard.
We reiterate our view that ANSI A300 be included in the requirements rather than as a footnote in the
standard.
MRO NERC Standards Review
Subcommittee
To avoid confusion, the diagrams of the ROWs in the White Paper should not have tree-like objects in the
Active Transmission Right of Way. If any vegetation is to be shown in those areas, the vegetation should be
shrubbery.
Northern Indiana Public Service
Company
When discussing R4 (Pg. 30), the document brings up the concept of identifying encroachments of the MVCD
during inspections but doesn't discuss indicators present in vegetation that has experienced flashover. For
example, at the time vegetation is inspected, offending vegetation may be well outside the minumum distance
in Table 1, but still exhibit evidence of sparkover such is wilted leaves, scorched limbs, etc. It would be
helpful for the document to discuss these and other indicators of encroachment into the MVCD in greater
detail.
111
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
15.
As stated in the background information above, in response to industry comments, the applicability section
is revised to replace Reliability Coordinator with Planning Coordinator. Do you agree with these changes? If
not, please explain and propose an alternative.
Organization
Yes or No
Question 15 Comment
Entegra Power Group LLC
No comment
Tampa Electric Company
We do not agree or disagree on this Requirement.
Ameren
Agree
American Electric Power
Agree
American Transmission
Company
Agree
Arizona Public Service
Agree
Associated Electric Cooperative,
Inc.
Agree
BC Transmission Corporation
Agree
Bonneville Power Administration
Agree
CenterPoint Energy
Agree
Central Maine Power an Energy
East Company
Agree
Consolidated Edison Company of
New York Inc.
Agree
112
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Duke Energy
Agree
Entergy Services, Inc
Agree
FirstEnergy Corp
Agree
Georgia Transmission
Corporation
Agree
Hydro One Networks inc.
Agree
Hydro-Quebec TransEnergie
(HQT)
Agree
Idaho Power Company
Agree
Independent Electricity System
Operator
Agree
ISO New England Inc.
Agree
Lee County Electric Cooperative
Agree
Manitoba Hydro
Agree
National Grid
Agree
Nebraska Public Power District
Agree
NERC Standards Review
Subcommittee
Agree
New Brunswick Power
Transmission
Agree
Question 15 Comment
113
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
North Carolina Electric
Membership Corporation
Agree
Northeast Power Coordinating
Council--RSC
Agree
Northeast Utilities
Agree
Northern Indiana Public Service
Company
Agree
Oncor Electric Delivery
Agree
Orange and Rockland Utilities,
Inc.
Agree
Pacific Gas and Electric Co.
Agree
PacifiCorp
Agree
Progress Energy Carolinas, Inc.
Agree
Puget Sound Energy
Agree
ReliabilityFirst Corporation
Agree
Salt River Project
Agree
SCE&G
Agree
SERC Vegetation Managment
Sub-committee (VMS)
Agree
Southern California Edison
Agree
Question 15 Comment
114
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 15 Comment
Company
Southern Company
Agree
Superintendent Transmission
Maintenance
Agree
Tenessee Valley Authority
Agree
Tennessee Valley Authority
Agree
Transmission Owner
Agree
Tucson Electric Power Company
Agree
TVA
Agree
TVA
Agree
TVA
Agree
WECC RC
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Xcel Energy
Agree
JEA
Agree
I agree this makes sense. Unfortunately, at least in FRCC, every TO has TWO Planning Coordinators so
unless the RE or NERC straightens that situation out, there will be confusion as to which has the authority.
Disagree
: E.ON U.S. recommends that the RC remain the responsible entity instead of the Planning Coordinator as
RCs are best situated to determine a line’s criticality to the region.
E.ON U.S.
115
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 15 Comment
Public Service Co. of New
Mexico
Disagree
As stated in several earlier questions, there isn't a definition of who this person(s) are and what their duties
are? Should be clearly defined in both the standard and in the white paper.
Pepco Holdings, Inc - Affiliates
(PHI)
Disagree
PHI concurs with replacing the Reliability Coordinator with the Planning Coordinator. However, PHI has
concerns with the Applicability section. 4.2.1 has (-applicable lines-) immediately following the term transmission lines-, indicating that all Transmission Lines are applicable lines. We are certain that is not what
the SDT meant. Additionally, Transmission Line is a NERC defined term and includes all Facilities 69kV 765kV. We assume what is meant is to limit the applicability to BES (BPS) Facilities 200kV and above plus
Transmission Lines operated below 200kV designated by the Planning Coordinator.PHI also encourages
further consideration for lines from generation facilities to network substations. Some Generator Owners
have lines greater than a mile in length. The SDT should consider whether to extend applicability of the
standard for Generator Owners that own lines that meeting certain predefined criteria, or other approaches
that would clarify the treatment of lines owned by Generator Owners on the generator side of a network
substation.
Vegetation Management Team
Disagree
Suggest adding BES to the first bullet under A.4.-Facilities: to clarify that FAC-003-2 only applies to the BES.
That radial lines supplying distribution substations, etc. aren’t part of the standard. The bullet could read:
“Bulk Electric System Transmission lines (“applicable lines”) operated at 200kV or higher, and transmission
lines operated below 200kV designated by the Planning Coordinator as being subject to this standard
including but not limited to those that cross lands owned by federal1, state, provincial, public, private, or tribal
entities.”
US Bureau of Reclamation
Disagree
The role should be examined as part of the functional model description. To modify the role in the inidividual
standards may result in holes in the fuctional model roles.
Platte River Power Authority
Vegetation Management Group
Disagree
We are still finding confusion within the industry about the function of the Planning Coordinator and
registration for Planning Coordinator (a.k.a. the Planning Authority). We think a strong possibility exists that
there may be Transmission Owners who don’t have a Planning Coordinator or assume that their Balancing
Authority or a other registered entity is providing this function for them when in reality they are not. This
confusion could present a gap in reliability. At one time there was discussion of removing this function from
the Functional Model all together and replacing Planning Coordinator with Transmission Planner in all
applicable standards. Although the Planning Coordinator and the Transmission Planner are the same within
our organization we believe it will provide clarity to the standard to make it applicable to the Transmission
Planner opposed to the Planning Coordinator. The coordination of the Transmission Planner would be
between the Transmission Owners and neighboring transmission planners in R10.
116
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
ISO/RTO Council
Yes or No
Question 15 Comment
Agree
If this standard retains the need to identify sub 200KV facilities, then the change of this responsibility from the
Reliability Coordinator to the Planning Coordinator is appropriate.
117
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
16.
As stated in the background information above, in response to industry comments, changes were made to
the definitions. Do you agree with these changes? If not, please explain and propose an alternative.
Organization
Yes or No
Entegra Power Group LLC
Question 16 Comment
No comment
American Electric Power
Agree
American Transmission
Company
Agree
Arizona Public Service
Agree
Associated Electric Cooperative,
Inc.
Agree
BC Transmission Corporation
Agree
Central Maine Power an Energy
East Company
Agree
Consolidated Edison Company of
New York Inc.
Agree
Duke Energy
Agree
E.ON U.S.
Agree
Georgia Transmission
Corporation
Agree
Hydro One Networks inc.
Agree
118
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Hydro-Quebec TransEnergie
(HQT)
Agree
Idaho Power Company
Agree
Independent Electricity System
Operator
Agree
ISO New England Inc.
Agree
JEA
Agree
Lee County Electric Cooperative
Agree
Nebraska Public Power District
Agree
New Brunswick Power
Transmission
Agree
North Carolina Electric
Membership Corporation
Agree
Northeast Power Coordinating
Council--RSC
Agree
Northeast Utilities
Agree
Northern Indiana Public Service
Company
Agree
Oncor Electric Delivery
Agree
Orange and Rockland Utilities,
Inc.
Agree
Question 16 Comment
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Pacific Gas and Electric Co.
Agree
PacifiCorp
Agree
Progress Energy Carolinas, Inc.
Agree
Puget Sound Energy
Agree
ReliabilityFirst Corporation
Agree
SCE&G
Agree
SERC Vegetation Managment
Sub-committee (VMS)
Agree
Southern Company
Agree
Superintendent Transmission
Maintenance
Agree
Tampa Electric Company
Agree
Tenessee Valley Authority
Agree
Tennessee Valley Authority
Agree
Transmission Owner
Agree
TVA
Agree
TVA
Agree
TVA
Agree
Question 16 Comment
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Organization
Yes or No
Question 16 Comment
WECC RC
Agree
Western Area Power
Administration, Rocky Mountain
Region
Agree
Bonneville Power Administration
Agree
“Response Control Center” is not defined in the NERC Glossary of Terms, so it either needs to be added to
the Glossary and/or defined within the Standard to be clear regarding its definition.
Edison Electric Institute
Agree
EEI also recommends that the SDT reconsider use of the term ‘applicable lines’ in the revised draft Standard
or clarify the definition. The way the Standard is written with the term “applicable lines” in parentheses and
quotes after the words “Transmission lines” in section 4, the term “applicable lines” would under normal
interpretation rules be interpreted to mean “Transmission lines.” This surely is not the intent of the SDT. If
“applicable lines” is meant to be the facilities defined in Section 4, then EEI recommends modifying Section 4
“Facilities” to read: “Facilities (‘applicable lines’)” if that is the intent to the term ‘applicable lines.’ If not, then
the term needs a more specific definition.While applicability of the Standard is already described, use of this
term in specific requirements could suggest that there may be lines that are otherwise subject to requirements
of the Standard and only ‘applicable lines’ are addressed in some requirements. For example, the sentence
‘Sustained Outages of applicable lines that result from natural disaster,’ could be interpreted to refer to lines
affected by a natural disaster, or some other subset of all lines subject to the Standard. EEI recommends that
the SDT consider revising language of this type to remove the phrase ‘applicable lines.’ In the example cited,
the sentence would become a clause reading: ‘Sustained Outages that result from natural disasters.’
National Grid
Agree
National Grid agrees with the new definition for active transmission right-of-way, though it may need further
clarification in the Technical reference document. We have concerns that TO’s might consider portions of the
original ROW width as not active. For example: Original width of a ROW was 100 feet, however over many
decades the maintained width has been reduced to 80 feet. Might the new definition provide incentive for the
TO to now define the active ROW as 80 feet? The proposed removal of the requirement to report Category 3
sustained outages provides additional incentive for the TO to adopt this approach.
Southern California Edison
Company
Agree
SCE generally agrees with the definitions, but suggests that the "Vegetation Inspection" definition be revised
to read: Vegetation Inspection - The systematic examination of vegetation conditions within an Active
Transmission Line Right of Way. A Vegetation Inspection may be combined with other transmission facility
inspections.
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 16 Comment
Agree
We agree with the definitions, but want to point out that this is the only standard that would utilize the term
Vegetation Inspection, and the current definition is not used anywhere in the currently approved set of NERC
standards. Should this definition only be specific to this standard and not a NERC glossary term? Regardless,
we do not have an issue either way.
Xcel Energy
Disagree
(a) The definition of Active Transmission Line Right of Way is confusing. There may be other portions of the
Right of Way that were not specifically acquired for other facilities (or being used for other facilities), but are
not used and are not needed. As drafted, this definition would ignore this fact. Further, by limiting the
definition in this manner, it ignores the fact that it may take different portions of the right of way to operate the
line (due to the characteristics of the line, size, location, etc.) and address vegetation concerns. It would be
more accurate if the “intended for other facilities” portion of the definition were deleted. This would allow the
flexibility to address the concerns noted above. Thus it would read: "A strip of land that is occupied by active
transmission facilities. This corridor does not include the inactive or unused part of the right of way."(b) The
definition of “Vegetation Inspection” should be rewritten to change the documentation requirement for any
vegetation which “may pose a threat.” As a practical mater, any vegetation “may” pose a threat. The
definition would be better phrased to read: "The systematic examination of vegetation conditions on an Active
Transmission Line Right of Way. This inspection may be combined with a general line inspection. The
inspection includes the documentation of any vegetation that poses an unacceptable risk to reliability prior to
the next planned inspection or maintenance work."
Platte River Power Authority
Vegetation Management Group
Disagree
“intended for other facilities” should be struck from the definition of Active Transmission Line Right of Way as
it may include deactivated transmission lines, buffer zones or other ROW never intended for other facilities
but wider that necessary.
Tucson Electric Power Company
Disagree
1- In the definition of the term “Active Transmission Right of Way” the final sentence should read “This
corridor does not include the inactive or unused part of the Right of Way.” Delete intended for other facilities.
2- We propose the following modification to the Vegetation Inspection definition the sentence; “The inspection
includes the documentation of any vegetation that may pose a threat unacceptable risk to reliability prior to
the next planned inspection or maintenance work”. This would make the language consistent with other
language found in M11 of this document.
MRO NERC Standards Review
Subcommittee
Disagree
A. The definition of Active Transmission Line Right of Way is confusing. There may be other portions of the
Right of Way that were not specifically acquired for other facilities (or being used for other facilities), but are
not used and are not needed. It would be more accurate if the text “intended for other facilities” was deleted.
Thus it would read: “A strip of land that is occupied by active transmission facilities. This corridor does not
include the inactive or unused part of the right of way.”B. The definition of “Vegetation Inspection” should be
FirstEnergy Corp
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 16 Comment
rewritten to change the documentation requirement for any vegetation which “may pose a threat.” As a
practical matter, any vegetation “may” pose a threat. The definition would be better phrased to read: “The
systematic examination of vegetation conditions on an Active Transmission Line Right of Way. This
inspection may be combined with a general line inspection. The inspection includes the documentation of any
vegetation that poses an unacceptable risk to reliability prior to the next planned inspection or maintenance
work.”
Pepco Holdings, Inc - Affiliates
(PHI)
Disagree
Active Transmission Line Right of Way should include the buffer needed to maintain clearances.
needs to be sufficient to maintain clearances. This should be identified by the TO.
Width
CenterPoint Energy
Disagree
Active Transmission Line Right of WayCenterPoint Energy disagrees with the inclusion and definition of
“Active Transmission Line Right of Way”. “Active Transmission Line Right of Way” is not defined as to its
geometric limits within the Standard. The SDT has indicated in its response to 1st Draft Comments from
CenterPoint Energy that the “...Transmission Owner is responsible for defining the Active Transmission Line
Right of Way.” However, that defining clause is not included in the current definition. CenterPoint Energy
recommends one of the following options in order of preference:1) Recommend deleting the term “Active
Transmission Line Right of Way” from the standard and revising the Requirements, Measures, and
Compliance line items accordingly. R1.6 already requires that maintenance strategies ensure that the MVCD
is never violated and considers “the sag and sway of the conductor throughout is operating range and under
rated conditions”. This requirement by itself defines the airspace that must be maintained to prevent a
Sustained Outage for grow-ins and blow-ins. R7 would be revised to read “Each Transmission Owner shall
prevent Sustained Outages of applicable lines due to the blowing together of vegetation and a conductor
operating within its designed sway under rated conditions with the following exceptions...”.R8 would be
revised to read, “Each Transmission Owner shall prevent Sustained Outages of applicable lines due to
vegetation falling into a conductor where the Transmission Owner had the legal right or prior permission to
remove the vegetation.”2) To parallel the requirement of R1.6, revise the definition of “Active Transmission
Line Right of Way” to, “A strip of land that is occupied by applicable lines considering the sag and sway of the
conductor throughout its operating range under rated conditions plus the Minimum Vegetation Clearance
Distance (MVCD) from Table 1, where applicable lines are defined as transmission lines operating in real time
at 200kV or higher and transmission lines operating in real time below 200kV designated by the Planning
Coordinator as being subject to this standard, including but not limited to those lines that cross lands owned
by federal, state, provincial, public, private, or tribal entities.”3) If the SDT and NERC intend for the Active
Transmission Line Right of Way limits to be determined based on the Transmission Owner’s interpretation,
CenterPoint Energy suggests an alternate definition as follows, “Active Transmission Line Right of Way - A
strip of land, the dimensions of which are determined by the Transmission Owner, occupied by applicable
lines, where applicable lines are defined as transmission lines operating in real time at 200kV or higher and
transmission lines operating in real time below 200kV designated by the Planning Coordinator as being
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 16 Comment
subject to this standard, including but not limited to those lines that cross lands owned by federal, state,
provincial, public, private, or tribal entities.”By making this suggested change to the definition of “Active
Transmission Line Right of Way”, most of the ambiguity is removed. It is now clear that the standard does not
apply to those portions of rights-of-way in which there are no applicable lines, such as 69kV and 138kV lines
that the Planning Coordinator has not determined to be subject to the standard. CenterPoint Energy has
added the phrase “operating in real time” to make it clear that the standard also does not apply to a right-ofway in which there is a non-operating line which would normally be subject to the standard if it was operating.
By adding MVCD and “sag and sway” requirements to the definition of “Active Transmission Line Right of
Way”, the standard has defined the physical limits necessary to determine if there has been a violation from
trees adjacent to the applicable lines. The alternate definition without the MVCD citation clarifies who is to
determine the physical limits of the Active Transmission Line Right of Way since none are provided in the
definition itself. However, adding such a reference would surmount to a “fill-in-the-blank” requirement which
the SDT has found undesirable. Vegetation InspectionCenterPoint Energy disagrees with the definition of
“Vegetation Inspection” since it includes the term “Active Transmission Line Right of Way” which is
ambiguously defined and not relevant to defining the type of inspection performed. CenterPoint Energy
recommends the following definition, “Vegetation Inspection - The systematic examination of vegetation
conditions under and adjacent to a transmission line considering the current location of the conductor and
other possible locations of the conductor due to sag and sway for rated conditions. This inspection may be
combined with a general line inspection. The inspection includes the documentation of any vegetation that
may pose a threat to reliability prior to the next planned inspection or maintenance work.”
Salt River Project
Disagree
For the definition of “Vegetation Inspection” recommend the following changes:- In the 3rd sentence, the use
of “threat”, change to “unacceptable risk”- In the 3rd sentence, remove the last statement “...consider the
current location of the conductor and other possible locations of the conductor due to sag and sway for rated
conditions”. The definition is too lengthy and it does not appear this additional language is necessary.
Vegetation Management Team
Disagree
MVCZ should be included in the Definitions of Terms Used in Standard.
Public Service Co. of New
Mexico
Disagree
PNM recommends ammending the definition of "Active Transmission Line Right of Way" as follows: A strip of
land that is occupied by active transmission facilities. This corridor does not include the inactive or unused
part of the Right of Way.PNM recommends ammending "Vegetation Inspection" to include acceptable types of
inspection methods i.e. ground patrols, aerial patrols, etc.
Entergy Services, Inc
Disagree
See additional Entergy comments below.
Manitoba Hydro
Disagree
the definition of "active ROW" should include the concept of meeting safe/reliable operation design criteria
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 16 Comment
US Bureau of Reclamation
Disagree
The definitions should not include performance measures or suggestions such as "This inspection may be
combined with a general lineinspection." The definition is also phrased in terms of a requirement by using
"The inspection includes the documentation of any vegetation that may pose a threatto reliability prior to the
next planned inspection or maintenance work, considering the current location of the conductor and other
possible locations of the conductor due to sag and sway for rated conditions." Both of these quoted phrases
should be removed to the requirements section.
Ameren
Disagree
Vegetation Inspection:Need to insert that these inspections are based on inspectors expectation of normal
growth and environmental factors or note that the inspector can not determine all hazards from vegetation
that may occur from natural disasters or human or animal activity when inspecting. This would be a
complimentary statement to the exceptions for actual events that occur in these requirements.
ISO/RTO Council
The SRC has no comment on this question.
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
17.
When compared to Version 1, does this proposed Version 2 of the standard either maintain or improve
overall electric reliability? Please provide a technical basis for your response?
Organization
Does or Does Not
Question 17 Comment
Entegra Power Group LLC
No comment
Southern California Edison
Company
Uncertain. At this point in time, SCE does not believe that it is possible to predict whether Version 2
will improve overall electric reliability when compared with Version 1 because NERC has not yet
demonstrated with documentation that the implementation of Version 1 of FAC-003 has improved
electric reliability.
Ameren
V2 Does maintain or
improve overall
reliability
CenterPoint Energy
V2 Does maintain or
improve overall
reliability
Central Maine Power an Energy
East Company
V2 Does maintain or
improve overall
reliability
Duke Energy
V2 Does maintain or
improve overall
reliability
Entergy Services, Inc
V2 Does maintain or
improve overall
reliability
FirstEnergy Corp
V2 Does maintain or
improve overall
reliability
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Does or Does Not
Georgia Transmission
Corporation
V2 Does maintain or
improve overall
reliability
Idaho Power Company
V2 Does maintain or
improve overall
reliability
Lee County Electric Cooperative
V2 Does maintain or
improve overall
reliability
Manitoba Hydro
V2 Does maintain or
improve overall
reliability
Nebraska Public Power District
V2 Does maintain or
improve overall
reliability
Northeast Utilities
V2 Does maintain or
improve overall
reliability
Oncor Electric Delivery
V2 Does maintain or
improve overall
reliability
Pacific Gas and Electric Co.
V2 Does maintain or
improve overall
reliability
Pepco Holdings, Inc - Affiliates
(PHI)
V2 Does maintain or
improve overall
reliability
Question 17 Comment
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Does or Does Not
Platte River Power Authority
Vegetation Management Group
V2 Does maintain or
improve overall
reliability
Progress Energy Carolinas, Inc.
V2 Does maintain or
improve overall
reliability
ReliabilityFirst Corporation
V2 Does maintain or
improve overall
reliability
Tenessee Valley Authority
V2 Does maintain or
improve overall
reliability
Transmission Owner
V2 Does maintain or
improve overall
reliability
Tucson Electric Power Company
V2 Does maintain or
improve overall
reliability
TVA
V2 Does maintain or
improve overall
reliability
TVA
V2 Does maintain or
improve overall
reliability
TVA
V2 Does maintain or
improve overall
reliability
Question 17 Comment
128
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Does or Does Not
Question 17 Comment
Vegetation Management Team
V2 Does maintain or
improve overall
reliability
WECC RC
V2 Does maintain or
improve overall
reliability
Xcel Energy
V2 Does maintain or
improve overall
reliability
SCE&G
V2 Does maintain or
improve overall
reliability
As stated, SCE&G believes that this standard version is superior to the previous. Improvement
areas include: o Clarification is made that sustained outages are a violation of the requirements. o
Separation of imminent threat, vegetation inspections and the annual work-plan have been made. o
Minimum clearance distances are realistic and eliminates references outside the standard (via
Appendix 1). The fill-in-the-blank aspects are eliminated. o Established a clear process for
identifying sub 200kV circuits applicable to the revised standard. o Clarification of the active ROW o
This revision eliminates non enhancing aspects of the previous version (e.g. personnel
qualifications, category 3 reporting, clearance 1, etc.) o Applies to applicable transmission facilities
regardless of location o Focus is made to actual and observable conditions rather than hypothetical
conditions. o Addresses the elements of FERC order 693
SERC Vegetation Managment
Sub-committee (VMS)
V2 Does maintain or
improve overall
reliability
As stated, the SERC VMS believes that this standard version is superior to the previous. These
improvements include:Clarification is made that sustained outages are a violation of the
requirements. Separation of imminent threat, vegetation inspections and the annual work-plan have
been made. Minimum clearance distances are realistic and eliminates references outside the
standard (via Appendix 1). The fill-in-the-blank aspects are eliminated. It establishes a clear
process for identifying sub 200kV circuits applicable to the revised standard. Clarification of the
active ROW is made.This revision eliminates non enhancing aspects of the previous version (e.g.
personnel qualifications, category 3 reporting, clearance 1, etc.)Applies to applicable transmission
facilities regardless of location.Focus is made to actual and observable conditions rather than
hypothetical conditions.It addresses the elements of FERC order 693.
American Transmission
V2 Does maintain or
improve overall
ATC believes that the standard provides for improved reliability, however, needs to consider ATC’s
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Does or Does Not
Question 17 Comment
Company
reliability
comments to earlier questions.
Bonneville Power Administration
V2 Does maintain or
improve overall
reliability
BPA believes V2 maintains overall reliability. Although there are many differences between the two
versions, the overall differences between version 1 and version 2 appear to have the same impact
on reliability.
Consolidated Edison Company of
New York Inc.
V2 Does maintain or
improve overall
reliability
CECONY believes that the Standard does help maintain or improve overall reliability since the
requirements for a TVMP are clearly addressed including inspection cycles, responses to imminent
threats, reduced ambiguity, and documentation requirements. Also, the fact that real time
encroachments are considered violations will make utilities more likely to use LIDAR and other
technology without the fear of discovery of an encroachment violation of a condition that has not
occurred. This will result in earlier detection of potential problems and will increase reliability. The
Transmission Owner should be solely responsible for determining the abilities and training needs of
their employees and ensure that capable individuals perform their vegetation management
functions.
E.ON U.S.
V2 Does maintain or
improve overall
reliability
E.ON U.S. believes the proposed revision provides much greater clarity to the requirements than
what is currently in place.
Edison Electric Institute
V2 Does maintain or
improve overall
reliability
EEI applauds the commitment and effort of the SDT and appreciates the revised draft FAC-003
Standard as a complete response to the key issues raised by FERC in Order No. 693:o NERC has
addressed applicability issues, balancing the need for covering facilities that impact reliability
against unreasonably increasing the burden of transmission owners.o NERC has addressed
minimum clearance issues, proposing requirements that will avoid vegetation-related sustained
outages for lines on both federal and non-federal lands.o NERC has proposed changes to
applicability to better recognize differing needs for active and inactive rights-of-way. o NERC has
addressed inspection cycles to ensure that inspections are conducted at reasonable
intervals.Overall, EEI believes that the Standard can provide adequate requirements for company
vegetation management programs for maintaining clearances on rights-of-way on the Bulk Power
System. Compliance with these requirements would, if established as mandatory by FERC,
support reliable operation of the Bulk Power System by preventing Sustained Outages caused by
vegetation.The electric industry broadly recognizes that several Reliability Standards contain
ambiguous terms and requirements, which have resulted in significant challenges for companies in
seeking to determine appropriate compliance actions, and for compliance enforcement activities
within NERC. EEI strongly supports the general process for improving the Standards development
process and content of the Standards as a long-term goal for NERC. In the context of revising
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Does or Does Not
Question 17 Comment
FAC-003, to the maximum extent practicable EEI encourages the SDT to use defined terms and
explicit references. EEI recognizes also that the need to reduce ambiguity must be balanced
against the need to adapt flexible requirements and measures that recognize the widely varying
vegetation circumstances on the Bulk Power System. This is especially challenging for developing
enforceable requirements to address vegetation encroachment issues on transmission rights-ofway.
Tennessee Valley Authority
V2 Does maintain or
improve overall
reliability
I believe it improves reliability.
Associated Electric Cooperative,
Inc.
V2 Does maintain or
improve overall
reliability
It is Associated Electric Cooperative Inc’s opinion that V2 maintains overall reliability as compared
to V1. o Developing separate requirements for documentation and implementation of the Imminent
Threat Process, Vegetation Inspections, and the Annual Work Plan adds to the clarity of the
standard.
North Carolina Electric
Membership Corporation
V2 Does maintain or
improve overall
reliability
NCEMC does believe that this standard version is an improvement to the previous. Improvement
areas include:o Clarification is made that sustained outages are a violation of the requirements. o
Separation of imminent threat, vegetation inspections and the annual work-plan have been made. o
Minimum clearance distances are realistic and eliminates references outside the standard (via
Appendix 1). The fill-in-the-blank aspects are eliminated. o Established a clear process for
identifying sub 200kV circuits applicable to the revised standard. o Clarification of the active ROW.o
This revision eliminates non enhancing aspects of the previous version (e.g. personnel
qualifications, category 3 reporting, clearance 1, etc.)o Applies to applicable transmission facilities
regardless of locationo Focus is made to actual and observable conditions rather than hypothetical
conditions.o Addresses the elements of FERC order 693
Southern Company
V2 Does maintain or
improve overall
reliability
The new standard differentiates between IROL and non IROL facilities. The use of the Planning
Coordinator in lieu of the Reliability Coordinator provides a long term approach to improving
reliability. The definition of active ROW helps differentiate between important ROW and less
important ROW.
Western Area Power
Administration, Rocky Mountain
Region
V2 Does maintain or
improve overall
reliability
The proposed Version 2 of the Standard improves overall system reliability by: 1) Clarifying
previously ambiguous requirements of Version 1 regarding what is or is not a violation of the
Standard. For example, previously unclear expectations associated with Version 1 reguirements
R1.2.2. and R3 are now clearly addressed as requirements in Version 2 requirements R4, R5, R6,
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Does or Does Not
Question 17 Comment
R7 and R8. 2) Providing real time, observable and measurable thresholds for compliance in
Version 2 verses the many subjective and "interpreted" thresholds for compliance which were
contained in Version 1 requirements. 3) Requiring a series of pro-active, mandatory and
graduated actions by the Transmission Owner for preventing vegetation related outages that could
lead to cascading events. These "layers of protection" include the formal identification of facilities
subject to the standard, the establishment of a credible TVMP and execution of annual plans,
mandatory field inspections, prevention of encroachments into Minimum Vegetation Clearance
Distances, mitigation of imminent threats, prevention of outages due to fall ins, prevention of
outages due to blow ins, and the prevention of outages due to grow ins.
JEA
V2 Does maintain or
improve overall
reliability
The standard seems to maintain reliability and add clarity.
American Electric Power
V2 Does maintain or
improve overall
reliability
This standard is a significant improvement in its specificity of the documentation and reporting
responsibilities necessary to be fully compliant.
MRO NERC Standards Review
Subcommittee
V2 Does maintain or
improve overall
reliability
Using the Gallet equation puts the tree trimmers closer to the lines than the OSHA standards will
allow due to the fact that OSHA recognizes the standard IEEE 516-2003 clearance distances. We
recommend revising Table 1 taking into account the IEEE standard.
New Brunswick Power
Transmission
V2 Does maintain or
improve overall
reliability
V2 is a much improved version of the standard in that it provides clarify on a number of issues; the
technical reference is a welcome addition and provides critical information for meeting proposed
standard.
Superintendent Transmission
Maintenance
V2 Does maintain or
improve overall
reliability
V2 maintains and improves overall system reliability with real-time, observable, and measurable
standards that include a thorough approach (inspections, reporting, MVCDs, etc) to minimizing
cascading outages caused by vegetation.
Tampa Electric Company
V2 Does maintain or
improve overall
reliability
V2 represents the growth of the standard via much improved clarification; I have to think that this
will result in a much better overall industry understanding of the standard and its requirements. This
should result in improved Industry performance and thus will maintain or improve overall reliability.
MVCD is improved via Gallet formula, definitions are new & improved, VRF & VSL’s clarify risk and
severity.
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Does or Does Not
Question 17 Comment
US Bureau of Reclamation
V2 Does not maintain
or improve overall
reliability
It is hard to imagine any vegetation encroachment that would not be exempted by this standard.
Overall the exemptions appear to be inconsistent with the language in the respective requirements.
National Grid
V2 Does not maintain
or improve overall
reliability
National Grid disagrees that V2 will improve reliability for 3 reasons: 1) National Grid believes
eliminating Clearance 1 will be detrimental to reliability. The determination of Clearance 1 is an
important exercise for the TO to better understand the dynamics of conductor movement and
vegetative growth. This required analysis should lead to development of a more informed
vegetation management program. Clearance 1 also gives the TO leverage with landowners and
local regulators to achieve the necessary operational clearances. If the only required clearance is
the R4 Minimum Vegetation Clearance Distance (MVCD), landowners and local regulators will push
the utility to maintain a clearance close to the MVCD. 2) National Grid believes eliminating the
reporting of Category 3 sustained outages will lead to less effort by the TO’s to mitigate danger tree
exposure where the TO’s property rights allow. This will lead to diminished reliability. 3) Removing
the qualifications requirement from the standard will likely lead to TO’s employing less qualified
employees and contractors. The Utility Vegetation Management (UVM) industry, through
development of ANSI Standards and industry Best Practices, and the International Society of
Arboriculture certification programs, has worked to raise the level of professionalism in the UVM
industry. National Grid believes that raising professional standards leads to better quality work and
improved reliability.
Orange and Rockland Utilities,
Inc.
V2 Does not maintain
or improve overall
reliability
ORU disagrees that V2 will improve reliability for 3 reasons: 1) ORU believes eliminating Clearance
1 will be detrimental to reliability. The determination of Clearance 1 is an important exercise for the
TO to better understand the dynamics of conductor movement and vegetative growth. This required
analysis should lead to development of a more informed vegetation management program.
Clearance 1 also gives the TO leverage with landowners and local regulators to achieve the
necessary operational clearances. If the only required clearance is the R4 Minimum Vegetation
Clearance Distance (MCVD), landowners and local regulators will push the utility to maintain a
clearance close to the MVCD. 2) ORU believe eliminating the reporting of Category 3 sustained
outages will lead to less effort by the TO’s to mitigate danger tree exposure where the TO’s
property rights allow. This will lead to diminished reliability. 3) Removing the qualifications
requirement from the standard will likely lead to TO’s employing less qualified employees and
contractors. The Utility Vegetation Management (UVM) industry, through development of ANSI
Standards, and the International Society of Arboriculture certification programs have worked to
raise the level of professionalism in the UVM industry. We believe that raising professional
standards leads to better quality work and improved reliability. ORU believes that the Standard
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Does or Does Not
Question 17 Comment
does help maintain or improve overall reliability since the requirements for a TVMP are clearly
addressed including inspection cycles, responses to imminent threats, and documentation
requirements. Also, the fact that real time encroachments are considered violations will make
utilities more likely to use LIDAR and other technology without the fear of discovery of an
encroachment violation of a condition that has not occurred. This will result in earlier detection of
potential problems and will increase reliability. Even though the Clearance 1 value is being
eliminated from the Standard, operating specifications will still govern the way a utility handles its
clearances as is currently done. We do agree, however, that landowners and local regulators may
want utilities to reduce operational clearance levels based on the MVCD listed in the Standard but
the utility must properly communicate the reasoning behind achieving greater clearances as per
their TVMP. We do not believe that eliminating the reporting of Category 3 sustained outages will
lead to less effort to mitigate danger tree exposure since all transmission outages are sensitive to a
Transmission Owner and must be addressed appropriately at multiple levels within the company as
well as with other regulatory agencies in some cases. Removing the qualifications requirement may
initially lead to Transmission Owners employing less qualified employees and contractors but there
needs to be some level of flexibility that will allow for a larger candidate pool or temporary support
since individuals with specialized training are not always readily available. The Transmission Owner
should be solely responsible for determining the abilities and training needs of their employees and
ensure that capable individuals perform their vegetation management functions.
PacifiCorp
V2 Does not maintain
or improve overall
reliability
PacifiCorp disagrees that FAC-003-02 will improve reliability because the standard lacks a
requirement to adhere to best management practices, it does not mandate that programs be
managed by qualified individuals, and it has no clearance 1.
Arizona Public Service
V2 Does not maintain
or improve overall
reliability
Removing the following sections from FAC-003 version 1 does not improve or maintain reliability;
R1.2.1, R1.3. APS has responded in the section above.
Puget Sound Energy
V2 Does not maintain
or improve overall
reliability
The elimination of Clearance 1 from the current standard, and the close distance to the wire in the
proposed Table 1 will create more difficulty with agencies and reluctant landowners. A closer
distance to the MVCD will be pushed by some. This revised standard gives Transmission Owner
no leverage for maintaining Utiltiy Vegetation management Best Management Practices (BMP). If
BMP’s were utilitzed consistently, there would be minimum outages.
Salt River Project
V2 Does not maintain
or improve overall
The proposed MVCD values are less than SRP has defined in the current standard for Clearance 2
values and would not provide adequate clearance. Also see comments stated in question #4
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Utility Arborist Association
Does or Does Not
Question 17 Comment
reliability
regarding concern regarding the method used to determine the MVCD values.
V2 Does not maintain
or improve overall
reliability
The Utility Arborist Association thinks version 2 does not improve reliability over version 1 for two
reasons. It does not have a qualification requirement, and it does not contain a requirement for
utilities to conform to ANSI A300.First, the UAA considers removal of the qualification requirement
from the standard to detract from reliability compared to FAC-003-01. Appropriate qualifications are
every bit as critical for vegetation management as they are for other areas of expertise necessary to
operate the electric grid. For example, no utility would assign engineering responsibilities to
anyone without engineering training and experience, as the electric grid would quickly fail. Yet, it is
common for utilities to assign vegetation management oversight to employees without the
appropriate knowledge and background to succeed. Consider that none of the three North
American blackouts in the past fifteen years occurred solely due to engineering deficiencies.
Rather, they were initiated by tree contacts. More effective vegetation management programs
would have prevented every one of them. Clearly vegetation management expertise is critical, as
the consequences of vegetation management deficiencies have resulted in three catastrophic grid
failures. It cannot be left to people with improper or inadequate competencies. The standard should
say as much.The Utility Arborist Association recognizes that the qualification requirement has been
removed due to industry reaction to unreasonable and overbearing demands for proof of
qualifications on the part of some auditors. For example, several utilities complained that auditors
required resumes of everyone in the program, including ground workers. Clearly, that goes well
beyond what was intended in the FAC-003-01, which was that vegetation management oversight
for a transmission operator be in the hands of knowledgeable and competent managers. Arguably,
demands for resumes of everyone remotely involved detracts from an effective program by
occupying managers with irrelevant paper work, rather than addressing the demands of protecting
their systems. On the other hand, poor judgment on the part of some auditors doesn’t reduce the
need for programs to be designed and implemented by qualified utility arborists. The Utility Arborist
Association understands the need to address deficiencies in aptitude among vegetation
management auditors, and is responding by developing training programs for them. Our objective
is to raise the level of understanding among vegetation management auditors to a level necessary
for consistent, fair and reasonable compliance oversight that will contribute to, rather than detract
from, electric reliability.Secondly, the Utility Arborist Association considers limiting a reference to
ANSI A300 to a footnote to insufficiently emphasize it’s criticality to overall electric reliability. The
UAA strongly urges adding language to R1.1 and M1.6, and hold utilities accountable for using best
management practices. The Utility Arborist Association has worked hard to incorporate sufficient
flexibility into integrated vegetation management best management practices to account for the
array of environmental, political and technical challenges that might confront vegetation managers
anywhere they practice. The Utility Arborist Association is confident that adding them as
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Does or Does Not
Question 17 Comment
requirements to the standard will improve reliability by raising professionalism and leading to more
effective results.
Northern Indiana Public Service
Company
V2 Does not maintain
or improve overall
reliability
There are many instances where V2 contains requirements and/or measures are weaker or less
stringent than V1. Examples:1. Elimination of Clearance 1 requirements which have been so
instrumental in improving T.O. vegetation maintenance activities on R.O.W.'s (see my comments
from Draft 1 of FAC-003-2).2. Elimination of requirement for personnel responsible for design and
implementation of TVMPs to hold appropriate qualifications to do so.3. Limitation of Corrective
Action Process or Mitigation Measures to instances of temporary constraints to planned work rather
than all constraints to planned work.4. Nesting the provision for T.O.'s to develop minimum
vegetation to conductor clearances that ensure MVCDs are never violated within a general
requirement to specify maintenance strategies. This needs to be a clear stand alone clearance
requirement similar to the existing Clearance 2.
BC Transmission Corporation
V2 Does not maintain
or improve overall
reliability
This is a vegetation outage standard not a vegetation management standard. It will do nothing to
improve the quality of vegetation maangement programs in North America
Northeast Power Coordinating
Council--RSC
V2 Does not maintain
or improve overall
reliability
V2 will not improve reliability for the following reasons. Eliminating Clearance 1 will be detrimental
to reliability. The determination of Clearance 1 is an important exercise for the TO to better
understand the dynamics of conductor movement and vegetative growth. This required analysis
should lead to development of a more informed vegetation management program. Clearance 1 also
gives the TO leverage with landowners and local regulators to achieve the necessary operational
clearances. If the only required clearance is the R4 Minimum Vegetation Clearance Distance
(MCVD), landowners and local regulators will push the utility to maintain a clearance close to the
MVCD. This will lead to diminished reliability. In some respects the Standard does help maintain
or improve overall reliability since the requirements for a TVMP are clearly addressed including
inspection cycles, responses to imminent threats, and documentation requirements. Also, the fact
that real time encroachments are considered violations will make utilities more likely to use LIDAR
(radar) and other technology without the fear of discovery of an encroachment violation of a
condition that has not occurred. This will result in earlier detection of potential problems and will
increase reliability. Even though the Clearance 1 value is being eliminated from the Standard,
operating specifications will still govern the way a utility handles its clearances as is currently done.
We do agree, however, that landowners and local regulators may want utilities to reduce
operational clearance levels based on the MVCD listed in the Standard, but the utility must properly
communicate the reasoning behind achieving greater clearances as per their TVMP. We do not
believe that eliminating the reporting of Category 3 sustained outages will lead to less effort to
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Does or Does Not
Question 17 Comment
mitigate danger tree exposure since all transmission outages are sensitive to a Transmission
Owner and must be addressed appropriately at multiple levels within the company as well as with
other regulatory agencies in some cases. Removing the qualifications requirement may initially lead
to Transmission Owners employing less qualified employees and contractors but there needs to be
some level of flexibility that will allow for a larger candidate pool or temporary support since
individuals with specialized training are not always readily available. The Transmission Owner
should be solely responsible for determining the abilities and training needs of its employees and
ensure that capable individuals perform their vegetation management functions.
Independent Electricity System
Operator
V2 Does not maintain
or improve overall
reliability
V2 will not improve reliability for the following reasons. Eliminating Clearance 1 will be detrimental
to reliability. The determination of Clearance 1 is an important exercise for the TO to better
understand the dynamics of conductor movement and vegetative growth. This required analysis
should lead to development of a more informed vegetation management program. Clearance 1 also
gives the TO leverage with landowners and local regulators to achieve the necessary operational
clearances. If the only required clearance is the R4 Minimum Vegetation Clearance Distance
(MCVD), landowners and local regulators will push the utility to maintain a clearance close to the
MVCD. This will lead to diminished reliability. The Standard does help maintain or improve overall
reliability since the requirements for a TVMP are clearly addressed including inspection cycles,
responses to imminent threats, and documentation requirements. Also, the fact that real time
encroachments are considered violations will make utilities more likely to use LIDAR (radar) and
other technology without the fear of discovery of an encroachment violation of a condition that has
not occurred. This will result in earlier detection of potential problems and will increase reliability.
Even though the Clearance 1 value is being eliminated from the Standard, operating specifications
will still govern the way a utility handles its clearances as is currently done. We do agree, however,
that landowners and local regulators may want utilities to reduce operational clearance levels based
on the MVCD listed in the Standard, but the utility must properly communicate the reasoning behind
achieving greater clearances as per their TVMP. We do not believe that eliminating the reporting of
Category 3 sustained outages will lead to less effort to mitigate danger tree exposure since all
transmission outages are sensitive to a Transmission Owner and must be addressed appropriately
at multiple levels within the company as well as with other regulatory agencies in some cases.
Removing the qualifications requirement may initially lead to Transmission Owners employing less
qualified employees and contractors but there needs to be some level of flexibility that will allow for
a larger candidate pool or temporary support since individuals with specialized training are not
always readily available. The Transmission Owner should be solely responsible for determining the
abilities and training needs of their employees and ensure that capable individuals perform their
vegetation management functions.
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Question 17 Comment
ISO New England Inc.
V2 Does not maintain
or improve overall
reliability
V2 will not improve reliability for the following reasons: 1) eliminating Clearance 1 will be
detrimental to reliability. The determination of Clearance 1 is an important exercise for the TO to
better understand the dynamics of conductor movement and vegetative growth. This required
analysis should lead to development of a more informed vegetation management program.
Clearance 1 also gives the TO leverage with landowners and local regulators to achieve the
necessary operational clearances. If the only required clearance is the R4 Minimum Vegetation
Clearance Distance (MCVD), landowners and local regulators will push the utility to maintain a
clearance close to the MVCD. 2) Eliminating the reporting of Category 3 sustained outages will lead
to less effort by the TO’s to mitigate danger tree exposure where the TO’s property rights allow.
This will lead to diminished reliability. The Standard does help maintain or improve overall reliability
since the requirements for a TVMP are clearly addressed including inspection cycles, responses to
imminent threats, and documentation requirements. Also, the fact that real time encroachments are
considered violations will make utilities more likely to use LIDAR (radar) and other technology
without the fear of discovery of an encroachment violation of a condition that has not occurred. This
will result in earlier detection of potential problems and will increase reliability. Even though the
Clearance 1 value is being eliminated from the Standard, operating specifications will still govern
the way a utility handles its clearances as is currently done. We do agree, however, that
landowners and local regulators may want utilities to reduce operational clearance levels based on
the MVCD listed in the Standard, but the utility must properly communicate the reasoning behind
achieving greater clearances as per their TVMP. We do not believe that eliminating the reporting of
Category 3 sustained outages will lead to less effort to mitigate danger tree exposure since all
transmission outages are sensitive to a Transmission Owner and must be addressed appropriately
at multiple levels within the company as well as with other regulatory agencies in some cases.
Removing the qualifications requirement may initially lead to Transmission Owners employing less
qualified employees and contractors but there needs to be some level of flexibility that will allow for
a larger candidate pool or temporary support since individuals with specialized training are not
always readily available. The Transmission Owner should be solely responsible for determining the
abilities and training needs of their employees and ensure that capable individuals perform their
vegetation management functions.
Hydro-Quebec TransEnergie
(HQT)
V2 Does not maintain
or improve overall
reliability
V2 will not improve reliability for the following reasons:. Eliminating Clearance 1 will be detrimental
to reliability. The determination of Clearance 1 is an important exercise for the TO to better
understand the dynamics of conductor movement and vegetative growth. This required analysis
should lead to development of a more informed vegetation management program. Clearance 1 also
gives the TO leverage with landowners and local regulators to achieve the necessary operational
clearances. If the only required clearance is the R4 Minimum Vegetation Clearance Distance
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Does or Does Not
Question 17 Comment
(MCVD), landowners and local regulators will push the utility to maintain a clearance close to the
MVCD. This will lead to diminished reliability. The Standard does help maintain or improve overall
reliability since the requirements for a TVMP are clearly addressed including inspection cycles,
responses to imminent threats, and documentation requirements. Also, the fact that real time
encroachments are considered violations will make utilities more likely to use LIDAR (radar) and
other technology without the fear of discovery of an encroachment violation of a condition that has
not occurred. This will result in earlier detection of potential problems and will increase reliability.
Even though the Clearance 1 value is being eliminated from the Standard, operating specifications
will still govern the way a utility handles its clearances as is currently done. We do agree, however,
that landowners and local regulators may want utilities to reduce operational clearance levels based
on the MVCD listed in the Standard, but the utility must properly communicate the reasoning behind
achieving greater clearances as per their TVMP. We do not believe that eliminating the reporting of
Category 3 sustained outages will lead to less effort to mitigate danger tree exposure since all
transmission outages are sensitive to a Transmission Owner and must be addressed appropriately
at multiple levels within the company as well as with other regulatory agencies in some cases.
Removing the qualifications requirement may initially lead to Transmission Owners employing less
qualified employees and contractors but there needs to be some level of flexibility that will allow for
a larger candidate pool or temporary support since individuals with specialized training are not
always readily available. The Transmission Owner should be solely responsible for determining the
abilities and training needs of their employees and ensure that capable individuals perform their
vegetation management functions.
Hydro One Networks inc.
V2 Does not maintain
or improve overall
reliability
V2 will not necessarily improve reliability for the following reasons: 1) eliminating Clearance 1 will
be detrimental to reliability. The determination of Clearance 1 is an important exercise for the TO to
better understand the dynamics of conductor movement and vegetative growth. This required
analysis should lead to development of a more informed vegetation management program.
Clearance 1 also gives the TO leverage with landowners and local regulators to achieve the
necessary operational clearances. If the only required clearance is the R4 Minimum Vegetation
Clearance Distance (MCVD), landowners and local regulators will push the utility to maintain a
clearance close to the MVCD. 2) Eliminating the reporting of Category 3 sustained outages will lead
to less effort by the TOs to mitigate danger tree exposure where the TOs property rights allow. This
might lead to diminished reliability.
ISO/RTO Council
V2 Does not
maintain or improve
overall reliability
The SRC believes the change from Reliability Coordinator to Planning Coordinator and the inclusion
of specific sub 200kv facilities maintains but does not improve the reliability effectiveness of this
standard over Version 1. The removal of the subrequirements R10.1 and R10.2 in Version 1 and the
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Question 17 Comment
new R10 applicable to PCs is appropriate.
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
18.
Besides the comments you have already provided for the preceding questions, do you have further
suggestions for improving this standard? If so, please elaborate.
Organization
Question 18 Comment
Salt River Project
- R4: Recommend changing the word “Minimum” in “Minimum Vegetation Clearance Distances” to “Critical” (same with M4) Footnote #4 (page 5 of 15): Recommend adding “microburst” (after storm) - Footnote #5 (page 5 of 15): Recommend addi
Xcel Energy
(a) The comments made above regarding the Requirement Sections of FAC-003-2 would need to be followed through in the
Measure Sections of the standard.(b) Compliance Section 1.5 â— 1b, the word “but” needs to be replaced with the word
“which.” (c) Attachment 1 needs to be renamed “Critical Clearance Distances” as discussed above in number 4.(d) We
understand the drafting team’s intent, when referring to “applicable lines”, is to encompass all 3 items under Facilities in the
Applicability section. Yet it is not clear as presently worded. Please clarify this in the next draft.(e) In version 1 of FAC-003, a
sustained outage caused by vegetation within the ROW likely results in a single violation. However, the latest draft of version 2
is written such that the same sustained outage would result in the violation of at least 2, if not 3, requirements. This could
quickly ratchet up the penalty amount by 3-4 times. We do not feel that this is reasonable, and recommend that modifications
be made to remove double or triple jeopardy circumstances.
Hydro One Networks inc.
(a) The inclusion of a detailed description of ANSI A300 contains a level of detail greater than what should be included in the
standard. A simple reference to the ANSI standard would be more than sufficient to provide an example of what may be
included in a TVMP, without appearing to dictate specific vegetation management practices that may or may not be available or
practical for all Transmission Owners across North America.(b) In the applicability Section, Facilities (4.2.1 in the clean version)
we suggest to explicitly indicate that the standard applies to BES facilities only, to read as follows:BES transmission lines
(“applicable lines”) operated at 200 kV or higher, and BES transmission lines operated below 200 kV designated by the
Planning Coordinator as being subject to this standard including but not limited to those that cross lands owned by federal,
state, provincial, public, private, or tribal entities.
FirstEnergy Corp
1. Applicability of the standard with regard to Line Ratings - Regarding the phrase "throughout its operating range under rated
conditions" in Req. R1, and also regarding the phrase "operating between no-load and their Rating" in Req. R4, R5, and R6, we
feel that "rated conditions" and "Rating" is ambiguous. FE interprets the intent to reflect the maximum conductor thermal rating
used in determining maximum sag conditions. We ask the SDT to confirm or clarify our interpretation. 2. Related to our
comments in Question 10, section 4.2.2 should be revised to state that sub-200kV lines designated by the PC are subject to
this standard 12 months after the Transmission Owner HAS RECEIVED the list from the PC.3. Changes may be needed to the
Technical Ref. document based on changes to the standard per our previous comments. Also, on pg. 32 of the ref. document it
shows a "high" VRF for Req. R6, but this should be "Medium". Lastly, on pg. 39 of the ref. document it references Part 11.3
which should say 1.1.3.4. Correct the misspelled word "Federal" in section 4.2.1.5. Compliance section 1.5 regarding
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Question 18 Comment
Categories, "Category 4" should be "Category 3". The footnote 7 is not needed and we suggest the team simply renumber the
category list to be 1A, 1B, 2 and 3. Or, FE would support a renumbering of 1, 2, 3 and 4. The list should not skip or omit a
category number.6. FE recommends that the SDT reconsider use of the term ‘applicable lines’ in the revised draft Standard.
While applicability of the standard is already described, use of this term in specific requirements could suggest that there may
be lines that are otherwise subject to requirements of the standard and only ‘applicable lines’ are addressed in some
requirements. Therefore, we suggest removing the repeated use of the term "applicable lines" throughout the standard because
it should be understood as those addressed in the "Applicability" section A4.2.. 7. Presently, the draft FAC-003-2 text includes a
footnote stating that ANSI A300 standard for tree care operations is considered an industry best practice. FE recommends that
this reference should not be included in the Standard. Since the ANSI standard would not provide certain obligations or
requirements, it is not necessary to be included in the NERC Standard (See definition of Reliability Standard, Standards
Development Procedure, p. 6). Rather, it should be included in a supporting document as a reference, as provided by the
Standards Development Procedure (p. 34).
Entergy Services, Inc
A) The definition of Active Transmission Line Right of Way in the White Paper contains several examples of “inactive or
unused” portions of corridors which are not contained in the definition in the standard. We suggest the examples contained in
the White Paper are also included in the definition contained in the standard. Examples of something, the “corridor” in this case,
helps clarify one’s understanding of “corridor”. The method is used in every dictionary. Therefore, we suggest adding the
following to the definition in the standard:”Examples of inactive or unused portions of corridors include:1) The portions of the
right of way acquired to accommodate future facilities. Power plant exits are examples where large rights of way are obtained
for maximum corridor utilization and may currently have fewer lines constructed.2) The portion of the right of way where
corridor edge zones (i.e., buffer zones) are provided for vegetation to exist.3) The portions of the right of way where doublecircuit structures are installed but only one circuit is currently strung with conductors.4) Portions of the right of way with
deactivated transmission lines that are unavailable for service.”B) Section 4.2 Facilities contains 3 subparts describing the
facilities to which this standard applies. We suggest adding a fourth subpart from the White Paper which describes facilities to
which this standard does not apply. Adding this fourth subpart will eliminate the need for future Interpretations and/or revisions
to this standard. Please add to section 4.2 Facilities the following from the last paragraph of page 8 of the White Paper:”4.2.4
This standard does not apply to line sections inside the electric station or substation fence, other boundary of an electric station
or substation, or underground lines.”C) The terms “imminent threat” and “vegetation imminent threat” are used in the standard.
We suggest “vegetation imminent threat” be used in all locations of the standard.D) Standard R1.6 uses the term “never
violated” which we believe requires 100% compliance and is too rigid a requirement given the propensity of hurricanes,
tornados, and other weather conditions that cause debris to possibly broach the clearances contained in Table 1 Attachment 1.
We suggest replacing “never violated” with “not violated during rated operating conditions and normal weather conditions.”E)
R5, R6 and R8 contain 2 bullet items while the second bullet item in those requirements is not contained in R7. We suggest
adding the second bullet item to R7:”Sustained Outages of applicable lines that result from human or animal activity.5”
MRO NERC Standards Review
A. In FAC-003-1 a self reportable violation could occur at any time vegetation was within, had previously been, or had passed
through (fall in) the Clearance 2 zone. In FAC-003-2, this is reportable only if observed in real time. Under FAC-003-1, a tree
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Question 18 Comment
Subcommittee
that was causing instantaneous operations of the line either through wind or loading would be a reportable violation of the
Clearance 2 zone when found later during a patrol, even though the clearance now was well outside of the Clearance 2 zone.
In FAC-003-2, a self reportable violation would be required only if the tree was observed, in real time, to be in the MVCD.B.
Perhaps there should be a statement in FAC-003-2 that is explicit that the TO will manage its ROW to its "full and legal
rights".C. The comments made above regarding the Requirement Sections of FAC-003-2 would need to be followed through in
the Measure Sections of the standard.D. Compliance Section 1.5 Category 1B(“Grow-ins: Sustained Outages caused by
vegetation growing into applicable lines but are not identified as an element of an IROL (or Major WECC Transfer Path) by
vegetation inside and/or outside of the Active Transmission Line ROW”), the word “but” needs to be replaced with the word
“which.” E. Attachment 1 needs to be renamed “Critical Clearance Distances” as discussed above in Question 4b.F. General
comment to entire standard: Remove the repeated use of the term “applicable lines” throughout the revised standard. It should
be understood as those addressed in the “Applicability” section A4.2.G. In version 1 of FAC-003, a sustained outage caused
by vegetation within the ROW likely results in a single violation. However, the latest draft of version 2 is written such that the
same sustained outage would result in the violation of at least 2, if not 3, requirements. This could quickly ratchet up the
penalty amount by 3-4 times. We do not feel that this is reasonable, and recommend that modifications be made to remove
double or triple jeopardy circumstances.
Utility Arborist Association
As the industry’s leading science and educational organization, the UAA urges the standards drafting team to incorporate
provisions that will encourage and compel all utilities to utilize proven vegetation management techniques and practices. We
advocate for adequate and appropriate training, adherence to applicable A300 standards, and a clear, consistent, sciencebased approach to effective vegetation management across North America. ANSI A300 has the flexibility to adjust to local
conditions, so there is no reason to not require it’s implementation. We also feel that it is appropriate to expect each utility to
have a qualified person on staff (or in a full or part time contracted position) who fully understands proper utlity vegetation
maangment. We believe the requirements of qualified people, and adherence to best practices, should be a part of this
standard. Further, it is important to recognize the impacts of not directly referencing qualifications and best management
standards (A300, etc) in this standard. Now that clearance 1 (in FAC-003 version 1) has been removed, there will likely be
more incidents where land agencies, local governments or individuals will attempt to force their own interpretation of what is
correct on the utility. In these cases the utility should be able to point to specific references in the proposed standard which will
clearly identify what needs to be done (such as the practices described in A300). The utilities should also be able to point to
specific references in the standard that establish them as the true authority on the required scope of work (particularly when
they are liable for any failure). A specific reference to qualified employees and adherence to A300 will enable the utilities to
better control their own ROW’s and should be included in this version of FAC-003.Finally, we believe that the regulators, and
other entities who shall be overseeing compliance with this standard, should have an equal understanding of utility vegetation
management and compliance as the utilities charged with complying with FAC-003-02. In order to raise the understanding of
vegetation managment on the part of vegetation management auditors, the UAA is developing training specifically for them.
Our intent is to offer a program that will be available to utilities and compliance auditors that will lead to a consistent and
informed understanding of vegetation management and its legal and regulatory requirements. Thank you for the opportunity to
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Question 18 Comment
comment on this very important regulation and the UAA stands ready to assist the standards drafting team in any way we can.
Consolidated Edison Company of
New York Inc.
CECONY recommends that stricter language be used in the Standard specifically requiring the industry to remove incompatible
species on Active ROWs. This should reduce the number of outages resulting from vegetation grow-ins and vegetation fall-ins
and help maintain a higher level of reliability. This is currently done at the state level (in New York) and the revised wording in
the Federal Standard would ensure consistency industry-wide and avoid confusion. A standard definition for the term
incompatible would be required to avoid misuse of the term as well.
Edison Electric Institute
EEI has two additional recommendations for consideration by the SDT. First, the draft revised Standard stated purpose is to
‘avoid vegetation related outages that could lead to Cascading.’ To better align the Standard with the direction provided by
Order No. 693 as well as the content of the revised draft Standard, EEI recommends that the SDT consider revising the
purpose statement to read: ‘To avoid vegetation-related Sustained Outages of transmission lines.’Second, EEI agrees with the
intent of including events that would define exceptions for requirements to comply with FAC-003. To assist in reducing
ambiguity and as an alternative to the approach in the draft Standard of using footnotes, EEI recommends that the SDT
consider adding a generic exceptions statement in the applicability section more specifically stating that companies will not be
subject to compliance requirements to the extent that events or circumstances beyond their control limit or prevent their abilities
to perform. Here’s one example:Compliance with this Standard will not apply should there exist an occurrence, nonoccurrence, or other set of circumstances that are beyond the reasonable control of a Registered Entity subject to this
Reliability Standard, and are not caused by the fault or negligence of the Registered Entity, including acts of God, strike, flood,
drought, earthquake, storm, fire, hurricane, tornado, landslides, logging activities, animals severing trees, lightning, epidemic,
war, riot, civil disturbance, sabotage, vandalism, terrorism, or action or inaction by any Governmental Authority or individual that
restricts or prevents performance to comply with this Reliability Standard. Should the SDT choose to not add a specific
exceptions statement, EEI encourages additional specificity in the footnotes.
Transmission Owner
FPL is in support of the changes made to the Purpose Statement. The purpose should be further clarified. FPL Suggests the
following wording:To improve the reliability of applicable electric transmission facilities by preventing those vegetation related
outages within active ROW that could lead to Cascading.FPL agrees with the changes in R9 and indicated that in Question 9,
however, FPL sees a need for an exemption due to disasters (natural or manmade). During the hurricane seasons of 2004 and
2005 most utilities in the east and southeast were either directly or indirectly affected by the hurricanes occurring in that time
period (including named storms. It was in the National interest that those not directly effected respond to requests for mutual
aid from those utilities that were. Conversely, those affected had to restore their systems. Annual Work Plans were delayed or
changed. An exemption or mechanism needs to be in place to allow utilities to respond with out violating the standard.
American Transmission
Company
General comment to entire standard: Remove the repeated use of the term “applicable lines” throughout the revised standard.
It should be understood as those addressed in the “Applicability” section A4.2.Also, ATC supports the deletion of footnote #2 to
R1.1 regarding ANSI A300. Since the ANSI standard would not provide certain obligations or requirements, it is not necessary
to be included in the NERC Standard. (See definition of Reliability Standard, Standards Development Procedure, p. 6) Rather,
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Question 18 Comment
it should be included in a supporting document as a reference, as provided by the Standards Development Procedure (p. 34)
Oncor Electric Delivery
Having a binary system for R4, 5, 6, 7, and 8 creates a one size fits all approach. The SDT should consider allowing for some
normalizing of events / sustained outages per metric considering the number of applicable miles to allow a range of VSL’s to be
applied.
CenterPoint Energy
Improvements to Standard1. Revise the Purpose statement to “preventing vegetation related outages” and delete “that could
lead to Cascading” since Cascading is not referenced anywhere else within the Standard.2. Within R1.6, substitute “practices”
for “strategies” as a more actionable word.3. R1.2 and R3 should use the same wording when referring to the frequency of
Vegetation Inspections.4. Within M1.6, substitute “practices” for “strategies” as a more actionable word.Improvements to
Technical Reference 1. Revise the statement on page 9 to read as follows, “It is not intended to prevent customer outages from
occurring due to tree contact with all transmission lines and voltages; however, the Standard is not intended to dissuade best
utility practice regarding vegetation management for transmission lines that fall outside the Standard.” The Technical
Reference is a public document, and thus should be careful to mention best management practices, public safety, and hazard
avoidance whenever applicable. Allowing trees to grow near transmission lines at any voltage is a public safety hazard.2. In
the Wire-Border Zone section on page 15, CenterPoint Energy recommends revising this sentence as follows, “The wire zone
is the section of a utility transmission right of way directly under the wires and extending outward a sufficient distance to allow
for movement of the conductors”, which deletes the phrase "about 10 feet on each side". The specific 10’ distance is
misleading where rights of way are purchased without ownership of a border zone, and it may be misleading to the public.
CenterPoint Energy has not historically purchased a border zone, and the wire zone equates to the legal limits of our rights of
way.The paragraphs on page 15 that start, “One way...”, and “In areas where...”, should be deleted because they may mislead
the public by not taking into account all the needs to remove trees such as access below the lines and possible reconductoring
or rebuilding of lines that change the transmission line profile and thus impact the need to remove tall trees in any instance.
The prior statement that starts, “Although the wire-border zone...” is sufficient to introduce flexibility in practices.3. In the
Selecting a Maintenance Strategy section on page 25, CenterPoint Energy recommends deleting the paragraph that starts, “If
faced with...”. It should be deleted because it may mislead the public to believing that granting exceptions for trees is a
common practice and should be pursued. It does not take into account all the needs to remove trees such as access below the
lines and possible reconductoring or rebuilding of lines that change the transmission line profile and thus impact the need to
remove tall trees in any instance. It is also not necessary to the example.4. The third bullet under R4 on page 30 has an extra
word, “Brief”, that is not in the Standard itself.5. R6 quoted on page 32 has an incorrect Violation Risk Factor of “High” instead
of “Medium”.
Idaho Power Company
In the definition of terms remove ‘intended for other facilities’ from the definition for Active Transmission Line Right of Way. In
the definition of Vegetation, remove ‘ considering the current location of the conductor and other possible locations of the
conductor due to sag and sway for rated conditions’ since this is covered in the Standards section.In the measures section,
remove ‘neighboring Planning Coordinators’ from M10 since a neighbor may have different views as to which sub-200kV lines
145
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Question 18 Comment
are subject to Standard R10
SCE&G
N/A
WECC RC
NO
National Grid
No additional comments.
American Electric Power
No additional questions at this time.
PacifiCorp
None
NRECA - National Rural Electric
Cooperative Association
NRECA on behalf of its members would like to thank the drafting team for its efforts in addressing cooperative concerns from
the previous draft of FAC-003-2. In addition, it is important for the drafting team to incorporate the recommendations of the
Generator Requirements at the Transmission Interface Ad Hoc Group (GOTO Team) regarding the implications of this standard
for the transmission facilities designated as Generator Interconnection Facilities (GIFs). The specific recommendations
NRECA supports are; the sole use of GIFs should not cause the registration of entities as Transmission Owners and
Transmission Operators, clarifying requirements for GIFs, adding new requirements to make expectations clear for these facility
types and working with the GOTO Team to incorporate any new definitions in the NERC Glossary of terms to clarify
requirements of this standard.
Orange and Rockland Utilities,
Inc.
ORU recommends that stricter language be used in the Standard specifically requiring the industry to remove incompatible
species on Active ROWs. This should reduce the number of outages resulting from vegetation grow-ins and vegetation fall-ins
and help maintain a higher level of reliability. This is currently done at the state level (in NY) and the revised wording in the
Federal Standard would ensure consistency industry-wide and avoid confusion. A standard definition for the term incompatible
would be required to avoid misuse of the term as well.
Associated Electric Cooperative,
Inc.
Paragraph A.4.2.1 - Associated Electric Cooperative Inc assumes the Standard Drafting Team’s intent is for the standard to
apply, without exception, to all transmission lines operated at 200 kV or higher and to all transmission lines operated below 200
kV designated by the Planning Coordinator as being subject to the standard. To this end, AECI believes the list of land
ownerships included in A.4.2.1 detracts from, rather than adds to, the clarity of the paragraph. It is suggested the paragraph be
revised to something like, “All transmission lines (“applicable lines”) operated at 200 kV or higher, and all transmission lines
operated below 200 kV designated by the Planning Coordinator as being subject to this standard.”Paragraph D.1.5 - This
paragraph clearly requires Transmission Owners to provide periodic reports to the Regional Entity of Sustained Outages
occurring on applicable lines that are caused by vegetation. As such, it should be included in the Requirements section of the
standard. Associated Electric Cooperative Inc. does not disagree with the intent of the paragraph, only its location within the
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Question 18 Comment
standard.
Progress Energy Carolinas, Inc.
PEC recommends that the ANSI A300 footnote #2 to R1.1 be removed and included in supporting documentation (the
Technical Reference document - “White Paper”).
Southern California Edison
Company
SCE appreciates the great amount of time and effort expended by the Drafting Team on the FAC-003-2 Reliability Standard.
Entegra Power Group LLC
See Question 14 comments
Florida Municipal Power Agency,
and its Member Cities, Lakeland
Electric and Kissimmee Utility
Authority
Specify an interim corrective action process for use when theTransmission Owner is temporarily constrained from
performingvegetation maintenance as planned.
Vegetation Management Team
The “methods ... to control” in R1.1, the annual work plan in R1.3, and the “maintenance strategies” in R1.6 seem to refer to the
same actions but require the TO to address them separately in the TVMP. This needs to be clarified or consolidated.
Central Maine Power an Energy
East Company
The clearance 2 defined in FAC 003 1 was a useful tool for transmission owners to manage rights of ways to a robust standard
rather than a minimum standard. This language should be included in the TVMP requirement (R1). Suggested language "The
TVMP must define a clearance two". The standard would only require this distance be included as part of each T.O's plan, and
would eliminate the fill in the blank concept.Suggest that standard note that qualif1ed vegetation managers are recommended
to manage the V.M. program.FAC 003 2 should retain the reference to ANSI A300.
Hydro-Quebec TransEnergie
(HQT)
The inclusion of a detailed description of ANSI A300 contains a level of detail greater than what should be included in the
standard. A simple reference to the ANSI standard would be more than sufficient to provide an example of what may be
included in a TVMP, without appearing to dictate specific vegetation management practices that may or may not be available or
practical for all Transmission Owners across North America.It is recommended that stricter language be used in the Standard,
specifically requiring the industry to remove incompatible species on Active ROWs. This should reduce the number of outages
resulting from vegetation grow-ins and vegetation fall-ins and help maintain a higher level of reliability. This is currently done at
the state level (in New York), and the revised wording in the Federal Standard would ensure consistency industry-wide and
avoid confusion. A standard definition for the term incompatible would be required to avoid misuse of the term as well. Editorial
comments--the “1” after “federal” in the first bullet under “Facilities” in the “Applicability” section should be a superscript to
indicate the footnote. The text that a footnote refers to should appear at the bottom of the page it is used on, or at a common
location, not on different pages.We reiterate the need to change the language used in the purpose of the Standard as per our
answer to Q10; if not, we would appreciate to know the SDT rational.
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Question 18 Comment
Independent Electricity System
Operator
The inclusion of a detailed description of ANSI A300 contains a level of detail greater than what should be included in the
standard. A simple reference to the ANSI standard would be more than sufficient to provide an example of what may be
included in a TVMP, without appearing to dictate specific vegetation management practices that may or may not be available or
practical for all Transmission Owners across North America.It is recommended that stricter language be used in the Standard,
specifically requiring the industry to remove incompatible species on Active ROWs. This should reduce the number of outages
resulting from vegetation grow-ins and vegetation fall-ins and help maintain a higher level of reliability. This is currently done at
the state level (in New York), and the revised wording in the Federal Standard would ensure consistency industry-wide and
avoid confusion. A standard definition for the term incompatible would be required to avoid misuse of the term as well. Editorial
comments--the “1” after “federal” in the first bullet under “Facilities” in the “Applicability” section should be a superscript to
indicate the footnote. The text that a footnote refers to should appear at the bottom of the page it is used on, or at a common
location, not on different pages.
ISO New England Inc.
The inclusion of a detailed description of ANSI A300 contains a level of detail greater than what should be included in the
standard. A simple reference to the ANSI standard would be more than sufficient to provide an example of what may be
included in a TVMP, without appearing to dictate specific vegetation management practices that may or may not be available or
practical for all Transmission Owners across North America.It is recommended that stricter language be used in the Standard,
specifically requiring the industry to remove incompatible species on Active ROWs. This should reduce the number of outages
resulting from vegetation grow-ins and vegetation fall-ins and help maintain a higher level of reliability. This is currently done at
the state level (in New York), and the revised wording in the Federal Standard would ensure consistency industry-wide and
avoid confusion. A standard definition for the term incompatible would be required to avoid misuse of the term as well. Editorial
comments--the “1” after “federal” in the first bullet under “Facilities” in the “Applicability” section should be a superscript to
indicate the footnote. The text that a footnote refers to should appear at the bottom of the page it is used on, or at a common
location, not on different pages.
Northeast Power Coordinating
Council--RSC
The inclusion of a detailed description of ANSI A300 contains a level of detail greater than what should be included in the
standard. A simple reference to the ANSI standard would be more than sufficient to provide an example of what may be
included in a TVMP, without appearing to dictate specific vegetation management practices that may or may not be available or
practical for all Transmission Owners across North America.It is recommended that stricter language be used in the Standard,
specifically requiring the industry to remove incompatible species on Active ROWs. This should reduce the number of outages
resulting from vegetation grow-ins and vegetation fall-ins and help maintain a higher level of reliability. This is currently done at
the state level (in New York), and the revised wording in the Federal Standard would ensure consistency industry-wide and
avoid confusion. A standard definition for the term incompatible would be required to avoid misuse of the term as well. Editorial
comments--the “1” after “federal” in the first bullet under “Facilities” in the “Applicability” section should be a superscript to
indicate the footnote. The text that a footnote refers to should appear at the bottom of the page it is used on, or at a common
location, not on different pages.
148
Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Question 18 Comment
Southern Company
The new format for the standard moves some requirements from the compliance section (i.e. outage reporting) to additional
compliance information. Does this remove the outage reporting requirement from the CMEP? If not, how will it be monitored?
ReliabilityFirst Corporation
The only comment I have is in Facilities section, in the first bullet. I do not see need for adding all the verbiage (including but
not limited to those that cross lands owned by federal1, state, provincial, public, private, or tribal entities) after “designated by
the Planning Coordinator”.
Superintendent Transmission
Maintenance
The white paper could further explain the process by which the planning coordinator and utilities identify sub-200kV lines to be
included in the standard. Clarify the definition of an active transmission ROW.
Manitoba Hydro
the wording of requirement 1.5, last word should be changed from "planned" to "required" as one could change the plan based
on land deal negotiations for example, or site specific engineering calculations, but at least the minimum requirements to
maintain the vegetation must be met.In version 1 of FAC-003, a sustained outage caused by vegetation within the ROW likely
results in a single violation. However, the latest draft of version 2 is written such that the same sustained outage would result in
the violation of at least 2, if not 3, requirements. This could quickly ratchet up the penalty amount by 3-4 times. We do not feel
that this is reasonable, and recommend that modifications be made to remove double or triple jeopardy circumstances.
SERC Vegetation Managment
Sub-committee (VMS)
There are certain lines, not owned by Transmission Owners (TO’s) that should be covered by this standard. These include
facilities owned by DP’s and GO’s that are not registered as TO’s. This should be addressed via the Standard’s applicability
section and not via registration.
Bonneville Power Administration
There are several inconsistencies throughout the document regarding the way Attachments are referred to. The lines are
referred to in many different ways - real-time, no load, etc. ??? Standard is a little difficult to follow. The term “sway” is not a
technical term, suggest using “swing” or “blow out”.
North Carolina Electric
Membership Corporation
Yes. There are certain facilities, not owned by Transmission Owners (TO’s) that should be covered by this standard. These
include facilities owned by Distribution Provider’s (DP’s) and Generation Owner’s (GO’s) that are NOT registered as TO’s. In
the last draft, several entities provided comments to the SDT about GO’s and DP’s who own such interconnection facilities to
connect their generation and load to the transmission system. We make a plea to the SDT to reconsider those comments such
as those provided by SERC Compliance Staff. As the standard currently exists today, it forces entities that have such
interconnection facilities to be registered as a TO’s regardless of the length of the facility used for interconnection (50 feet, 0.50
miles or 50 miles). These additional facilities should be captured via the Standard’s applicability section and not via
registration, thus making the entity subject only to the FAC-003 standard and not to all TO standards. Also, we respectfully
request that the SDT provide additional guidance in the standard about length of interconnection facilities before the standard is
applicable to such facilities. One suggestion has been offered in the GOTO Team forum ad we repeat here for the benefit of
the SDT: Only those Generator Interconnection Facilities above 200kv which extend more than one mile from the Generator
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Consideration of Comments on Standard FAC-003-2 — Project 2007-07
Organization
Question 18 Comment
Owner property boundary should be assigned applicability for FAC-003-1. A clarification may be needed to provide that those
Generator Interconnection Facilities which are located entirely on Generator Owner property should not be applicable.We
would also suggest the same guidance be provided for tap lines and radials owned by DPs when these taps or radial are short
distances and are within DP property where there would be no gaps. Without this guidance or clarification, then it is left to each
Regional Entity to apply their own opinion which may result in inconsistency in enforcing the standard.
150
Summary Considerations FAC-003-2
Second Industry Comment Period (9/10/09 to 10/24/09)
Background:
On January 14, 2010, the NERC Standards Committee endorsed the use of Project 2007-07
Vegetation Management as the prototype for the proof-of-concept for using the results-based
criteria for developing a reliability standard. The results-based initiative is intended to focus the
collective effort of NERC and industry participants on improving the clarity and quality of
NERC reliability standards by developing performance, risk and competency-based requirements
that accomplish a reliability objective through a defense-in-depth strategy, while eliminating
documentation-driven requirements that do not have an impact on bulk power system reliability.
The Standards Committee directed the Vegetation Management SDT to stop work in refining its
second draft of the Vegetation Management standard but to inform stakeholders on how the team
had used stakeholder comments to refine the technical requirements carried over into draft 3 of
the standard.
This report provides a copy of each of the questions that was posted for stakeholder comment
with the second draft of FAC-003-2, and a summary indicating how the drafting team used
stakeholder comments submitted in response to that question. The questions included in the
second comment form provided explicit references to either background information provided in
the comment form or to specific requirements or other elements in the standard and have been
paraphrased here.
All questions asked and all comments provided by stakeholders have been posted at the
following site:
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
FAC-003-2 — Transmission Vegetation Management
Index to Questions and Summary Responses:
Question 1 ................................................................................................................... 3
Question 2 ................................................................................................................... 5
Question 3 ................................................................................................................... 6
Question 4 ................................................................................................................... 7
Question 5 ................................................................................................................... 8
Question 6 ................................................................................................................... 9
Question 7 ................................................................................................................. 10
Question 8 ................................................................................................................. 11
Question 9 ................................................................................................................. 12
Question 10 ............................................................................................................... 13
Question 11 ............................................................................................................... 14
Question 12 ............................................................................................................... 15
Question 13 ............................................................................................................... 16
Question 14 ............................................................................................................... 17
Question 15 ............................................................................................................... 18
Question 16 ............................................................................................................... 19
Question 17 ............................................................................................................... 20
Question 18 ............................................................................................................... 21
Draft 3: March 1, 2010
2
FAC-003-2 — Transmission Vegetation Management
Question 1
In response to industry comments, the Requirement for documentation of a TVMP was revised to clarify
that the objective of the TVMP is to improve reliability by preventing Sustained Outages due to
vegetation. Additionally the SDT assigned Time Horizons, Violation Risk Factors, and Violation
Severity Levels. Do you agree? If not, please explain and propose an alternative.
Second draft of proposed R1:
R1.
Each Transmission Owner shall have a documented transmission vegetation management
program that describes how it conducts work on its Active Transmission Line Rights of
Way to prevent Sustained Outages due to vegetation, considering all possible locations the
conductor may occupy under the effects of sag and sway throughout its operating range
under rated conditions. The transmission vegetation management program shall: [Violation
Risk Factor – Lower][Time Horizon – Long-term planning]
1.1.
Specify the methods that the Transmission Owner may use to control vegetation. 1
1.2.
Specify a Vegetation Inspection frequency of at least once per calendar year that
takes into account local 2 and environmental factors.
1.3.
Require an annual work plan. An annual work plan shall:
1.3.1. Identify the applicable lines to be maintained
1.3.2. Identify the work to be performed and methods to be used
1.3.3. Be flexible to adjust to changing conditions and to findings from Vegetation
Inspections. Adjustments to the plan within the year are permissible.
1.3.4. Take into consideration permitting and scheduling requirements from
landowners or regulatory authorities.
1.4.
Require a process or procedure for response to an imminent threat of a vegetationrelated Sustained Outage. The process or procedure shall specify actions which
shall include communication of the threat to the responsible control center.
1.5.
Specify an interim corrective action process for use when the Transmission Owner
is temporarily constrained from performing vegetation maintenance as planned.
1.6.
Specify the maintenance strategies used (such as minimum vegetation-to-conductor
distance or maximum vegetation height) to ensure that Table 1 clearances in
Attachment 1 are never violated. The maintenance strategies shall consider the sag
and sway of the conductor throughout its operating range under rated conditions.
Summary Consideration: The vast majority of comments for this Question related to the
Annual Vegetation Inspection frequency. Those commenters believed that a once/year mandate
was too prescriptive and preferred to let the Transmission Owner choose a frequency.
1
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices,
while not a requirement of this standard, is considered to be an industry best practice.
2
Local factors include items such as treatment cycle, extent and type of treatment, and their relationship to the
normal growth rate.
Draft 3: March 1, 2010
3
FAC-003-2 — Transmission Vegetation Management
After reviewing Order 693 in its entirety, the SDT set the frequency at once/year to avoid a fillin-the-blank requirement and establish a reasonable frequency for most regions. However, the
SDT also made it explicitly clear that this Vegetation Inspection can be combined with other line
inspections to allow maximum flexibility in meeting this requirement. The vast majority of other
comments dealt with specific wording in the Draft 2, Requirement 1. In an effort to be less
prescriptive, the new Draft has removed most of the text that commenters wanted changed.
Draft 3: March 1, 2010
4
FAC-003-2 — Transmission Vegetation Management
Question 2
In response to industry comments, the Requirement for implementation of Imminent Threat
process/procedure was revised. Additionally the SDT assigned Time Horizons, Violation Risk
Factors, and Violation Severity Levels. Do you agree? If not, please explain and propose an
alternative.
Second draft of proposed R2:
R2. Each Transmission Owner shall implement its imminent threat process or procedure when
the Transmission Owner has actual knowledge of such a threat, obtained through normal
operating practices. [Violation Risk Factor – Medium][Time Horizon – Real Time]
Summary Consideration: Ninety percent of respondents agreed with Requirement 2
(Implementation of the Imminent Threat Process). No major themes of disagreement surfaced.
Two respondents expressed confusion between the NERC defined term “Operating Process” and
the language “operating practices” used in R2. Two respondents preferred more specificity in
the requirement for audit purposes, one respondent suggested changing “actual knowledge” to
“confirmed” and one respondent expressed concerns about proving a negative. Two other
respondents had comments that were more appropriate for questions 1 & 4 and are answered
there.
The SDT considered all comments and essentially retained all the previous language in the new
draft. Of note, the term “actual knowledge” was changed to “verified knowledge” based on the
guidelines for Requirements with the new standard format. This change still retains its meaning
that the Transmission Owner “confirmed” the potential threat prior to initiating the Imminent
Threat process.
Proposed requirement in Draft 3 of FAC-003-2:
R5. Each Transmission Owner shall take interim corrective action when it is temporarily
constrained from performing planned vegetation work, where a Transmission Line is put at
potential risk due to the constraint.
Draft 3: March 1, 2010
5
FAC-003-2 — Transmission Vegetation Management
Question 3
In response to industry comments, the Requirement for conducting Vegetation Inspections was
revised. Additionally the SDT assigned Time Horizons, Violation Risk Factors, and Violation
Severity Levels. Do you agree? If not, please explain and propose an alternative.
Second draft of proposed R3:
R3. Each Transmission Owner shall conduct Vegetation Inspections of all applicable lines (as
measured in line miles) in accordance with the frequency specified in its transmission
vegetation management program, unless constrained by natural disasters. When constrained
by a natural disaster, the Transmission Owner shall conduct the Vegetation Inspection(s)
within six months or a period agreed to by its Regional Entity, whichever is greater.
[Violation Risk Factor – Medium][Time Horizon – Operations Planning]
Summary Consideration: Eight commenters perceived an inconsistency in the inspection
frequency required between Requirement 1.2 and Requirement R3. Eleven (11)respondents felt
an inspection frequency of longer than once per calendar year should be acceptable, the required
frequency for inspection was unclear, or that the requirement should simply state an inspection
interval of once per calendar year. Five comments (5) noted that the Requirement R3 exception
for non performance due to natural disasters should be expanded, re-organized, or re-worded to
be more clear or include a number of additional situations including disease or species
epidemics. Several entities (6) expressed a concern over the use of the term “line miles” in the
performance measures for this requirement. Finally, a few comments (2) were received that
suggested the phrase “all applicable lines” be removed from the requirement.
With this new Draft, the Standards Drafting Team has removed 1.2 which eliminates any
perceived confusion. After reviewing Order 693 in its entirety, the SDT re-established the
frequency at once/year to avoid a fill-in-the-blank requirement and establish a reasonable
frequency for most regions. However, the SDT also made it explicitly clear that this Vegetation
Inspection can be combined with other line inspections to allow maximum flexibility in meeting
this requirement. The FAC-003-2 Draft 3 includes a general, and more inclusive, Force Majeure
section which applies to the entire Standard. The Standards Drafting Team responded to industry
comments about the term “line miles”. There is now more explanation of this term in the VSL
for R6.”
Draft 3: March 1, 2010
6
FAC-003-2 — Transmission Vegetation Management
Question 4
In response to industry comments, the Requirement for preventing vegetation encroachments
was revised. Additionally the SDT assigned Time Horizons, Violation Risk Factors, and
Violation Severity Levels. Do you agree? If not, please explain and propose an alternative.
Second draft of proposed R4:
R4. Each Transmission Owner shall prevent encroachment of vegetation into the Minimum
Vegetation Clearance Distances (MVCD) listed in FAC-003-2 - Attachment 1 for its
applicable lines as observed in real-time operating between no-load and their Rating, with
the following exceptions: [Violation Risk Factor – Medium][Time Horizon – Real Time]
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting from
natural disasters. 3
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting from
human or animal activity. 4
Encroachment into the MVCD listed in FAC-003-2-Attachment 1 resulting from falling
vegetation.
Summary Consideration: Fifty-two percent (32 of 62) of the respondents disagreed with
various aspects of Requirement 4 (Preventing Vegetation Encroachments). A major theme from
19 responses requested clarification on the fall-in tree exemption particularly when a fall-in tree
may be lodged in another tree. The following six minor themes were identified:
Requested the use of the word “critical” rather than “minimum” to aide with public
perception (7 responses)
Clarification on operating beyond emergency ratings (7 responses)
Clarification on what is meant by “observed in real-time”( 6 responses)
Requested a force majeure exemption be added (5 responses)
Requested observations be done by qualified observers (4 responses)
Requested to eliminate R4 (4 responses).
Requested an interpolation in the clearance tables for altitude(2 responses)
Identified “Double Jeopardy” concern between Requirement 4 and the outage
Requirements(1 response)
The SDT considered all comments and determined that two of these were significant enough to
change the standard - the SDT combined the outage requirements (R5, R6, R7 and R8) with the
encroachment requirement (R4). The SDT determined the other comments could be adequately
addressed as modifications for clarity to the Technical Reference Document.
3
Examples include, but are not limited to, earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale,
major storms as defined either by the Transmission Owner or an applicable regulatory body, ice storms, and floods.
4
Examples include, but are not limited to, logging, animal severing tree, vehicle contact with tree, arboricultural
activities or horticultural or agricultural activities, or removal or digging of vegetation.
Draft 3: March 1, 2010
7
FAC-003-2 — Transmission Vegetation Management
Question 5
In response to industry comments, the Requirement for preventing Sustained Outages due to
grow-ins on IROL or Major WECC Transfer Paths was developed. Additionally the SDT
assigned Time Horizons, Violation Risk Factors, and Violation Severity Levels. Do you agree? If
not, please explain and propose an alternative.
Second draft of proposed R5:
R5. Each Transmission Owner shall prevent Sustained Outages 5 of applicable lines that are
identified as an element of an Interconnection Reliability Operating Limit (IROL) (or
Major WECC Transfer Path) due to vegetation growing into a conductor operating between
no-load and its Rating, with the following exceptions: [Violation Risk Factor – High][Time
Horizon – Real Time]
Sustained Outages of applicable lines that result from natural disasters.
Sustained Outages of applicable lines that result from human or animal activity.
Summary Consideration: Commenters generally agreed with R5 in draft 2. The most
significant issues that the SDT needed to consider were: the addition of other exclusionary
conditions, the prima facie double jeopardy that exists with this requirement and R4, the lack of
robust VSLs, and the need for further clarity on terms and concepts (e.g. rating, minimum).
Finally, a few commenters noted that this requirement is structured unlike other conventional
NERC standard requirements in that it does not say what must be accomplished for reliability
(and compliance) but rather says what must NOT be done.
The SDT considered these comments and determined that two of these were significant enough
to change the standard - the SDT combined the outage requirements (R5, R6, R7 and R8) with
the encroachment requirement (R4), with one combined Requirement for IROLs/Major WECC
Transfer Paths and another combined Requirement for all other lines. A broadened Force
Majeure section was added to the applicability section of the standard. Additionally, the new R1
and R2 in this Draft were reworded to describe what must be done.
5
Multiple Sustained Outages on an individual line, if caused by the same vegetation, shall be considered as one
outage regardless of the actual number of outages within a 24-hour period.
Draft 3: March 1, 2010
8
FAC-003-2 — Transmission Vegetation Management
Question 6
In response to industry comments, the Requirement for preventing Sustained Outages due to
grow-ins on non-IROL or Major WECC Transfer Paths was developed. Additionally the SDT
assigned Time Horizons, Violation Risk Factors, and Violation Severity Levels. Do you agree? If
not, please explain and propose an alternative.
Second draft of proposed R6:
R6. Each Transmission Owner shall prevent Sustained Outages of applicable lines that are not
an element of an IROL (or major WECC Transfer Path) due to vegetation growing into a
conductor operating between no-load and its Rating, with the following exceptions:
[Violation Risk Factor – Medium][Time Horizon – Real Time]
Sustained Outages of applicable lines that result from natural disasters.
Sustained Outages of applicable lines that result from human or animal activity.
Summary Consideration: Commenters generally agreed with R6 in draft 2. The most
significant issues that the SDT needed to consider were: the addition of other exclusionary
conditions, the prima facie double jeopardy that exists with this requirement and R4, the lack of
robust VSLs, and the need for further clarity on terms and concepts (e.g. rating, minimum).
Finally, a few commenters noted that this requirement is structured unlike other conventional
NERC standard requirements in that it does not say what must be accomplished for reliability
(and compliance) but rather says what must NOT be done.
The SDT considered these comments and determined that two of these were significant enough
to change the standard and have combined the outage requirements (R5, R6, R7 and R8) with
this encroachment requirement (R4), with one combined Requirement for IROLs/Major WECC
Transfer Paths and another combined Requirement for all other lines. A broadened Force
Majeure section was added to the applicability section of the standard. Additionally, the new R1
and R2 in this Draft were reworded to describe what must be done.
Draft 3: March 1, 2010
9
FAC-003-2 — Transmission Vegetation Management
Question 7
In response to industry comments, the Requirement for preventing Sustained Outages due to
blowing together of vegetation and transmission line conductors was developed. Additionally the
SDT assigned Time Horizons, Violation Risk Factors, and Violation Severity Levels. Do you
agree? If not, please explain and propose an alternative.
Second draft of proposed R7:
R7. Each Transmission Owner shall prevent Sustained Outages of applicable lines due to the
blowing together of vegetation and a conductor within an Active Transmission Line Right
of Way (operating within design blow-out conditions) with the following exception:
[Violation Risk Factor – Medium][Time Horizon – Real Time]
Sustained Outages of applicable lines that result from natural disasters or wind-blown
debris.
Summary Consideration: Approximately 70% of the respondents agreed with Requirement
R7. Among the commenters who disagreed, a major comment issue pertains to the definition of
the Active Transmission Line ROW which is further split into two sub issues.
The first sub issue relates to a desire for a more descriptive definition of Active ROW.
The other sub issue suggests the elimination of Active ROW.
A minority comment area pertains to altering the requirement to become more performance
based with a graduated set of VSLs.
The SDT believes that the definition of “active transmission right-of-way” is appropriate for
meeting the objectives of the Standard. This topic is addressed in the Guideline and Technical
Basis section of this of FAC-003-2 Draft 3. The SDT considered the other comments and
determined that two of these were significant enough to change the standard - the SDT combined
the outage requirements (R5, R6, R7 and R8) with this encroachment requirement (R4), with one
combined Requirement for IROLs/Major WECC Transfer Paths and another combined
Requirement for all other lines. A broadened Force Majeure section was added to the
applicability section of the standard. Additionally, the new R1 and R2 in this Draft were
reworded to describe what must be done.
Draft 3: March 1, 2010
10
FAC-003-2 — Transmission Vegetation Management
Question 8
In response to industry comments, the Requirement for preventing Sustained Outages due to fallins of vegetation was developed. Additionally the SDT assigned Time Horizons, Violation Risk
Factors, and Violation Severity Levels. Do you agree? If not, please explain and propose an
alternative.
Second draft of proposed R8:
R8. Each Transmission Owner shall prevent Sustained Outages of applicable lines due to
vegetation falling into a conductor from within an Active Transmission Line Right of Way
with the following exceptions: [Violation Risk Factor – Medium] [Time Horizon – Real
Time]
Sustained Outages of applicable lines that result from natural disasters or wind-blown
debris.
Sustained Outages of applicable lines that result from human or animal activity.
Summary Consideration: Approximately 78% of the respondents agreed with the Requirement
R8. Among the commenters who disagree, a major comment pertains to the definition of Active
Transmission Line ROW which is further split up into two sub issues.
The first sub issue relates to a desire for a more descriptive/quantitative definition of the
Active Transmission Line ROW.
The other sub issue suggests the elimination of Active Transmission Line ROW.
A minority comment area pertains to altering the requirement to become more performance
based with a graduated set of VSL’s.
The SDT believes that the definition of “active transmission right-of-way” is appropriate for
meeting the objectives of the Standard. This topic is addressed in the Guideline and Technical
Basis section of FAC-003-2 Draft 3. The SDT considered the other comments and determined
that two of these were significant enough to change the standard and have combined the outage
requirements (R5, R6, R7 and R8) with this encroachment requirement (R4), with one combined
Requirement for IROLs/Major WECC Transfer Paths and another combined Requirement for all
other lines. A broadened Force Majeure section was added to the applicability section of the
standard. Additionally, the new R1 and R2 in this Draft were reworded to describe what must be
done.
Draft 3: March 1, 2010
11
FAC-003-2 — Transmission Vegetation Management
Question 9
In response to industry comments, the Requirement for implementation of annual work plan was
developed. Additionally the SDT assigned Time Horizons, Violation Risk Factors, and Violation
Severity Levels. Do you agree? If not, please explain and propose an alternative.
Second draft of proposed R9:
R9. Each Transmission Owner shall implement its annual work plan for vegetation
management to accomplish the purpose of this standard. [Violation Risk Factor – Medium]
[Time Horizon – Operations Planning]
Summary Consideration: A majority of commenters requested the restoration of the phrase
“subject to legal rights,” citing that doing so would improve the ability of TO’s in expediting
approvals for access. A few comments objected to the phrase “to accomplish the purpose of the
standard” citing it was superfluous. A minority of comments pertained to the extent and effect of
the phrase “within the year”. Commenters pointed out that carryover work into the next year is
not possible with the requirement 1.3 as written.
In response to overwhelming industry comments from the first posting of the draft standard, the
SDT removed the words “within the extent of its easements and/or legal rights”. The concern
expressed by the first commenters pertained to avoiding the situation where the expectation is for
the transmission Owner to exercise its fullest legal rights when not needed. The SDT did remove
the two phrases for clarity and in keeping with the guidelines for this new form of standard
development. And sections 1.3.3 and 1.3.4 which were subject to misinterpretation have been
removed.
Draft 3: March 1, 2010
12
FAC-003-2 — Transmission Vegetation Management
Question 10
In response to industry comments, the Requirement for the preparation of list for sub 200kV
transmission lines by the Planning Coordinator was developed. Additionally the SDT assigned
Time Horizons, Violation Risk Factors, and Violation Severity Levels. Do you agree? If not,
please explain and propose an alternative.
Second draft of proposed R10:
R10.
Each Planning Coordinator shall prepare and review annually, a list of
lines that are operated below 200kV, if any, which are subject to this standard. Each
Planning Coordinator shall consult with its Transmission Owner(s) and neighboring
Planning Coordinators to obtain input to develop the list. [Violation Risk Factor – Lower]
[Time Horizon – Long-term Planning]
Summary Consideration: An overwhelming majority of respondents agreed with this
requirement as found in the second draft. For those commenters that disagreed with the
requirement, three concepts arose. First, some commenters note that a similar identification of
important circuit exists in FAC-014 and as such this requirement is unnecessary. The second
issue expressed involves the interaction between the TO and the PC. There was concern that the
word “consult” was ambiguous and that the mere preparation of the list did not ensure that the
TO would be provided the list. The last group opined that this requirement for the actual
preparation of the list could be combined with the requirement to establish a methodology (R11)
since either one is toothless without the other.
After reviewing these comments as well as a complete analysis of Draft 2 with respect to the
guidelines for this new results-based standard development process, the Requirements dealing
with the Planning Coordinator have been removed. For sub-200 kV lines, the applicability will
derive from identification of Transmission Lines associated with IROLs or as Major WECC
Transfer Paths - analysis already exists for both of these.
Draft 3: March 1, 2010
13
FAC-003-2 — Transmission Vegetation Management
Question 11
In response to industry comments, the Requirement for the Planning Coordinator to document
method for identification of applicable sub-200kV transmission lines was developed.
Additionally the SDT assigned Time Horizons, Violation Risk Factors, and Violation Severity
Levels. Do you agree? If not, please explain and propose an alternative.
Second draft of proposed R11:
R11. Each Planning Coordinator shall develop and document its method for assessing the
reliability significance of sub-200kV transmission lines whose loss would place the grid at
an unacceptable risk of instability, separation, or cascading failures. [Violation Risk Factor
– Lower] [Time Horizon – Long-term Planning]
Summary Consideration: An overwhelming majority of respondents agreed with this
requirement as found in the second draft. For those commenters that disagreed with the
requirement the most common concern was that a similar identification of important circuit
exists in FAC-014 and as such this requirement is unnecessary or duplicative. Two minor
opinions also arose, one that all lines should be included in this standard, regardless of voltage,
the other that no lines operating at voltage less than 200kV should be included.
After reviewing these comments as well as a complete analysis of Draft 2 with respect to the
guidelines for this new results-based standard development process, the Requirements dealing
with the Planning Coordinator have been removed. For sub-200 kV lines, the applicability will
derive from identification of Transmission Lines associated with IROLs or as Major WECC
Transfer Paths - analysis already exists for both of these.
Draft 3: March 1, 2010
14
FAC-003-2 — Transmission Vegetation Management
Question 12
The SDT received suggestions from commenters to re-sequence the requirements contained in
the standard to improve the logical flow of this document. The SDT submits for consideration a
proposed alternative sequence. Do you agree with the proposed alternative sequencing? If not,
please recommend a suggested sequence.
Summary Consideration: With only one exception, every commenter agreed that some resequencing was logical and appropriate. All others that disagreed with the SDT proposal
included alternative sequences.
The SDT has rewritten the Requirements and re-sequenced those remaining by Results-based type requirements, i.e., competency-based, risk-based, or performance-based.
Draft 3: March 1, 2010
15
FAC-003-2 — Transmission Vegetation Management
Question 13
The Implementation Plan proposes an effective date that gives entities at least a year to become
fully compliant. Do you agree with this implementation plan? If not, please indicate what
should be changed and indicate why.
Summary Consideration: Most commenters felt that the proposed implementation was
acceptable. However, a sizable number found this proposed Revision to be far superior to the
current in-force standard and would like the SDT to consider options to expedite the
implementation. One commenter indicated they would need more time.
The SDT has chosen to retain the implementation plan, rather than attempt an expedited
schedule, with FAC-003-2 Draft 3.
Draft 3: March 1, 2010
16
FAC-003-2 — Transmission Vegetation Management
Question 14
Do you have further questions about the standard that the Technical Reference document (White
Paper) does not clear up? If so, please elaborate and propose additions.
Summary Consideration: The most prevalent comment requested revisions to the Diagrams to
eliminate trees in impermissible areas. Another popular comment dealt with a change to the
Active Transmission Line Right of Way. Some commenters wanted the SDT to address the
Generator Interconnection Facility (GIF) issue. And finally, a few commenters wanted a change
in the phrase “operating range” and in an expanded Force Majeure section.
The SDT will modify the Drawings as requested and they will be provided in the Technical
Reference Document which is planned to be posted on March 23rd 2010.
The SDT slightly modified the definition of Active Transmission Line Right of Way as shown:
Active Transmission Line Right of Way — A strip or corridor of land that is occupied by
active Transmission facilities. This corridor does not include the parts of the Right-of-Way that
are unused or intended for other facilities.
The SDT is aware of the GIF issue, i.e. 200 kV, and above, circuits owned by Generator Owners
which have in some instances been considered Transmission Lines. NERC created a team to
address this issue for all NERC standards. The product of that team was a report of suggested
changes that will be addressed by a NERC drafting team. As such this draft of FAC-003 does not
include any of those recommendations as they may apply to this standard.
The phrase “operating range” has been re-written to use all NERC terms and a general Force
Majeure section has been added to the applicability section of the standard.
Draft 3: March 1, 2010
17
FAC-003-2 — Transmission Vegetation Management
Question 15
In response to industry comments, the applicability section is revised to replace Reliability
Coordinator with Planning Coordinator. Do you agree with these changes? If not, please explain
and propose an alternative.
Summary Consideration: The vast majority of commenters agreed the Planning Coordinator
was the appropriate entity. A common concern of those who disagreed was that the Planning
Coordinator role is not defined, not well defined, or duplicated in practice. (The SDT believes
that this is registration/Functional Model problem not suited for resolution in this standard.) Only
one commenter suggested the Reliability Coordinator was more appropriate for technical
reasons, opining that the Reliability Coordinator was better suited to determine the importance of
lines.
After reviewing these comments as well as a complete analysis of Draft 2 with respect to the
guidelines for this new results-based standard development process, the Requirements dealing
with the Planning Coordinator have been removed. For sub-200 kV lines, the applicability will
derive from identification of Transmission Lines associated with IROLs or as Major WECC
Transfer Paths - analysis already exists for both of these.
Draft 3: March 1, 2010
18
FAC-003-2 — Transmission Vegetation Management
Question 16
In response to industry comments, changes were made to the definitions. Do you agree with
these changes? If not, please explain and propose an alternative.
Definitions proposed with FAC-003-2 Draft 2:
Active Transmission Line Right of Way — A strip of land that is occupied by active
transmission facilities. This corridor does not include the inactive or unused part of the
Right of Way intended for other facilities.
Vegetation Inspection — The systematic examination of vegetation conditions on an
Active Transmission Line Right of Way. This inspection may be combined with a general
line inspection. The inspection includes the documentation of any vegetation that may
pose a threat to reliability prior to the next planned inspection or maintenance work,
considering the current location of the conductor and other possible locations of the
conductor due to sag and sway for rated conditions.
Summary Consideration: A majority of commenters expressed a concern with the Active
Transmission Line ROW definition ranging from unnecessary to requiring modification. Those
who recommended modification cited an issue with the phrase “intended for other facilities”.
The belief is this phrase might preclude certain parts of a ROW from being considered inactive.
A minority comment pertains to the concern of abuse in the application of the concept of Active
Transmission Line ROW.
The SDT has revised the definition to attempt to address some of the concerns and in keeping
with the guidelines for this new results-based standard development process.
Active Transmission Line Right-of-Way
A strip or corridor of land that is occupied by active transmission facilities. This corridor
does not include the parts of the Right-of-Way that are unused or intended for other
facilities.
The majority of commenters held concern with two aspects of Vegetation Inspection definition.
One concern relates to the phrase “poses a threat” and offered the alternative phrase “poses an
unacceptable risk” in its place. The other concern questions the necessity of the last sentence of
the definition which contains “requirement-like” text about documentation. The SDT changed
the definition as shown below:
Vegetation Inspection
The systematic examination of vegetation conditions on an Active Transmission Line
Right-of-Way and may be combined with a general line inspection.
Draft 3: March 1, 2010
19
Summary Consideration of Comments Submitted in Response to Draft 2 of FAC-003-2
Question 17
When compared to Version 1, does this proposed Version 2 of the standard either maintain or
improve overall electric reliability? Please provide a technical basis for your response?
Summary Consideration: The majority of the commenters agreed that Draft 2 improved
reliability. Of those who disagreed, the primary objection was the elimination of Clearance 1 and
removal of the qualification requirement. The commenters cited a reduce leverage with
landowners in the rationale for disagreement. A majority comment insists that the standard ought
to require the application of best management practices. A majority comment insists that the
standard ought to require the application of best management practices.
The SDT thanks the commenters for their support. With this new Draft, the essential concepts in
Draft 2 are retained with wording better suited to the new Results-based standards development
process. The SDT believes that the qualification issue is better left to a SAR team for PER
standards. The SDT considered requiring ANSI A300 as part of this standard but opted to
include it in the Guideline and Technical Basis section.
20
Summary Consideration of Comments Submitted in Response to Draft 2 of FAC-003-2
Question 18
Besides the comments you have already provided for the preceding questions, do you have
further suggestions for improving this standard? If so, please elaborate.
Summary Consideration: Many commenters repeated concerns expressed in other sections.
The most cited items were: the purpose statement, the definition of applicable lines, double
jeopardy for encroachments and outages, the GO/GOP/DP line issue, the necessity for a general
force majeure statement, and the reference to ANSI A300.
The SDT has replaced the purpose statement with an Objective statement retaining the same
concept.
The Applicability section has been revised to address commenters concerns, except relating to
Generator Interconnection Facilities. (Please see response to Question 14.)
The Double Jeopardy concerns were addressed by combining requirements to produce the new
Draft R1 and R2.
A general Force Majeure section was added to the applicability section of the standard that
covers all Requirements. The reference to ANSI 300 has been added to the Guideline and
Technical Basis section.
21
FAC-003-2 — Transmission Vegetation Management
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. SC approved SAR for initial posting (January 11, 2007).
2. SAR posted for comment (January 15–February 14, 2007).
3. SAR posted for comment (April 10–May 9, 2007).
4. SC authorized moving the SAR forward to standard development (June 27, 2007).
Proposed Action Plan and Description of Current Draft
This is the first posting of the proposed revisions to the standard in accordance with ResultsBased Criteria. The drafting team requests posting for a 30-day informal comment period.
Future Development Plan
Anticipated Actions
Anticipated Date
Drafting team considers comments, makes conforming changes, posts April 2010
for 30-day informal comment period.
Drafting team considers comments, makes conforming changes, and
requests SC approval to proceed to formal comment and ballot.
June 2010
Recirculation ballot of standards.
August 2010
Receive BOT approval
September 2010
Draft 3: March 1, 2010
1
FAC-003-2 — Transmission Vegetation Management
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Active Transmission Line Right-of-Way
A strip or corridor of land that is occupied by active
transmission facilities. This corridor does not
include the parts of the Right-of-Way that are
unused or intended for other facilities.
Examples of active portions of corridors
include:
The width of any Active Transmission Line Right-ofWay (ROW) is the portion of the ROW that has been
cleared of vegetation to meet design clearance
requirements such as National Electrical Safety Code or
other design criteria, for the reliable operation of active
facilities.
Examples of inactive portions of corridors
include:
1) The portions of the ROW acquired to
accommodate future Facilities. Power plant
exits are examples where large ROWs are
obtained for maximum corridor utilization and
may currently have fewer circuits constructed.
2) The portion of the ROW where corridor edge
zones are designated by regulatory bodies for
vegetation to exist.
3) The portions of the ROW where double-circuit
structures are installed but only one circuit is
currently strung with conductors.
Vegetation Inspection
The systematic examination of vegetation conditions on
an Active Transmission Line Right-of-Way which may
be combined with a general line inspection.
The current glossary definition of this NERC term
is modified to allow both maintenance inspections
and vegetation inspections to be performed
concurrently.
Current definition of Vegetation Inspection: The
systematic examination of a transmission corridor
to document vegetation conditions.
Draft 3: March 1, 2010
2
FAC-003-2 — Transmission Vegetation Management
Effective Dates
Requirement
Jurisdiction
Alberta
British
Columbia
Manitoba
New
Brunswick
Newfoundland
Nova
Scotia
Ontario
Quebec
Saskatchewan
USA
R1
1
1
1
3
TBD
TBD
2
TBD
1
1
R2
1
1
1
3
TBD
TBD
2
TBD
1
1
R3
1
1
1
3
TBD
TBD
2
TBD
1
1
R4
1
1
1
3
TBD
TBD
2
TBD
1
1
R5
1
1
1
3
TBD
TBD
2
TBD
1
1
R6
1
1
1
3
TBD
TBD
2
TBD
1
1
R7
1
1
1
3
TBD
TBD
2
TBD
1
1
1. First calendar day of the first calendar quarter one year after applicable regulatory authority approval for all requirements
2. First calendar day of the first calendar quarter one year following Board of Trustees adoption unless governmental authority
withholds approval
3. First calendar day of the first calendar quarter that is at least one year following Board of Trustees adoption
Exceptions:
Lines operated below 200kV, designated by the Planning Coordinator as an element of an IROL or as a Major WECC
transfer path, become subject to this standard 12 months after the date the Planning Coordinator or WECC initially
designates the lines as being subject to this standard.
An existing transmission line operated at 200kV or higher that is newly acquired by an asset owner and was not previously
subject to this standard, becomes subject to this standard 12 months after the acquisition date of the line(s).
Draft 3: March 1, 2010
3
FAC-003-2 — Transmission Vegetation Management
Version History
Version
1
Date
TBA
Action
1. Added “Standard Development
Roadmap.”
Change Tracking
01/20/06
2. Changed “60” to “Sixty” in section
A, 5.2.
3. Added “Proposed Effective Date:
April 7, 2006” to footer.
4. Added “Draft 3: November 17,
2005” to footer.
1
2
April 4, 2007
Draft 3: March 1, 2010
Regulatory Approval — Effective Date
New
4
FAC-003-2 — Transmission Vegetation Management
Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-2
3.
To improve the reliability of the electric Transmission system by
preventing those vegetation related outages that could lead to Cascading.
Objectives:
4. Applicability
4.1. Functional Entities:
4.1.1 Transmission Owners
4.2. Facilities: Defined below, including but not limited to those that cross lands owned by
federal 1 , state, provincial, public, private, or tribal entities:
4.2.1. Overhead transmission lines operated at 200kV or higher.
4.2.2. Overhead transmission lines operated below 200kV having been identified as
elements of an Interconnection Reliability Operating Limit (IROL).
4.2.3. Overhead transmission lines operated below 200 kV having been identified as
included in the definition of one of the Major WECC Transfer Paths in the Bulk
Electric System.
4.2.4. This Standard does not apply to Facilities identified above (4.2.1 through 4.2.3)
located in the fenced area of a switchyard, station or substation.
4.3.
Other:
4.3.1. This Standard does not apply to any occurrence, non-occurrence, or other set of
circumstances that are beyond the reasonable control of a Transmission Owner
subject to this Reliability Standard, and are not caused by the fault or negligence
of the Transmission Owner, including acts of God, flood, drought, earthquake,
major storms, fire, hurricane, tornado, landslides, logging activities, animals
severing trees, lightning, epidemic, strike, war, riot, civil disturbance, sabotage,
vandalism, terrorism, wind shear, or fresh gales that restricts or prevents
performance to comply with this reliability standard’s requirements.
5.
Background
This NERC Vegetation Management Standard (“Standard”) uses a defense-in-depth
approach to improve the reliability of the electric Transmission System by preventing
those vegetation related outages that could lead to Cascading. This Standard is not
intended to address non-preventable outages such as those due to vegetation fall-ins
from outside the Active Transmission Line Right-of-Way, vandalism, human errors
1
EPAct 2005 section 1211c: “Access approvals by Federal agencies”.
Draft 3: March 1, 2010
5
FAC-003-2 — Transmission Vegetation Management
and acts of nature. Operating experience indicates that trees that have grown out of
specification have contributed to Cascading, especially under heavy electrical loading
conditions.
Major outages and operational problems have resulted from interference between
overgrown vegetation and transmission lines located on many types of lands and
ownership situations. Adherence to the Standard requirements for applicable lines on
any kind of land or easement, whether they are Federal Lands, state or provincial
lands, public or private lands, franchises, easements or lands owned in fee, will
reduce and manage this risk. For the purpose of the Standard the term “public lands”
includes municipal lands, village lands, city lands, and a host of other governmental
entities.
This Standard addresses vegetation management along applicable overhead lines that
serve to connect one electric station to another. However, this Standard does not
apply to underground lines or to line sections inside an electric station boundary.
This Standard focuses on transmission lines to prevent those vegetation related
outages that could lead to Cascading. It is not intended to prevent customer outages
due to tree contact with lower voltage distribution system lines. For example,
localized customer service might be disrupted if vegetation were to make contact with
a 69kV transmission line supplying power to a 12kV distribution station. However,
this Standard is not written to address such isolated situations which have little impact
on the overall Bulk Electric System.
Since vegetation growth is constant and always present, unmanaged vegetation poses
an increased outage risk, especially when numerous transmission lines are operating
at or near their Rating. This can present a significant risk of multiple line failures and
Cascading. Conversely, most other outage causes (such as trees falling into lines,
lightning, animals, motor vehicles, etc.) are statistically intermittent. These events are
not any more likely to occur during heavy system loads than any other time. There is
no cause-effect relationship which creates the probability of simultaneous occurrence
of other such events. Therefore these types of events are highly unlikely to cause
large-scale grid failures. Thus, this Standard’s emphasis is on vegetation grow-ins.
Draft 3: March 1, 2010
6
FAC-003-2 — Transmission Vegetation Management
Requirements and Measures
R1. Each Transmission Owner shall prevent
vegetation from encroaching within the
Minimum Vegetation Clearance Distance
(MVCD) of each line conductor that is
identified as an element of an Interconnection
Reliability Operating Limit (IROL) or Major
Western Electricity Coordinating Council
(WECC) transfer path (operating within
Rating and Rated Electrical Operating
Conditions) to avoid a Sustained Outage.
Rationale
The MVCD is a calculated minimum
distance stated in feet (meters) to prevent
spark-over between conductors and
vegetation, for various altitudes and
operating voltages. The distances in Table 2
were derived using a proven transmission
design method.
M1. Evidence of violation of Requirement R1 is limited to:
Real-time observation of encroachment into the MVCD, or
A vegetation-related Sustained Outage due to a fall-in from inside the Active
Transmission Line ROW, or
A vegetation-related Sustained Outage due to blowing together of applicable
lines and vegetation located inside the Active Transmission Line ROW, or
A vegetation-related Sustained Outage due to a grow-in.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a
24-hour period.
R2.
Each Transmission Owner shall prevent
vegetation from encroaching within the
MVCD of each applicable line conductor,
which are not elements of an IROL and are
not a Major WECC transfer path, (operating
within Rating and Rated Electrical Operating
Conditions) to avoid a Sustained Outage.
Rationale
The MVCD is a calculated minimum
distance stated in feet (meters) to prevent
spark-over between conductors and
vegetation, for various altitudes and
operating voltages. The distances in Table
2 were derived using a proven
Transmission design method.
M2. Evidence of violation of Requirement R2
is limited to:
Real-time observation of encroachment into the MVCD, or
A vegetation-related Sustained Outage due to a fall-in from inside the Active
Transmission Line ROW, or
A vegetation-related Sustained Outage due to blowing together of applicable
lines and vegetation located inside the Active Transmission Line ROW, or
A vegetation-related Sustained Outage due to a grow-in.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a
24-hour period.
Draft 3: March 1, 2010
7
FAC-003-2 — Transmission Vegetation Management
R3. Each Transmission Owner shall have a
documented transmission vegetation
management program that describes how it
conducts work on its Active Transmission
Line ROWs to avoid Sustained Outages due
to vegetation, considering all possible
locations the conductor may occupy
assuming operation within Rating and Rated
Electrical Operating Conditions.
Rationale
Provide a basis for evaluation on the intent
and competency of the Transmission Owner
in maintaining vegetation. There may be
many acceptable approaches to maintain
clearances. However, the Transmission
Owner should be able to state what its
approach is and how it conducts work to
maintain clearances. See Figure 1 for an
illustration of possible conductor locations.
M3. Each Transmission Owner has a
documented transmission vegetation
management program that describes
how it conducts work on its Active Transmission Line ROW to avoid Sustained
Outages due to vegetation, considering all possible locations the conductor may
occupy assuming operation within Rating and Rated Electrical Operating Conditions.
R4. Each Transmission Owner shall notify the
responsible control center when it has
verified knowledge of a vegetation
imminent threat condition. A vegetation
imminent threat condition is one which is
likely to cause a Sustained Outage at any
moment.
Rationale
To ensure rapid notification of the correct
personnel when an occurrence of a critical
situation is observed. Verified knowledge
includes observations by journeyman lineman,
utility arborist, or other qualified personnel, or a
report verified by these personnel.
M4. Each Transmission Owner that has
experienced a verified vegetation
imminent threat will have evidence
that it notified the responsible control
center.
Draft 3: March 1, 2010
8
FAC-003-2 — Transmission Vegetation Management
R5. Each Transmission Owner shall take
interim corrective action when it is
temporarily constrained from performing
planned vegetation work, where a
transmission line is put at potential risk
due to the constraint.
M5. Each Transmission Owner has
evidence of the interim corrective
action taken for each temporary
constraint where a transmission line
was put at potential risk. Examples
of acceptable forms of evidence may
include work orders, invoices, or
inspection records.
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
Transmission Owner from performing
planned vegetation maintenance work.
When this event occurs and the work is
essential to avoid risk to the transmission
line the Transmission Owner must establish
and act on a plan to prevent an imminent
threat. This is not intended to address
situations where a planned work
methodology cannot be performed but an
alternate work methodology can be used.
R6. Each Transmission Owner shall perform a
Vegetation Inspection of all applicable
transmission lines at least once per calendar
year.
M6. Each Transmission Owner has evidence that it
conducted Vegetation Inspections at least once per
calendar year for applicable transmission lines.
Examples of acceptable forms of evidence may
include work orders, invoices, or inspection records.
R7. Each Transmission Owner shall execute a
flexible annual vegetation work plan to ensure
no vegetation encroachments occur within the
MVCD.
M7. Each Transmission Owner has evidence
that it executed a flexible annual
vegetation work plan. Examples of
acceptable forms of evidence may include
work orders, invoices, or inspection
records.
Draft 3: March 1, 2010
Rationale
The requirement is for once per calendar
year because that seems to be reasonable
length of time for a majority of situations.
Transmission Owners should consider
local and environmental factors that could
warrant more frequent inspections that
may affect reliability.
Rationale
This requirement sets the expectation that
the work identified in the annual work
plan will be completed as planned. A
flexible annual vegetation work plan
allows for work to be deferred into the
following calendar year provided it does
not have the potential to become an
imminent threat.
9
FAC-003-2 — Transmission Vegetation Management
Compliance
Compliance Enforcement Authority
Regional Entity
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
Evidence Retention
The Transmission Owner retains data or evidence of Requirements R1 through R7, Measures
M1 through M7 for three years to show compliance unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a Transmission Owner is found non-compliant, it shall keep information related to the noncompliance until found compliant.
The Compliance Enforcement Authority shall keep the last audit records and all requested
and submitted subsequent audit records.
Additional Compliance Information
(See Administrative Procedure)
Draft 3: March 1, 2010
10
FAC-003-2 — Transmission Vegetation Management
Time Horizons, Violation Risk Factors, and Violation Severity Levels
Table 1
R#
R1
R2
R3
Time
Horizon
Real-time
Real-time
Long-Term
Planning
VRF
Violation Severity Level
Lower
High
Medium
Lower
Draft 3: March 1, 2010
Moderate
High
Severe
The Transmission Owner
failed to prevent vegetation
from encroaching within the
MVCD of a transmission
line as described in R1.
The Transmission Owner
incurred a Sustained
Outage due to vegetation
falling into a transmission
line as described in R1
from within the Active
Transmission Line ROW.
The Transmission Owner
incurred a Sustained Outage
due to the blowing together of
vegetation and a transmission
line as described in R1 from
within the Active
Transmission Line ROW.
The Transmission Owner
incurred a Sustained Outage due
to vegetation growing into a
transmission line as described in
R1.
The Transmission Owner
failed to prevent vegetation
from encroaching within the
MVCD of a transmission
line as described in R2.
The Transmission Owner
incurred a Sustained
Outage due to vegetation
falling into a transmission
line as described in R2
from within the Active
Transmission Line ROW.
The Transmission Owner
incurred a Sustained Outage
due to the blowing together of
vegetation and a transmission
line as described in R2 from
within the Active
Transmission Line ROW.
The Transmission Owner
incurred a Sustained Outage due
to vegetation growing into a
transmission line as described in
R2.
The Transmission Owner
has a documented
transmission vegetation
management program, but
the transmission vegetation
management program does
not describe how work is
conducted on the Active
Transmission Line ROWs
to avoid Sustained Outages
due to vegetation.
The Transmission Owner has
a documented transmission
vegetation management
program, but the transmission
vegetation management
program does not consider all
possible locations the
conductor may occupy
assuming operation within
Rating and Rated Electrical
Operating Conditions
The Transmission Owner does
not have a documented
transmission vegetation
management program.
11
FAC-003-2 — Transmission Vegetation Management
R4
R5
R6
R7
Real-time
Operations
Planning
Operations
Planning
Operations
Planning
The Transmission Owner had
verified knowledge of a
vegetation imminent threat
condition and did not notify the
responsible control center.
Medium
The Transmission Owner did not
take interim corrective action
when it was temporarily
constrained from performing
planned vegetation work where
an applicable transmission line
was put at potential risk.
Medium
High
The Transmission Owner
inspected greater than 95%
but less than 100% of the
ROW as measured by
applicable-line miles
(kilometers) (based on units
of choice: circuit, pole line,
ROW, etc.).
The Transmission Owner
inspected greater than 90%
but less than or equal to
95% of the ROW as
measured by applicable-line
miles (kilometers) (based
on units of choice: circuit,
pole line, ROW, etc.).
The Transmission Owner
inspected greater than 85%
but less than or equal to 90%
of the ROW as measured by
applicable-line miles
(kilometers) (based on units
of choice: circuit, pole line,
ROW, etc.).
The Transmission Owner
inspected less than or equal to
85% of the ROW as measured by
applicable-line miles
(kilometers) (based on units of
choice: circuit, pole line, ROW,
etc.).
High
The Transmission Owner
executed greater than 95%
but less than 100% of its
annual work plan as
adjusted.
The Transmission Owner
executed greater than 90%
but less than or equal to
95% of its annual work
plan as adjusted.
The Transmission Owner
executed greater than 85%
but less than or equal to 90%
of its annual work plan as
adjusted.
The Transmission Owner
executed less than or equal to
85% of its annual work plan as
adjusted.
Draft 3: March 1, 2010
12
FAC-003-2 — Transmission Vegetation Management
Administrative Procedure
The Transmission Owner will submit a quarterly report to its Regional Entity, or the Regional
Entity’s designee, identifying all Sustained Outages of transmission lines determined by the
Transmission Owner to have been caused by vegetation that includes, as a minimum, the
following:.
The name of the circuit(s), the date, time and duration of the outage; the voltage of the
circuit; a description of the cause of the outage; the category associated with the
Sustained Outage; other pertinent comments; and any countermeasures taken by the
Transmission Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation growing into
applicable transmission lines, that are identified as an element of an IROL or
Major WECC Transfer Path, by vegetation inside and/or outside of the Active
Transmission Line ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation growing into
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, by vegetation inside and/or outside of the Active
Transmission Line ROW;
o Category 2 — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines from within the Active Transmission Line ROW;
o Category 2 4 — Blowing together: Sustained Outages caused by vegetation and
applicable transmission lines blowing together from within the Active
Transmission Line ROW.
The Regional Entity will report the outage information provided by Transmission Owners, as per
the above, quarterly to NERC, as well as any actions taken by the Regional Entity as a result of
any of the reported Sustained Outages.
Variances
None.
Interpretations
None.
2
Category 3 reporting is eliminated.
Draft 3: March 1, 2010
13
FAC-003-2 — Transmission Vegetation Management
Guideline and Technical Basis
Requirements R1 and R2:
Requirements R1 and R2 state that if a Transmission Owner observes vegetation within the
distances prescribed in FAC-003 - Table 2 it is in violation of this Standard. The MVCD table
contains the distances which are required to ensure that spark-over will not occur; the distances
are based on the Gallet equations. Requirements R1 and R2 refer to observation in “real time”.
This means an actual field observation or measurement of the conductor-to-vegetation distance
and not a calculated determination of relative positions.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will help prevent transmission outages. The
movement of the transmission line conductor and the MVCD is illustrated in Figure 1 below.
Figure 1
Cross-section view of a single conductor at a given point along the span showing six possible conductor positions
due to movement resulting from thermal and mechanical loading.
By complying with encroachment-prevention Requirements R1 and R2, together with the
competency-based Requirement R3 (for a documented transmission vegetation management
program), the Transmission Owner will have a cohesive vegetation management program for
managing vegetation in such a manner as to maintain separation between conductors and
vegetation. Additionally, an effective imminent threat process and interim corrective action plan
strategies should be executed to be successful in meeting these requirements. The Transmission
Owner’s maintenance approach should result in vegetation never approaching the distances listed
Draft 3: March 1, 2010
14
FAC-003-2 — Transmission Vegetation Management
in the MVCD Table. However, brief encroachments by falling vegetation are not considered to
be a violation.
In addition, the Transmission Owner should maintain detailed records of the findings of its
planned inspections. This documentation constitutes evidence that the Transmission Owner had
no encroachments into the MVCD Table distances.
These requirements assume that transmission lines are operating within their Rating. If a line
conductor is intentionally or inadvertently operated beyond its rating (potentially in violation of
other standards), the occurrence of a clearance encroachment is not be a violation of this
Standard. Conductor position, and the associated vegetation distance, that result from operation
of a transmission line beyond its Rating (for example emergency actions taken by a TOP or RC
to protect an Interconnection) is beyond the scope of this Standard.
Requirement R3:
An adequate transmission vegetation management program formally establishes the guidelines
that are used by the Transmission Owner to plan and perform vegetation work that is necessary
to prevent transmission outages and minimize risk to the Transmission System.
There may be many acceptable approaches to maintain clearances. However, the Transmission
Owner should be able to state what its approach is and how it conducts work to maintain
clearances. See Figure 1 for illustration of possible conductor locations.
Requirement R4:
The term “verified knowledge” implies reliable confirmation that an imminent threat actually
exists due to vegetation. Verification could be that the initial call-in came from a trained
employee able to identify such a threat or it could be verified by sending out such a trained
person to confirm a call-in from a citizen.
Two key elements of an acceptable imminent threat procedure are outlined below:
Specify the vegetation-related conditions that warrant a response:
Examples of these vegetation-related conditions include vegetation that is near or
encroaching into the MVCD (growth issue) or vegetation that presents an imminent
danger of falling into the transmission conductor (fall-in issue)
Notify the appropriate operating authority:
The Transmission Owner has the responsibility to ensure the proper communication
between field personnel and the operating authority to allow the operating authority to
take the appropriate action until the threat is relieved. Appropriate actions may include a
temporary reduction in the line loading or switching the line out of service.
The protocol for contacting the operating authority should be defined. Some
Transmission Owners’ processes may require a call directly to the operating authority,
while other Transmission Owners may require a call to a supervisor or field forester who
will in turn notify the proper operating authority.
Draft 3: March 1, 2010
15
FAC-003-2 — Transmission Vegetation Management
The term “responsible control center” refers to personnel with direct responsibility for
operating the transmission lines, such as the Transmission Owner’s control center, an
Independent System Operator, or other operating entity. In the case where the operating
authority is not the Transmission Operator the communication between the Transmission
Operator and the operating authority will occur by the normal policies that govern their
relationship.
The imminent threat process should be implemented in terms of minutes or hours as opposed to a
longer time frame for interim corrective action plans (see R5).
All serious growth or fall-in vegetation-related conditions are not necessarily considered
imminent threats under this Standard. For example, some Transmission Owners may have a
danger tree identification program that identifies for removal trees with the potential to fall near
the line. These trees are not necessarily considered imminent threats under the Standard unless
they pose an immediate fall-in threat.
There can be situations involving vegetation that are not considered vegetation-related imminent
threats under this Standard. For example, a logging operation on or near the Active
Transmission Line ROW can pose an immediate threat of a sustained outage and result in the
initiation of an imminent threat process in the same manner as the presence of a nearby crane or
the notification of a hot-spot on a conductor connector. Although the logging threat in this
example tangentially involves vegetation, it is not considered a vegetation-related imminent
threat under the Standard.
Requirement R5:
The intent of this requirement is to deal with situations that prevent the Transmission Owner
from performing planned vegetation management work and, as a result, have the potential to put
the transmission line at risk. Constraints to performing vegetation maintenance work as planned
could result from legal injunctions filed by property owners, the discovery of easement
stipulations which limit the Transmission Owner’s rights, or other circumstances.
This requirement is not intended to address situations where the transmission line is not at
immediate risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
Transmission Owner is not under any immediate time constraint for achieving the management
objective, can easily reschedule work using an alternate approach, and therefore does not need to
take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the Transmission Owner is required to take an interim corrective action to mitigate the potential
risk to the transmission line. A wide range of actions can be taken to address various situations.
General considerations include:
Draft 3: March 1, 2010
16
FAC-003-2 — Transmission Vegetation Management
Identifying locations where the Transmission Owner is constrained from performing
planned vegetation maintenance work which potentially leaves the transmission line at
risk.
Developing the specific action to immediately mitigate any potential risk associated with
not performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for each location.
In developing the specific action to mitigate the potential risk to the transmission line the
Transmission Owner could consider location specific measures such as modifying the inspection
and/or maintenance intervals. Where a legal constraint would not allow any vegetation work, the
interim corrective action could include limiting the loading on the transmission line.
The Transmission Owner should document and track the specific corrective action taken at each
location. This location may be indicated as one span, one tree or a combination of spans on one
property where the constraint is considered to be temporary.
Requirement R6:
This requirement sets a minimum time period for the Vegetation Inspections. More frequent
inspections may be needed to maintain reliability levels, depending upon such factors as
anticipated growth rates of the local vegetation, length of the growing season for the
geographical area, limited Active Transmission ROW width, and rainfall amounts. Therefore
some lines may be designated with a higher frequency of inspections.
The VSL for Requirement R6 has VSL categories ranked by the percentage of the required ROW
inspections completed. To calculate the percentage of inspection completion the Transmission
Owner lines may choose units such as: line miles or kilometers, circuit miles or kilometers, pole
line miles, ROW miles, etc.
If a Transmission Owner operates 2,000 miles of 230 kV transmission lines this Transmission
Owner will be responsible for inspecting all 2,000 miles of 230 kV transmission at least once
line during the calendar year. If one of the included lines was 100 miles long, and if it was not
inspected during the year, then the amount inspected would be 1900/2000 = 0.95 or 95%. The
“Lower VSL” for R6 would apply in this example.
The standard allows Vegetation Inspections to be performed in conjunction with general line
inspections as per the definition.
Requirement R7:
Documentation or other evidence of the work performed typically consists of signed-off work
orders, signed contracts, printouts from work management systems, spreadsheets of planned
versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence
may include photographs, work inspection reports and walk-through reports.
Documentation is required when the annual work plan is adjusted or not completely
implemented as originally planned. The reasons for the deferrals or changes and the expected
completion date of postponed work should be documented.
Draft 3: March 1, 2010
17
FAC-003-2 — Transmission Vegetation Management
The flexibility to adjust the annual work plan must always ensure the reliability of the electric
Transmission system. Flexibility is meant to address changing conditions of the vegetation on
the Active Transmission Line ROW, emergencies, and other significant changing conditions.
This standard requires that the annual work plan be flexible to allow the Transmission Owner to
change priorities during the year as conditions or situations dictate. For example, weather
conditions (drought) could make herbicide application ineffective during the plan year. Another
situational variance could be a major storm that redirects local resources away from planned
maintenance. This situation may also include complying with mutual assistance agreements by
moving resources off the Transmission Owner’s system to work on another system. Examples of
documented adjustments may include deferrals or additions to the annual work plan.
The work plan is not intended to be a “span-by-span” detailed description of all work to be
performed. It is intended to require the Transmission Owner to annually plan and schedule
vegetation work to prevent encroachment into the MVCD.
The Transmission Owner is required to implement the annual work plan for vegetation
management to accomplish the purpose of this standard. This means that vegetation maintenance
ought to be performed to the extent of the Transmission Owner’s easement, fee simple and other
legal rights. It is intended to address the importance of maintaining all locations on the Active
Transmission Line ROWs for reliability purposes in lieu of making special exceptions.
Property owners and other interested parties occasionally request special considerations
to leave undesirable vegetation conditions. Such considerations must never be allowed to
impact reliability.
These undesirable vegetation conditions require more frequent work or inspections than
other locations with similar vegetation threats and similar easement rights which are not
subject to the special property owner requests.
The Transmission Owner's vegetation maintenance work necessary to implement the
annual work plan is most effective when performed to the maximum extent allowed by
any easement, fee simple and other legal rights.
The Transmission Owner should, therefore, endeavor to maintain its Active Transmission
Line ROW to the full extent of its legal rights at all times and in all cases.
A comprehensive approach that exercises the full extent of legal rights is superior to incremental
management in the long term because it reduces overall encroachments, and it ensures that future
planned work and future planned inspection cycles are sufficient at all locations on the Active
Transmission Line ROW .
When developing the annual work plan the Transmission Owner should allow time for
procedural requirements to obtain permits to work on federal, state, provincial, public, tribal
lands. In some cases the lead time for obtaining permits may necessitate preparing work plans
more than a year prior to work start dates. Transmission Owners may also need to consider those
special landowner requirements as documented in easement instruments.
The following conditions may result in adjustments to the annual work plan: abnormal weather
such as drought, major storms, excessive rainfall, other environmental conditions such as
infestation, disease, fire, etc. These conditions may be found as part of a special or scheduled
Draft 3: March 1, 2010
18
FAC-003-2 — Transmission Vegetation Management
Vegetation Inspection. Examples of annual work plan adjustments that are permitted may
include revising the work plan priorities, rescheduling work to another time or selecting alternate
vegetation control methods. Changes in land usage made by a property owner, such as timber
clearing, may be another condition that warrants an adjustment.
Draft 3: March 1, 2010
19
FAC-003-2 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 3
For Alternating Current Voltages
( AC )
Nominal
System
Voltage
(kV)
( AC )
Maximum
System
Voltage
(kV)
765
800
500
550
345
362
230
242
161*
169
138*
145
115*
121
88*
100
69*
72
MVCD
feet
(meters)
sea level
8.06ft
(2.46m)
5.06ft
(1.54m)
3.12ft
(0.95m)
2.97ft
(0.91m)
2ft
(0.61m)
1.7ft
(0.52m)
1.41ft
(0.43m)
1.15ft
(0.35m)
0.82ft
(0.25m)
MVCD
feet
(meters)
3,000ft
(914.4m)
MVCD
feet
(meters)
4,000ft
(1219.2m)
MVCD
feet
(meters)
5,000ft
(1524m)
MVCD
feet
(meters)
6,000ft
(1828.8m)
8.89ft
(2.71m)
5.66ft
(1.73m)
3.53ft
(1.08m)
3.36ft
(1.02m)
2.28ft
(0.69m)
1.94ft
(0.59m)
1.61ft
(0.49m)
1.32ft
(0.40m)
0.94ft
(0.29m)
9.17ft
(2.80m)
5.86ft
(1.79m)
3.67ft
(1.12m)
3.49ft
(1.06m)
2.38ft
(0.73m)
2.03ft
(0.62m)
1.68ft
(0.51m)
1.38ft
(0.42m)
0.99ft
(0.30m)
9.45ft
(2.88m)
6.07ft
(1.85m)
3.82ft
(1.16m)
3.63ft
(1.11m)
2.48ft
(0.76m)
2.12ft
(0.65m)
1.75ft
(0.53m)
1.44ft
(0.44m)
1.03ft
(0.31m)
9.73ft
(2.97m)
6.28ft
(1.91m)
3.97ft
(1.21m)
3.78ft
(1.15m)
2.58ft
(0.79m)
2.21ft
(0.67m)
1.83ft
(0.56m)
1.5ft
(0.46m)
1.08ft
(0.33m)
MVCD
feet
(meters)
7,000ft
(2133.6m)
MVCD
feet
(meters)
8,000ft
(2438.4m)
MVCD
feet
(meters)
9,000ft
(2743.2m)
MVCD
feet
(meters)
10,000ft
(3048m)
MVCD
feet
(meters)
11,000ft
(3352.8m)
10.01ft
(3.05m)
6.49ft
(1.98m)
4.12ft
(1.26m)
3.92ft
(1.19m)
2.69ft
(0.82m)
2.3ft
(0.70m)
1.91ft
(0.58m)
1.57ft
(0.48m)
1.13ft
(0.34m)
10.29ft
(3.14m)
6.7ft
(2.04m)
4.27ft
(1.30m)
4.07ft
(1.24m)
2.8ft
(0.85m)
2.4ft
(0.73m)
1.99ft
(0.61m)
1.64ft
(0.50m)
1.18ft
(0.36m)
10.57ft
(3.22m)
6.92ft
(2.11m)
4.43ft
(1.35m)
4.22ft
(1.29m)
2.91ft
(0.89m)
2.49ft
(0.76m)
2.07ft
(0.63m)
1.71ft
(0.52m)
1.23ft
(0.37m)
10.85ft
(3.31m)
7.13ft
(2.17m)
4.58ft
(1.40m)
4.37ft
(1.33m)
3.03ft
(0.92m)
2.59ft
(0.79m)
2.16ft
(0.66m)
1.78ft
(0.54m)
1.28ft
(0.39m)
11.13ft
(3.39m)
7.35ft
(2.24m)
4.74ft
(1.44m)
4.53ft
(1.38m)
3.14ft
(0.96m)
2.7ft
(0.82m)
2.25ft
(0.69m)
1.86ft
(0.57m)
1.34ft
(0.41m)
3
The distances in this Table are the minimums required to prevent flashover; however prudent vegetation maintenance practices dictate that substantially greater
distances will be achieved at time of vegetation maintenance.
Draft 3: March 1, 2010
20
FAC-003-2 — Transmission Vegetation Management
Table 2 (cont.) — Minimum Vegetation Clearance Distances (MVCD)
For Direct Current Voltages
sea level
MVCD feet
(meters)
3,000ft
(914.4m)
Alt.
MVCD feet
(meters)
4,000ft
(1219.2m)
Alt.
MVCD feet
(meters)
5,000ft
(1524m)
Alt.
MVCD feet
(meters)
6,000ft
(1828.8m)
Alt.
MVCD
feet
(meters)
7,000ft
(2133.6m)
Alt.
MVCD
feet
(meters)
(8,000ft
(2438.4m)
Alt.
MVCD
feet
(meters)
9,000ft
(2743.2m)
Alt.
MVCD
feet
(meters)
10,000ft
(3048m)
Alt.
MVCD
feet
(meters)
11,000ft
(3352.8m)
Alt.
±750
13.92ft
(4.24m)
15.07ft
(4.59m)
15.45ft
(4.71m)
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.9ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
±600
10.07ft
(3.07m)
11.04ft
(3.36m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
(13.54ft
4.13m)
±500
7.89ft
(2.40m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
±400
4.78ft
(1.46m)
5.35ft
(1.63m)
5.55ft
(1.69m)
5.75ft
(1.75m)
5.95ft
(1.81m)
6.15ft
(1.87m)
6.36ft
(1.94m)
6.57ft
(2.00m)
6.77ft
(2.06m)
6.98ft
(2.13m)
±250
3.43ft
(1.05m)
4.02ft
(1.23m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5ft
(1.52m)
5.17ft
(1.58m)
( DC )
Nominal Pole
to Ground
Voltage
(kV)
MVCD feet
(meters)
Draft 3: March 1, 2010
21
Implementation Plan for FAC-003-2
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress
or approved, that must be implemented before this standard can be implemented.
FAC-003-2 — Vegetation Management
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards.
When FAC-003-2 is approved, a new definition for Active Transmission Line Right-of-Way and
a revised definition for Vegetation Inspection should become effective.
The original definition of Vegetation Inspection should be retired when the new definition
becomes effective.
FAC-003-1 will be retired when FAC-003-2 becomes effective.
Compliance with Standard
The standard applies to Transmission Owners.
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Effective Date
The effective date is the date entities are expected to meet the performance identified in this standard. The effective date allows entities time to make
revisions to their existing transmission vegetation management programs to comply with the new requirements.
Requirement
Jurisdiction
Alberta
British
Columbia
Manitoba
New
Brunswick
Newfoundland
Nova
Scotia
Ontario
Quebec
Saskatchewan
USA
R1
1
1
1
3
TBD
TBD
2
TBD
1
1
R2
1
1
1
3
TBD
TBD
2
TBD
1
1
R3
1
1
1
3
TBD
TBD
2
1
1
R4
1
1
1
3
TBD
TBD
2
TBD
1
1
R5
1
1
1
3
TBD
TBD
2
TBD
1
1
R6
1
1
1
3
TBD
TBD
2
TBD
1
1
R7
1
1
1
3
TBD
TBD
2
TBD
1
1
1. First calendar day of the first calendar quarter one year after applicable regulatory authority approval for all requirements
2. First calendar day of the first calendar quarter one year following Board of Trustees adoption unless governmental authority withholds
approval
3. First calendar day of the first calendar quarter that is at least one year following Board of Trustees adoption
Exceptions:
Lines operated below 200kV, designated by the Planning Coordinator as an element of an IROL or as a Major WECC Transfer Path, become
subject to this standard 12 months after the date the Planning Coordinator or WECC initially designates the lines as being subject to this
standard.
An existing transmission line operated at 200kV or higher that is newly acquired by an asset owner and was not previously subject to this
standard, becomes subject to this standard 12 months after the acquisition date of the line(s).
March 1, 2010
2
Mapping of FAC-003-2 Draft 2 to FAC-003-2 Draft 3 (Results-based Standard)
Standard FAC-003-2
Draft 2
Comment
Proposed Standard FAC-003-2 RBS (Draft 3)
Standard Development Roadmap
Modified per proposed
SCPSC format for RBS
Standard Development Timeline
Definitions of Terms Used in Standard
Modified per proposed
SCPSC format for RBS
Definitions of Terms Used in Standard
Effective Dates
Modified per proposed
SCPSC format for RBS. This
section now contains a table
that lists the various
Jurisdictions and their
associated Effective Dates.
Effective Dates
1. Title: Transmission Vegetation Management
No change
1. Title: Transmission Vegetation Management
2. Number: FAC-003-2
No change
2. Number: FAC-003-2
3. Purpose: To improve the reliability of the
electric Transmission system by preventing those
vegetation related outages that could lead to
Cascading.
No change
3. Purpose: To improve the reliability of the electric transmission system by preventing
those vegetation related outages that could lead to Cascading.
4. Applicability:
4.1. Functional Entities:
4.1.1. Transmission Owner
4.1.2. Planning Coordinator
4.2. Facilities:
4.2.1 Transmission lines
(“applicable lines”) operated at
200kV or higher, and
transmission lines operated
below 200kV designated by
the Planning Coordinator as
being subject to this standard
Modified to remove the
Planning Coordinator, to
include Exceptions in 4.2
and revised Facilities to
include only those that meet
specified criterion.
4. Applicability:
4.1.
Functional Entities:
4.1.1
Transmission Owners
4.2.
Facilities: Defined below, including but not limited to those that cross
lands owned by federal 1 , state, provincial, public, private, or tribal
entities:
4.2.1. Overhead transmission lines operated at 200kV or higher.
4.2.2. Overhead transmission lines operated below 200kV having
been identified as included in the definition of an IROL.
4.2.3. Overhead transmission lines operated below 200 kV having
been identified as included in the definition of one of the Major
WECC Transfer Paths in the Bulk Electric System.
1
EPAct 2005 section 1211c: “Access approvals by Federal agencies”
March 1, 2010
1
Mapping of FAC-003-2 Draft 2 to FAC-003-2 Draft 3 (Results-based Standard)
Standard FAC-003-2
Draft 2
including but not limited to
those that cross lands owned
by federal , state, provincial,
public, private, or tribal
entities.
4.2.2. Transmission lines
operated below 200kV
designated by the Planning
Coordinator as being subject
to this standard become
subject to this standard 12
months after the date the
Planning Coordinator initially
designates the transmission
line as being subject to this
standard.
4.2.3. Existing transmission
line(s) operated at 200kV or
higher that is newly acquired
by a Transmission Owner and
was not previously subject to
this standard, become subject
to this standard 12 months
after the acquisition date of
the transmission line(s).
Comment
4.3.
Added new section titled,
“Background” per SCPSC
format.
R1.
Each Transmission Owner shall have a
documented transmission vegetation
management program that describes how
it conducts work on its Active
Transmission Line Rights of Way to avoid
Sustained Outages due to vegetation,
March 1, 2010
Modified R1. by removing
prescriptive text in sub
parts 1.1 through 1.6. and
focused on desired result
of requiring competency
on the part of
Proposed Standard FAC-003-2 RBS (Draft 3)
4.2.4. This Standard does not apply to Facilities identified above
(4.2.1 through 4.2.3) located in the fenced area of a switchyard,
station or substation.
Other:
4.3.1 This Standard does not apply to any occurrence, nonoccurrence, or other set of circumstances that are beyond the
reasonable control of a Transmission Owner subject to this
Reliability Standard, and are not caused by the fault or
negligence of the Transmission Owner, including acts of God,
flood, drought, earthquake, major storms, fire, hurricane,
tornado, landslides, logging activities, animals severing trees,
lightning, epidemic, strike, war, riot, civil disturbance, sabotage,
vandalism, terrorism, wind shear, or fresh gales that restricts or
prevents performance to comply with this reliability standard’s
requirements.
5. Background
This NERC Vegetation Management Standard (“Standard”) uses a defense-in-depth
approach to improve the reliability of the electric Transmission system by
preventing those vegetation related outages that could lead to Cascading. This
Standard is…
R3. Each Transmission Owner shall have a documented transmission vegetation
management program that describes how it conducts work on its Active
Transmission Line Rights of Way to avoid Sustained Outages due to vegetation,
considering all possible locations the conductor may occupy assuming
operation within Rating and Rated Electrical Operating Conditions.
R5. Each Transmission Owner shall take interim corrective action when it is
2
Mapping of FAC-003-2 Draft 2 to FAC-003-2 Draft 3 (Results-based Standard)
Standard FAC-003-2
Draft 2
considering all possible locations the
conductor may occupy under the effects
of sag and sway throughout its operating
range under rated conditions. The
transmission vegetation management
program shall: [Violation Risk Factor:
Lower][Time Horizon: Long-term planning]
1.1. Specify the methodologies that the
Transmission Owner uses to control
vegetation.
1.2. Specify a Vegetation Inspection frequency
of at least once per calendar year that
takes into account local and
environmental factors.
1.3. Require an annual work plan that
identifies the applicable lines to be
maintained and associated work to be
performed during the year. It shall be
flexible to adjust to changing conditions
and to findings from Vegetation
Inspections. Adjustments to the plan
within the year are permissible. The plan
shall take into consideration permitting
and scheduling requirements from
landowners or regulatory authorities. It
shall support the objectives of the
transmission vegetation management
program and utilize the methodologies
outlined in the transmission vegetation
management program.
1.4. Require a process or procedure for
response to imminent threats of a
vegetation-related Sustained Outage. The
process or procedure shall specify actions
which shall include immediate
communication of the threat to the
Transmission Operator or proper
operating authority. The process or
March 1, 2010
Comment
Transmission Owner.
Proposed Standard FAC-003-2 RBS (Draft 3)
temporarily constrained from performing planned vegetation work, where a
transmission line is put at potential risk due to the constraint.
Elevated interim corrective
actions to a standalone
requirement to focus on
desired result of working
around impediments.
Moved VRF and Time
Horizon.
3
Mapping of FAC-003-2 Draft 2 to FAC-003-2 Draft 3 (Results-based Standard)
Standard FAC-003-2
Draft 2
procedure shall specify what conditions
warrant a response.
1.5. Specify an interim corrective action
process for use when the Transmission
Owner is constrained from performing
vegetation maintenance as planned.
1.6. Specify the maintenance approach used
(such as minimum vegetation-toconductor distance or maximum
vegetation height) to ensure that Table 1
clearances are never violated. The
maintenance approach shall consider the
sag and sway of the conductor throughout
its operating range under rated conditions.
R2.
R3.
Comment
Each Transmission Owner shall implement
its imminent threat process or procedure
when the Transmission Owner has actual
knowledge of such a threat, obtained
through normal operating practices.
Revised to focus on desired
result to notify of imminent
threats.
Each Transmission Owner shall conduct
Vegetation Inspections of all applicable
lines (as measured in line miles) in
accordance with the frequency specified
in its transmission vegetation
management program, unless constrained
by natural disasters. When constrained
by a natural disaster, the Transmission
Owner shall conduct the Vegetation
Inspection(s) within six months or a period
agreed to by its Regional Entity,
whichever is greater.
Revised to focus on desired
result of inspecting for
vegetation annually and to
eliminate prescriptive text.
March 1, 2010
Proposed Standard FAC-003-2 RBS (Draft 3)
R4. Each Transmission Owner shall notify the responsible control center when it has
verified knowledge of a vegetation imminent threat condition. A vegetation imminent
threat condition is one which is likely to cause a Sustained Outage at any moment.
Moved VRF and Time
Horizon.
R6. Each Transmission Owner shall perform a Vegetation Inspection of all applicable
lines once per calendar year, at a minimum.
Moved VRF and Time
Horizon.
4
Mapping of FAC-003-2 Draft 2 to FAC-003-2 Draft 3 (Results-based Standard)
Standard FAC-003-2
Draft 2
R4.
Each Transmission Owner shall prevent
encroachment of vegetation into the
Minimum Vegetation Clearance Distances
(MVCD) listed in FAC-003-2 - Attachment
1 for its applicable lines as observed in
real-time operating between no-load and
their Rating, with the following exceptions:
[Violation Risk Factor — Medium][Time
Horizon — Real Time]
Encroachment into the MVCD listed in FAC-0032-Attachment 1 resulting from natural
disasters. 2
Encroachment into the MVCD listed in FAC-0032-Attachment 1 resulting from human or
animal activity. 3
Encroachment into the MVCD listed in FAC-0032-Attachment 1 resulting from falling
vegetation.
R5. Each Transmission Owner shall prevent
Sustained Outages 4 of applicable lines
that are identified as an element of an
Interconnection Reliability Operating Limit
(IROL) (or Major WECC Transfer Path)
due to vegetation growing into a
conductor operating between no-load and
its Rating, with the following exceptions:
[Violation Risk Factor — High][Time
Horizon — Real Time]
Comment
Proposed Standard FAC-003-2 RBS (Draft 3)
Revised to focus on desired
result of keeping vegetation
out of a minimum clearance
distance from transmission
lines and to improve clarity.
Combined R4, R4, R6, R7,
and R8 into two standalone
requirements.
R1. Each Transmission Owner shall prevent vegetation from encroaching within the
Minimum Vegetation Clearance Distance (MVCD) of line conductors that are identified
as an element of an IROL or Major WECC Transfer Path (operating within Rating and
Rated Electrical Operating Conditions) to avoid a Sustained Outage.
R2. Each Transmission Owner shall prevent vegetation from encroaching within the
Minimum Vegetation Clearance Distance (MVCD) of applicable line conductors, which
are not elements of an IROL and are not a Major WECC Transfer Path, (operating
within Rating and Rated Electrical Operating Conditions) to avoid a Sustained Outage.
Moved VRFs and Time
Horizons.
Sustained Outages of applicable
2
Examples include, but are not limited to, earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the
Transmission Owner or an applicable regulatory body, ice storms, and floods.
3
Examples include, but are not limited to, logging, animal severing tree, vehicle contact with tree, arboricultural activities or horticultural or agricultural
activities, or removal or digging of vegetation.
4
Multiple Sustained Outages on an individual line, if caused by the same vegetation, shall be considered as one outage regardless of the actual number of outages
within a 24-hour period.
March 1, 2010
5
Mapping of FAC-003-2 Draft 2 to FAC-003-2 Draft 3 (Results-based Standard)
Standard FAC-003-2
Draft 2
lines that result from natural
disasters.
Comment
Proposed Standard FAC-003-2 RBS (Draft 3)
R6.
Sustained Outages of applicable
lines that result from human or
animal activity.
Each Transmission Owner shall prevent
Sustained Outages of applicable lines that
are not an element of an IROL (or major
WECC Transfer Path) due to vegetation
growing into a conductor operating
between no-load and its Rating, with the
following exceptions: [Violation Risk
Factor — Medium][Time Horizon — Real
Time]
Sustained Outages of applicable
lines that result from natural
disasters.
Sustained Outages of applicable
lines that result from human or
animal activity.
R7. Each Transmission Owner shall prevent
Sustained Outages of applicable lines due
to the blowing together of vegetation and
a conductor within an Active Transmission
Line Right of Way (operating within design
blow-out conditions) with the following
exception: [Violation Risk Factor —
Medium][Time Horizon — Real Time]
Sustained Outages of applicable lines that result
from natural disasters or wind-blown
debris.
R8. Each Transmission Owner shall prevent
Sustained Outages of applicable lines
due to vegetation falling into a conductor
from within an Active Transmission Line
Right of Way with the following
exceptions: [Violation Risk Factor —
March 1, 2010
6
Mapping of FAC-003-2 Draft 2 to FAC-003-2 Draft 3 (Results-based Standard)
Standard FAC-003-2
Draft 2
Medium] [Time Horizon — Real Time]
R9.
Sustained Outages of applicable
lines that result from natural
disasters or wind-blown debris.
Sustained Outages of applicable
lines that result from human or
animal activity.
Each Transmission Owner shall implement
its annual work plan for vegetation
management to accomplish the purpose
of this standard.
Comment
Moved VRF and Time
Horizon.
R10. Each Planning Coordinator shall prepare
and review annually, a list of lines that are
operated below 200kV, if any, which are
subject to this standard. Each Planning
Coordinator shall consult with its
Transmission Owner(s) and neighboring
Planning Coordinators to obtain input to
develop the list.
Revised to add applicability
sections 4.3.2 and 4.3.3 and
eliminated this requirement.
R11. Each Planning Coordinator shall develop
and document its method for assessing
the reliability significance of sub-200kV
transmission lines whose loss would place
the grid at an unacceptable risk of
instability, separation, or cascading
failures.
Revised to add applicability
sections 4.3.2 and 4.3.3 and
eliminated this requirement.
March 1, 2010
Proposed Standard FAC-003-2 RBS (Draft 3)
R7. Each Transmission Owner shall execute a flexible annual vegetation work plan to
ensure no encroachments within the MVCD.
4.3.2.
4.3.3.
4.3.2.
4.3.3.
Overhead transmission lines operated below 200kV having been identified as
elements of an IROL.
Overhead transmission lines operated below 200 kV having been included in
the definition of one of the Major WECC Transfer Paths in the Bulk Electric
System.
Overhead transmission lines operated below 200kV having been identified as
elements of an IROL.
Overhead transmission lines operated below 200 kV having been included in
the definition of one of the Major WECC Transfer Paths in the Bulk Electric
System.
7
Unofficial Comment Form for 3rd Draft of FAC-003-2 Transmission
Vegetation Management — Part of Project 2007-07 Vegetation
Management
Please DO NOT use this form to submit comments. Please use the electronic form located at
the site below to submit comments on the 3rd Draft of FAC-003-2 Transmission Vegetation
Management. Comments must be submitted by March 31, 2010
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
If you have questions please contact Harry Tom at [email protected] or by telephone at
(860) 550-4157.
Background Information
The purpose of Project 2007-07 Vegetation Management is to:
•
Assist in providing an adequate level of reliability for the North American electric
Transmission System by verifying that the FAC-003-2 Transmission Vegetation
Management standard is complete and that its requirements are set at an
appropriate level to ensure reliability.
•
Incorporate other general improvements described in the Standard Review
Guidelines to bring FAC-003-2 Transmission Vegetation Management into
conformance with the latest version of the Reliability Standards Development
Procedure and the ERO Sanctions Guidelines.
•
Consider comments received from ERO regulatory authorities and stakeholders on
FAC-003-1 Transmission Vegetation Management as noted in the NERC Standards
Issues Database.
•
Satisfy the requirement for review of FAC-003-2 Transmission Vegetation
Management within five-year review cycle.
In addition, on January 14, 2010, the NERC Standards Committee endorsed the use of
Project 2007-07 Vegetation Management as the prototype for the proof-of-concept for using
the results-based criteria for developing a reliability standard. The results-based initiative is
intended to focus the collective effort of NERC and industry participants on improving the
clarity and quality of NERC reliability standards by developing performance-based, riskbased and competency-based requirements that accomplish a reliability objective through a
defense-in-depth strategy, while eliminating documentation-driven requirements that do not
have an impact on bulk power system reliability.
The Standards Committee also directed the standard drafting team for Project 2007-07
Vegetation Management to do so with a target for final industry ballot of draft FAC-003-2
Transmission Vegetation Management by August 31, 2010.
The criteria for developing a results-based reliability standard include:
1. Strive to achieve a portfolio of performance-based, risk-based, and competencybased mandatory reliability requirements that provide an effective defense-in-depth
strategy for achieving an adequate level of reliability of the bulk power system.
a) Performance-based — defines a particular reliability objective or outcome
to be achieved. In its simplest form, a results-based requirement has four
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Unofficial Comment Form for 3rd Draft of FAC-003-2 — Project 2007-07 Vegetation
Management
components: who, under what conditions (if any), shall perform what action,
to achieve what particular result or outcome?
b) Risk-based — preventive requirements to reduce the risks of failure to
acceptable tolerance levels. A risk-based reliability requirement should be
framed as: who, under what conditions (if any), shall perform what action, to
achieve what particular result or outcome that reduces a stated risk to the
reliability of the bulk power system?
c) Competency-based — defines a minimum capability an entity needs to have
to demonstrate it is able to perform its designated reliability functions.
2. The defense-in-depth strategy for reliability standards development should recognize
that each requirement in a NERC reliability standard has a role in preventing system
failures, and that these roles are complementary and reinforcing. Reliability
standards should not be viewed as a body of unrelated requirements, but rather
should be viewed as part of a portfolio of requirements designed to achieve an
overall defense-in-depth strategy and comport with the quality objectives of a
reliability standard.
3. Each requirement should identify a clear and measurable expected outcome, such
as: i) a stated level of reliability performance, ii) a reduction in a specified reliability
risk, or iii) a necessary competency.
4. Strive to minimize prescriptive, administrative (document something), and
commercial requirements within the set of NERC reliability standards (i.e., these
types of requirements are permissible in standards but should be the exception
rather then the rule).
5. A requirement should not prescribe commercial business practices which do not
contribute directly to reliability.
The Vegetation Management Standard Drafting Team worked with Ivy Hooks of Compliance
Automation, Inc. to apply the “results-based” approach to developing requirements that are
clear and enforceable. Ivy is the CEO of Compliance Automation and has shared a wealth of
knowledge and expertise with the drafting team. The “look and feel” of the proposed
standard contains much more information than we have been including in previous
standards, thus the look and feel of the draft FAC-003-2 Transmission Vegetation
Management standard is quite different from the look of our existing standards. One of the
more obvious changes is the addition of information to aid end users in reading the
requirements from a common understanding of the standard’s objective and the rationale
for including each requirement. During the Three-year Performance Assessment,
stakeholders indicated that they wanted more information to assist in applying standards –
and the additional details provided in the proposed Vegetation Management standard
provide an example of one way to fill that void.
On February 11, 2010 the Standards Committee authorized the standard drafting team for
Project 2007-07 Vegetation Management to take the following actions relative to the
development of draft FAC-003-2 Transmission Vegetation Management:
•
Discontinue work in developing a complete Consideration of Comments Report for
the comments received in response to the posting of the second draft of the draft
FAC-003-2 Transmission Vegetation Management standard that was posted in
August 2009; however, post the comments received along with a summary of the
actions taken by the team in response to those comments but without an individual
response to each comment provided.
2
Unofficial Comment Form for 3rd Draft of FAC-003-2 — Project 2007-07 Vegetation
Management
•
Use informal comment periods to collect comments on future “drafts” of the
standard, post the comments received during the informal comment periods along
with a summary of how the team used the comments received and a redline version
of the standard showing the changes made based on the comments received.
•
Conduct a 45-day formal comment period in parallel with the formation of the ballot
pool and the initial ballot of the standard; post the comments from the formal
comment period as they are received for at least the first 30 days of the comment
period.
•
Use a standard template that is different from the template stipulated in the
Reliability Standard Development Procedure as provided by the Standards
Committee’s Process Subcommittee.
With respect to the first bullet above regarding stakeholder comments submitted in
response to the posting of the second draft of the proposed standard, the SDT has posted a
general summary response to the comments on the draft which was posted in August,
2009. However, the limited response does not mean that the SDT ignored the comments
received in August 2009. The SDT carefully considered those comments and made
modifications to the standard based on the comments received. A summary of the SDT
considerations has been posted on the NERC website in lieu of a full Consideration of
Comments Report.
A subset of comments received during the August 2009 posting suggested that the STD for
this project (Project 2007-07 Vegetation Management) address the recommendations in the
Final Report from the Ad Hoc Group for Generator Requirements at the Transmission
Interface that pertain to FAC-003-1 Transmission Vegetation Management. The SDT for this
project respectfully declined to address the referenced recommendations primarily for the
following reasons:
•
Project 2010-07 Transmission Requirements at the Generator Interface has been
established to address the recommendations in the Final Report from the Ad Hoc
Group for Generator Requirements at the Transmission Interface.
•
The referenced recommendations are outside the scope of the Standard
Authorization Request for this project (Project 2007-07 Vegetation Management).
•
The appointed SDT does not have the proper representation to address the
referenced recommendations.
Significant modifications incorporated into this draft of FAC-003-2 Transmission Vegetation
Management include:
•
Two new sections have been added: Background and Guideline and Technical Basis.
While the titles are self-evident, the SDT would like to point out that this information
was previously included for review in the Technical Reference (aka, White Paper).
•
A “global” Force Majeure statement was added to the Applicability section of the
standard in response to comments received. This statement is included at the front
of the standard and thus is applicable to all Requirements. This “exclusion language”
was included in a footnote in the prior version of the standard.
•
The wording relating to expected conductor positions was modified. The previous
draft of the standard referred to “operating within Rating under normal conditions”
and/or “sag and sway”. With this draft, and in response to comments received on
this issue, the wording was changed, to state “operating within Rating under Rated
Electrical Operating Conditions”. This modification uses standard NERC glossary
3
Unofficial Comment Form for 3rd Draft of FAC-003-2 — Project 2007-07 Vegetation
Management
terms to indicate the expectation that vegetation management should account for
line operation as designed but not, for example, for overloaded conditions or
excessive wind speeds.
With respect to the format of the draft FAC-003-2 Transmission Vegetation Management
standard currently posted for informal comment, the NERC Standards Committee's Process
Subcommittee (SCPS) has developed a proposed standard template for use by the standard
drafting team for Project 2007-07 Vegetation Management. The proposed template is
intended to meet the following key objectives:
1. Depicting the basic criteria for writing standard requirements that meet the ResultsBased Reliability Standards concepts;
2. Having one Section that contains only the reliability requirements and associated
measures;
3. Moving the administrative and compliance information that is not required for
reliability into different sections so that there are "homes" for these materials;
In addition, the new template contains the following features/changes:
1. Allowing insertion of explanatory text to help readers better understand the basis of
the definitions and requirements;
2. Moving the standard development timeline (previously called roadmap), revision
history and effective date(s) up front before the Introduction Section;
3. Grouping Requirements and their corresponding Measures together;
4. Grouping VRFs, Time Horizons and VSLs - all of which are used only in the
determination of a penalty or sanction - together in a table while leaving the
requirements and measures free of any of the compliance elements.
The following questions will assist the SDT in finalizing the development of FAC-003-2
Transmission Vegetation Management and will also assist the Standards Committee’s
Process Subcommittee in refining the proposed standard template. For questions where you
agree with indicated statement, please state that you agree and if able, please provide
supporting documentation. If you disagree with the statement, please explain why you
disagree and provide a rationale to support your position. We would appreciate responses
to as many of the following questions as possible.
1. In response to comments received regarding potential for “double jeopardy” and to
provide differentiation between transmission lines designated as having IROLs and Major
WECC transfer paths from those that are not, the SDT consolidated requirements R4
though R8 found in the August 2009 draft of FAC-003-2 into two requirements in the
latest draft of FAC-003-2 (new requirements R1 and R2). Do you agree? Please explain.
Yes
No
Comments:
2. The results-based reliability standard criteria focus on striving to achieve a portfolio of
performance-based, risk-based, and competency-based mandatory reliability
requirements that provide an effective defense-in-depth strategy for achieving an
4
Unofficial Comment Form for 3rd Draft of FAC-003-2 — Project 2007-07 Vegetation
Management
adequate level of reliability of the bulk power system in lieu of prescriptive
requirements. Consequently, the SDT revised R1 and its subparts found in the August
2009 draft of FAC-003-2 in favor of the text in the latest draft of FAC-003-2 (new
requirement R3). Do you agree? Please explain.
Yes
No
Comments:
3. Do you agree with the overall layout of the proposed template? If not, please suggest an
alternative layout.
Yes
No
Comments:
4. Do you agree with grouping the standard development timeline (previously called
roadmap) with the revision history, and the effective date(s) and putting this
administrative information up front before the Introduction Section? Please explain.
Yes
No
Comments:
5. Do you agree with grouping the Requirements and Measures together, in one Section
now called Requirements and Measures? Please explain.
Yes
No
Comments:
6. Do you agree with grouping VRFs, Time Horizons and VSLs together, and putting them
in a table separate from the Requirements and Measures Section? Please explain.
Yes
No
Comments:
7. Do you agree with the insertion of text boxes, where necessary, to help readers better
understand the basis of the Definitions and Requirements? Please explain.
Yes
No
Comments:
8. Do you agree with the addition of a Guideline and Technical Basis Section to place
technical materials and other related information that assists entities in understanding
5
Unofficial Comment Form for 3rd Draft of FAC-003-2 — Project 2007-07 Vegetation
Management
how to comply with the standard but does not contain mandatory actions/activities?
Please explain.
Yes
No
Comments:
9. Do you prefer putting URL links to reference materials in the Guideline and Technical
Basis Section, or do you prefer putting the additional technical/information materials in
appendices, where needed, to supplement the Guideline and Technical Basis Sections?
Please explain.
Prefer the inclusion of URL links
Prefer appendices
Comments:
10. Do you agree with the addition of the Background Section to allow provision of
background information, and to elaborate on the reliability-related drivers for the
standard/change? Please explain.
Yes
No
Comments:
11. Do you agree with the addition of an Administrative Procedure Section to place
administrative/procedural requirements that are contained in the existing standards but
which do not meet the results-based or risk-based criteria? Please explain.
Yes
No
Comments:
12. Is there any other information that should be included in the standard document? If so,
please explain why you feel that this information should be included.
Yes
No
Comments:
13. Do you have any other comment regarding the draft FAC-003-2 Transmission Vegetation
Management standard that have not been addressed above? If yes, please provide a
reference to the section, requirement, or subrequirement that you believe should be
changed, added or deleted and the rationale for your proposal.
Yes
No
Comments:
6
Transmission Vegetation Management
Standard FAC-003-2 Technical Reference
Vegetation Management Standard Drafting Team
March 17, 2010
NERC Standard FAC-003-2 Technical Reference
Table of Contents
INTRODUCTION ....................................................................................................................................................... 3
SPECIAL NOTE: THE APPLICATION OF RESULTS-BASED APPROACH TO FAC-003-2 ........................ 4
DISCLAIMER ............................................................................................................................................................. 6
DEFINITION OF TERMS ......................................................................................................................................... 7
APPLICABILITY OF THE STANDARD............................................................................................................... 11
REQUIREMENTS R1 AND R2 ............................................................................................................................... 14
REQUIREMENT R3 ................................................................................................................................................. 16
ANSI A300 – BEST MANAGEMENT PRACTICES FOR TREE CARE OPERATIONS ............................................... 21
REQUIREMENT R4 ................................................................................................................................................. 26
REQUIREMENT R5 ................................................................................................................................................. 28
REQUIREMENT R6 ................................................................................................................................................. 30
REQUIREMENT R7 ................................................................................................................................................. 31
APPENDIX ONE: CLEARANCE DISTANCE DERIVATION BY THE GALLET EQUATION .................. 33
LIST OF ACRONYMS AND ABBREVIATIONS ................................................................................................. 40
REFERENCES .......................................................................................................................................................... 41
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Introduction
This document is intended to provide supplemental information and guidance for complying with
the requirements of Reliability Standard FAC-003-2.
The purpose of the Standard is to improve the reliability of the electric transmission system by
preventing those vegetation related outages that could lead to Cascading.
Compliance with the Standard is mandatory and enforceable.
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Special Note: The Application of Results-Based
Approach to FAC-003-2
In its three-year assessment as the ERO, NERC acknowledged stakeholder comments and
committed to:
i) addressing quality issues to ensure each reliability standard has a clear statement of
purpose, and has outcome-focused requirements that are clear and measurable; and
ii) eliminating requirements that do not have an impact on bulk power system reliability.
In 2010, the Standards Committee approved a recommendation to use Project 2007-07
Vegetation Management as a first proof of concept for developing results-based standards.
The Standard Drafting Team (SDT) employed a defense-in-depth 1 strategy for FAC-003-2,
where each requirement has a role in preventing those vegetation related outages that could lead
to Cascading. This portfolio of requirements was designed to achieve an overall defense-indepth strategy and to comply with the quality objectives identified in the Acceptance Criteria of
a Reliability Standard document.
The SDT developed a portfolio of performance, risk, and competency-based mandatory
reliability requirements to support an effective defense-in-depth strategy. Each Requirement was
developed using one of the following requirement types:
a. Performance-based - defines a particular reliability objective or outcome to be
achieved. In its simplest form, a results-based requirement has four components:
who, under what conditions (if any), shall perform what action, to achieve what
particular result or outcome?
b. Risk-based - preventive requirements to reduce the risks of failure to acceptable
tolerance levels. A risk-based reliability requirement should be framed as: who, under
what conditions (if any), shall perform what action, to achieve what particular result
or outcome that reduces a stated risk to the reliability of the bulk power system?
c. Competency-based - defines a minimum set of capabilities an entity needs to have to
demonstrate it is able to perform its designated reliability functions. A competencybased reliability requirement should be framed as: who, under what conditions (if
any), shall have what capability, to achieve what particular result or outcome to
perform an action to achieve a result or outcome or to reduce a risk to the reliability
of the bulk power system?
1
A defense-in-depth strategy for reliability standards recognizes that each requirement in the NERC standards has a
role in preventing system failures, and that these roles are complementary and reinforcing. These prevention
measures should be arranged in a series of defensive layers or walls. No single defensive layer provides complete
protection from failure by itself. But taken together, with well-designed layers including performance, risk, and
competency-based, requirements, a defense-in-depth approach can be very effective in preventing future large scale
power system failures.
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NERC Standard FAC-003-2 Technical Reference
The drafting team reviewed and edited version 1 of FAC-003-1 to remove prescriptive and
administrative language in order to distill the technical requirements down to their essential
reliability content. Text that is explanatory in nature is placed in a special section of the standard
entitled Guideline and Technical Basis to aid in the understanding of the requirements.
Furthermore, Rationale text boxes are inserted alongside each requirement to communicate the
foundation for the requirement.
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NERC Standard FAC-003-2 Technical Reference
Disclaimer
This supporting document is supplemental to the reliability standard FAC-003-2 —
Transmission Vegetation Management and does not contain mandatory requirements subject to
compliance review.
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NERC Standard FAC-003-2 Technical Reference
Def inition of Terms
Active Transmission Line Right of Way* — A strip or corridor of land that is occupied by
active transmission facilities. This corridor does not include the parts of the Right-of-Way that
are unused or intended for other facilities.
Examples of active portions of corridors include:
1) The width of any Active Transmission Line Right-of-Way (ROW) is the portion of
the ROW that has been cleared of vegetation to meet design clearance requirements
such as National Electrical Safety Code or other design criteria, for the reliable
operation of active facilities.
Examples of inactive portions of corridors include:
2) The portions of the right of way acquired to accommodate future facilities. Power
plant exits are examples where large rights-of-way are obtained for maximum
corridor utilization and may currently have fewer structures constructed.
3) The portion of the ROW where corridor edge zones are designated by regulatory
bodies for vegetation to exist.
4) The portions of the ROW where double-circuit structures are installed but only one
circuit is currently strung with conductors.
Vegetation Inspection** — The systematic examination of vegetation conditions on an Active
Transmission Line Right-of-Way which may be combined with a general line inspection.
The inspection includes the identification of any vegetation that may pose a threat to reliability
prior to the next planned inspection or maintenance work, considering the current location of the
conductor and other possible locations of the conductor due to sag and sway for rated conditions.
This definition allows both maintenance inspections and vegetation inspections to be performed
concurrently.
*To be added to the NERC glossary of terms with final approval of this standard revision
** This is a modification to a defined term in the NERC glossary.
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Figure 1
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Figure 2
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Figure 3
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Applicability of the Standard
4. Applicability
4.1. Functional Entities:
4.1.1 Transmission Owners
4.2. Facilities: Defined below, including but not limited to those that cross lands owned
1
by federal , state, provincial, public, private, or tribal entities:
4.2.1 Overhead transmission lines operated at 200kV or higher.
4.2.2 Overhead transmission lines operated below 200kV having been identified as
elements of an Interconnection Reliability Operating Limit (IROL).
4.2.3 Overhead transmission lines operated below 200 kV having been identified as
included in the definition of one of the Major WECC Transfer Paths in the
Bulk Electric System.
4.2.4 This Standard does not apply to Facilities identified above (4.2.1 through
4.2.3) located in the fenced area of a switchyard, station or substation.
4.3. Other:
4.3.1 This Standard does not apply to any occurrence, non-occurrence, or other set
of circumstances that are beyond the reasonable control of a Transmission Owner
subject to this Reliability Standard, and are not caused by the fault or negligence of
the Transmission Owner, including acts of God, flood, drought, earthquake, major
storms, fire, hurricane, tornado, landslides, logging activities, animals severing
trees, lightning, epidemic, strike, war, riot, civil disturbance, sabotage, vandalism,
terrorism, wind shear, or fresh gales that restricts or prevents performance to
comply with this reliability standard’s requirements.
In Order 693, FERC discussed the 200 kV bright-line test of applicability. While FERC did not
change the 200 kV bright line, the Commission remained concerned that there may be some
transmission lines operating at lesser voltages that could have significant impact on the Bulk
Electric System that should therefore be subject to this standard.
NERC Standard FAC-014 has the stated purpose, “To ensure that System Operating Limits
(SOLs) used in the reliable planning and operation of the Bulk Electric System (BES) are
determined based on an established methodology or methodologies.” FAC-014 requires
Reliability Coordinators, Planning Coordinators, and Transmission Planners to have a
methodology to identify all lines that might comprise an IROL. Thus, these entities would
identify sub-200 kV lines that qualify as part of an IROL and should be subject to FAC-003-2.
Although all three entities may prepare the list of elements, FAC-003-2 presently does not
specify that it is the list from the Planning Coordinator that should be used by Transmission
Owners for FAC-003. However, the Time Horizon needed to plan vegetation management work
does not lend itself to the operating horizon of a Reliability Coordinator. Additionally, the
Planning Coordinator has a wider-area view than the Transmission Planner and could thus
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NERC Standard FAC-003-2 Technical Reference
identify any elements of importance to a sub-set of its area that might be missed by a
Transmission Planner.
Transmission Owners, who do not already get the list of circuits included in the definition of an
IROL, can get them from the Planning Coordinator. Specifically R5 of FAC-014 specifies that
“The Reliability Coordinator, Planning Authority (Coordinator) and Transmission Planner
shall each provide its SOLs and IROLs to those entities that have a reliability-related need for
those limits and provide a written request that includes a schedule for delivery of those limits”
Vegetation-related Sustained Outages that occur due to natural disasters are beyond the control
of the Transmission Owner. These events are not classified as vegetation-related Sustained
Outages and are therefore exempt from the Standard. Transmission lines are not designed to
withstand the impacts of natural disasters such as tornadoes, hurricanes, severe ice loads,
landslides, etc. In the aftermath of catastrophic system damage from natural disasters the
Transmission Owner’s focus is on electric system restoration for public safety and critical
support infrastructure.
Sustained Outages due to human or animal activity are beyond the control of the Transmission
Owner. These outages are not classified as vegetation-related Sustained Outages and are
therefore exempt from the Standard. Examples of these events may include new plantings by
outside parties of tall vegetation under the transmission line planted since the last Vegetation
Inspection, tree contacts with line initiated by vehicles, logging activities, etc.
The foregoing exemptions are addressed in a new subsection, 4.3 Other, of the Applicability
section. Referred to collectively as force majeure events and activities, this section applies to all
requirements in FAC-003-2.
The reliability objective of this NERC Vegetation Management Standard (“Standard”) is to
prevent vegetation-related outages which could lead to Cascading by effective vegetation
maintenance while recognizing that certain outages such as those due to vandalism, human errors
and acts of nature are not preventable. Operating experience clearly indicates that trees that have
grown out of specification could contribute to a cascading grid failure, especially under heavy
electrical loading conditions.
Serious outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations. To
properly reduce and manage this risk, it is necessary to apply the Standard to applicable lines on
any kind of land or easement, whether they are Federal Lands, state or provincial lands, public or
private lands, franchises, easements or lands owned in fee. For the purposes of the Standard and
this technical paper, the term “public lands” includes municipal lands, village lands, city lands,
and land owned by a host of other governmental entities.
The Standard addresses vegetation management along applicable overhead lines that serve to
connect one electric station to another. However, it is not intended to be applied to lines sections
inside the electric station fence or other boundary of an electric station or underground lines.
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NERC Standard FAC-003-2 Technical Reference
The Standard is intended to reduce the risk of Cascading involving vegetation. It is not intended
to prevent customer outages from occurring due to tree contact with all transmission lines and
voltages. For example, localized customer service might be disrupted if vegetation were to make
contact with a 69kV transmission line supplying power to a 12kV distribution station. However,
this Standard is not written to address such isolated situations which have little impact on the
overall Bulk Electric System. In fact, the inclusion of such a transmission line (which does not
lead to the undesirable conditions listed in Requirement R10) on the Planning Coordinator’s list
of sub-200kV lines may constitute a violation of Requirement R10.
Vegetation growth is constant and always present. Unmanaged vegetation poses an increased
outage risk when numerous transmission lines are operating at or near their Rating. This poses a
significant risk of multiple line failures and Cascading. On the other hand, most other outage
causes (such as trees falling into lines, lightning, animals, motor vehicles, etc.) are statistically
intermittent. The probability of occurrence of these events is not dependent on heavy loads.
There is no cause-effect relationship which creates the probability of simultaneous occurrence of
other such events. Therefore these types of events are highly unlikely to cause large-scale grid
failures.
In preparing the original vegetation management standard in 2005, industry stakeholders set the
threshold for applicability of the standard at 200kV. This was because an unexpected loss of
lines operating at above 200kV has a higher probability of initiating a widespread blackout or
cascading outages compared with lines operating at less than 200kV.
The NERC vegetation management standard FAC-003-1 also allowed for application of the
standard to “critical” circuits (critical from the perspective of initiating widespread blackouts or
cascading outages) operating below 200kV. While the percentage of these circuits is relatively
low, it remains a fact that there are sub-200kV circuits whose loss could contribute to a
widespread outage. Given the very limited exposure and unlikelihood of a major event related to
these lower-voltage lines, it would be an imprudent use of resources to apply the Standard to all
sub-200kV lines. The drafting team, after evaluating several alternatives, selected the IROL and
WECC Major Transfer Path criteria to determine applicable lines below 200 kV that are subject
to this standard.
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NERC Standard FAC-003-2 Technical Reference
Requirements R1 and R2
R1.
Each Transmission Owner shall prevent
vegetation from encroaching within the
Minimum Vegetation Clearance Distance
(MVCD) of each line conductor that is
identified as an element of an
Interconnection Reliability Operating
Limit (IROL) or Major Western Electricity
Coordinating Council (WECC) transfer
path (operating within Rating and Rated
Electrical Operating Conditions) to avoid
a Sustained Outage.
Rationale
The MVCD is a calculated minimum
distance stated in feet (meters) to prevent
spark-over between conductors and
vegetation, for various altitudes and
operating voltages. The distances in
Table 2 were derived using a proven
transmission design method.
R2. Each Transmission Owner shall prevent vegetation from encroaching within the MVCD of
each applicable line conductor, which are not elements of an IROL and are not a Major
WECC transfer path, (operating within Rating and Rated Electrical Operating Conditions)
to avoid a Sustained Outage.
M1. Evidence of violation of Requirement R1 is limited to:
•
•
•
•
Real-time observation of encroachment into the MVCD, or
A vegetation-related Sustained Outage due to a fall-in from inside the Active
Transmission Line ROW, or
A vegetation-related Sustained Outage due to blowing together of applicable lines
and vegetation located inside the Active Transmission Line ROW, or
A vegetation-related Sustained Outage due to a grow-in.
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be
reported as one outage regardless of the actual number of outages within a 24-hour period.
M2. Evidence of violation of Requirement R2 is limited to:
•
•
•
•
Real-time observation of encroachment into the MVCD, or
A vegetation-related Sustained Outage due to a fall-in from inside the Active
Transmission Line ROW, or
A vegetation-related Sustained Outage due to blowing together of applicable lines
and vegetation located inside the Active Transmission Line ROW, or
A vegetation-related Sustained Outage due to a grow-in.
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be
reported as one outage regardless of the actual number of outages within a 24-hour period.
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the prevention of vegetation encroachments within a minimum distance of
transmission lines. Content-wise, R1 and R2 are the same requirements, however, they apply to
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NERC Standard FAC-003-2 Technical Reference
different Facilities. Both R1 and R2 require each Transmission Owner to prevent vegetation
from encroaching within the Minimum Vegetation Clearance Distance of transmission lines. R1
is applicable to lines “identified as an element of an Interconnection Reliability Operating Limit
(IROL) or Major Western Electricity Coordinating Council (WECC) transfer path (operating
within Rating and Rated Electrical Operating Conditions) to avoid a Sustained Outage”. R2
applies to all other applicable lines that are not an element of an IROL or Major WECC Transfer
Path.
The separation of applicability (between R1 and R2) recognizes that an encroachment into the
MVCD of an IROL or Major WECC Transfer Path transmission line is a greater risk to the
electric transmission system. Applicable lines that are not an element of an IROL or Major
WECC Transfer Path are required to be clear of vegetation but these lines are comparatively less
operationally significant. As a reflection of this difference in risk impact, the Violation Risk
Factors (VRFs) are assigned as High for R1 and Medium for R2.
These requirements (R1 and R2) state that if vegetation encroaches within the distances
prescribed in Table 1 in Appendix 1 of this Technical Reference document, it is in violation of
the standard. Table 1 delineates the distances necessary to prevent spark-over based on the Gallet
equations as described more fully in Appendix 1.
This requirement assumes that transmission lines and their conductors are operating within their
Rating. If a line conductor is intentionally or inadvertently operated beyond its rating (potentially
in violation of other standards), the occurrence of a clearance encroachment may not be a
violation of this Standard. Conductor position, and the associated vegetation distance, that result
from operation of a transmission line beyond its recognized Rating (for example emergency
actions taken by a TOP or RC to protect an Interconnection) is beyond the scope of this standard.
Evidence of violation of Requirement R1 and R2 is limited to a real-time observation of
encroachment into the MVCD, or a vegetation-related Sustained Outage due to a fall-in from
inside the Active Transmission Line ROW, or a vegetation-related Sustained Outage due to
blowing together of applicable lines and vegetation located inside the Active Transmission Line
ROW, or a vegetation-related Sustained Outage due to a grow-in.
It is also important to note that Multiple Sustained Outages on an individual line can be caused
by the same vegetation. Such events are considered to be a single vegetation-related Sustained
Outage under the Standard where the Sustained Outages occur within a 24 hour period.
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NERC Standard FAC-003-2 Technical Reference
Requirement R3
R3. Each Transmission Owner shall have a
documented transmission vegetation
management program that describes how it
conducts work on its Active Transmission
Line ROWs to avoid Sustained Outages
due to vegetation, considering all possible
locations the conductor may occupy
assuming operation within Rating and
Rated Electrical Operating Conditions.
Rationale
Provide a basis for evaluation on the intent and
competency of the Transmission Owner in
maintaining vegetation. There may be many
acceptable approaches to maintain clearances.
However, the Transmission Owner should be
able to state what its approach is and how it
conducts work to maintain clearances. See
Figure 1 for an illustration of possible
conductor locations.
M3. Each Transmission Owner has a documented transmission vegetation
management program that describes how it conducts work on its Active
Transmission Line ROW to avoid Sustained Outages due to vegetation,
considering all possible locations the conductor may occupy assuming
operation within Rating and Rated Electrical Operating Conditions.
Whitepaper for section R3: (Competency Based Requirement)
Requirement R3 is a competency based requirement concerned with the content of the TVMP
and supporting documentation.
An adequate transmission vegetation management program formally establishes the approach the
Transmission Owner uses to plan and perform vegetation work that is necessary to prevent
transmission Sustained Outages and minimize risk to the Transmission System.
This approach provides the basis for evaluating the intent, allocation of appropriate resources and
the competency of the Transmission Owner in managing vegetation. There are many acceptable
approaches to manage vegetation and avoid sustained outages. However, the Transmission
Owner must be able to state what its approach is and how it conducts work to maintain
clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach a
Transmission Owner chooses to use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the Transmission Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
Conductor Dynamics
In order for a Transmission Owner to develop a specific maintenance approach, it is important to
understand the dynamics of a line conductor’s movement. This paper will first address the
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complexities inherent in observing and predicting conductor movement, particularly for field
personnel. It will then present some examples of maintenance approaches which Transmission
Owners may consider that take into account these complexities, while resulting in practical
approaches for field personnel.
Additionally, it is important the Transmission Owner consider all conductor locations, the
MVCD, and vegetation growth between maintenance activities when developing a maintenance
approach.
Understanding Conductor Position and Movement
The conductor’s position in space at any point in time is continuously changing as a reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading.
As a consequence of these loading variables, the conductor’s position in space is dynamic and
moving. When calculating the range of conductor positions, the Transmission Owner should use
the same design criteria and assumptions that the Transmission Owner uses when establishing
Ratings and SOL, as described in other standards. Typically, the greatest conductor movement
would be at mid-span. As the conductor moves through various positions, a spark-over zone
surrounding the conductor moves with it. The radius of the spark-over zone may be found by
referring to Table 1 (“Minimum Vegetation Clearance Distances”) in the standard. For
illustrations of this zone and conductor movements, Figures 4 through 6 below demonstrate these
concepts. At the time of making a field observation, however, it is very difficult to precisely
know where the conductor is in relation to its wide range of all possible positions. Therefore,
Transmission Owners must adopt maintenance approaches that account for this dynamic
situation.
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Figure 4
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Figure 5
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Cross-Section View of a Single Conductor
At a Given Point Along The Span
Showing Six Possible Conductor Positions Due to Movement
Resulting From Thermal and Mechanical Loading
For Consideration in Developing a Maintenance Approach
Figure 6
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Selecting a Maintenance Approach
In order to maintain adequate separation between vegetation and transmission line conductors,
the Transmission Owner must craft a maintenance strategy that keeps vegetation well away from
the spark-over zone mentioned above. In fact, it is generally necessary to incorporate a variety of
maintenance strategies. For example, one Transmission Owner may utilize a combination of
routine cycles, traditional IVM techniques and long-term planning. Another Transmission Owner
may place a higher reliance on frequent inspections and quick remediation as opposed to a
cyclical approach. This variation of approaches is further warranted when factors, such as
terrain, legal and other constraints, vegetation types, and climates, are considered in developing a
Transmission Owner’s specific approach to satisfying this requirement.
The following is a sample description of one combination of strategies which may be utilized by
a Transmission Owner.
A Transmission Owner’s basic maintenance approach could be to remove all incompatible
vegetation from the right of way if it has the right to do so and has no constraints. In
mountainous terrain, however, this strategy could change to one where the Transmission Owner
manages vegetation based on vegetation-to-conductor clearances, since it might not be necessary
to remove vegetation in a valley that is far below.
If faced with constraints and assuming a line design with sufficient ground clearance, the
Transmission Owner ’s approach could then be to allow vegetation such as fruit trees, but
perhaps only up to a given height at maturity (perhaps 10 feet from the ground). If constraints
cannot be overcome and if design clearances are sufficient, an exception to the Transmission
Owner’s 10-foot guideline might be made. Finally, if the Transmission Owner has chosen to
utilize vegetation-to-conductor clearance distance methods, the Transmission Owner could have
an inspection regimen in place to regularly ensure that any impending clearance problems are
identified early for rectification.
ANSI A300 – Best Management Practices for Tree Care Operations
A description of ANSI A-300, part 7, is offered below to illustrate another maintenance approach
that could be used in developing a comprehensive transmission vegetation management program.
Introduction
Integrated Vegetation Management (IVM) is a best management practice conveyed in the
American National Standard for Tree Care Operations, Part 7 (ANSI 2006) and the International
Society of Arboriculture Best Management Practices: Integrated Vegetation Management (Miller
2007). IVM is consistent with the requirements in FAC-003-02, and it provides practitioners
with what industry experts consider to be appropriate techniques to apply to electric right-of-way
projects in order to meet or exceed the Standard.
IVM is a system of managing plant communities whereby managers set objectives; identify
compatible and incompatible vegetation; consider action thresholds; and evaluate, select and
implement the most appropriate control method or methods to achieve set objectives. The choice
of control method or methods should be based on the environmental impact and anticipated
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effectiveness; along with site characteristics, security, economics, current land use and other
factors.
Planning and Implementation
Best management practices provide a systematic way of planning and implementing a vegetation
management program. While designed primarily with transmission systems in mind, it is also
applicable to distribution projects. As presented in ANSI A300 part 7 and the ISA best
management practices, IVM consists of 6 elements:
1)
2)
3)
4)
5)
6)
Set Objectives
Evaluate the Site
Define Action Thresholds
Evaluate and Select Control Methods
Implement IVM
Monitor Treatment and Quality Assurance
The setting of objectives, defining action thresholds, and evaluating and selecting control
methods all require decisions. The planning and implementation process is cyclical and
continuous, because vegetation is dynamic and managers must have the flexibility to adjust their
plans. Adjustments may be made at each stage as new information becomes available and
circumstances evolve.
Set Objectives
Objectives should be clearly defined and documented. Examples of objectives can
include promoting safety, preventing sustained outages caused by vegetation growing
into electric facilities, maintaining regulatory compliance, protecting structures and
security, restoring electric service during emergencies, maintaining access and clear lines
of sight, protecting the environment, and facilitating cost effectiveness.
Objectives should be based on site factors, such as workload and vegetation type, in
addition to human, equipment and financial resources. They will vary from utility to
utility and project to project, depending on line voltage and criticality, as well as
topographical, environmental, fiscal and political considerations. However, where it is
appropriate, the overriding focus should be on environmentally-sound, cost effective
control of species that potentially conflict with the electric facility, while promoting
compatible, early successional, sustainable plant communities.
Work Load Evaluations
Work-load evaluations are inventories of vegetation that could have a bearing on
management objectives. Work load assessments can capture a variety of vegetation
characteristics, such as location, height, species, size and condition, hazard status, density
and clearance from conductors. Assessments should be conducted considering voltage,
conductor sag from ambient temperatures and loading, and the potential influence of
wind on line sway.
Evaluate and Select Control Methods
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NERC Standard FAC-003-2 Technical Reference
Control methods are the process through which managers achieve objectives. The most
suitable control method best achieves management objectives at a particular site. Many
cases call for a combination of methods. Managers have a variety of controls from which
to choose, including manual, mechanical, herbicide and tree growth regulators,
biological, and cultural options.
Manual Control Methods
Manual methods employ workers with hand-carried tools, including chainsaws,
handsaws, pruning shears and other devices to control incompatible vegetation. The
advantage of manual techniques is that they are selective and can be used where others
may not be. On the other hand, manual techniques can be inefficient and expensive
compared to other methods.
Mechanical Control Methods
Mechanical controls are done with machines. They are efficient and cost effective,
particularly for clearing dense vegetation during initial establishment, or reclaiming
neglected or overgrown right of way. On the other hand, mechanical control methods can
be non-selective and disturb sensitive sites.
Tree Growth Regulator and Herbicide Control Methods
Tree growth regulators and herbicides can be effective for vegetation management. Tree
growth regulators (TGRs) are designed to reduce growth rates by interfering with natural
plant processes. TGRs can be helpful where removals are prohibited or impractical by
reducing the growth rates of some fast-growing species.
Herbicides control plants by interfering with specific botanical biochemical pathways.
Herbicide use can control individual plants that are prone to re-sprout or sucker after
removal. When trees that re-sprout or sucker are removed without herbicide treatment,
dense thickets develop, impeding access, swelling workloads, increasing costs, blocking
lines-of-site, and deteriorating wildlife habitat. Treating suckering plants allows early
successional, compatible species to dominate the right-of-way and out-compete
incompatible species, ultimately reducing work.
Cultural Control Methods
Cultural methods modify habitat to discourage incompatible vegetation and establish and
manage desirable, early successional plant communities. Cultural methods take
advantage of seed banks of native, compatible species lying dormant on site. In the long
run, cultural control is the most desirable method where it is applicable.
A cultural control known as cover-type conversion provides a competitive advantage to
short-growing, early successional plants, allowing them to thrive and eventually outcompete unwanted tree species for sunlight, essential elements and water. The early
successional plant community is relatively stable, tree-resistant and reduces the amount
of work, including herbicide application, with each successive treatment.
Wire-Border Zone
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NERC Standard FAC-003-2 Technical Reference
The wire-border zone technique is a management philosophy that can be applied through
cultural control. W.C. Bramble and W.R. Byrnes developed it in the mid-1980s out of
research begun in 1952 on a transmission right-of-way in the Pennsylvania State Game
Lands 33 Research and Demonstration project (Yahner and Hutnik (2004).
The wire zone is the section of a utility transmission right-of-way directly under the wires
and extending outward about 10 feet on each side. The wire zone is managed to promote
a low-growing plant community dominated by grasses, herbs and small shrubs (under 3
feet in height at maturity). The border zone is the remainder of the right-of-way. It is
managed to establish small trees and tall shrubs (under 25 feet in height at maturity).
When properly managed, diverse, tree-resistant plant communities develop in wire and
border zones. The communities not only protect the electric facility and reduce long-term
maintenance, but also enhance wildlife habitat, forest ecology and aesthetic values.
Although the wire-border zone is a best practice in many instances, it is not necessarily
universally suitable. For example, standard wire-border zone prescriptions may be
unnecessary where lines are high off the ground, such as across low valleys or canyons,
so the technique can be modified without sacrificing reliability.
One way to accommodate variances in topography is to establish different regions based
on wire height. For example, over canyon bottoms or other areas where conductors are
100 feet or more above the ground, only a few trees are likely to be tall enough to conflict
with the lines. In those cases, trees that potentially interfere with the transmission lines
can be removed selectively on a case-by-case basis.
In areas where the wire is lower, perhaps between 50-100 feet from the ground, a border
zone community can be developed throughout the right-of-way. Note that in many cases,
conductor attachment points are more than 50 feet off the ground, so a border zone
community can be cultivated near structures. Where the line is less than 50 feet off the
ground, managers could apply a full wire-border zone prescription.
An environmental advantage of this type of modification is stream protection. Streams
often course through the valleys and canyons where lines are likely to be elevated.
Leaving timber or border zone communities in canyon bottoms helps shelter this valuable
habitat, enabling managers to achieve environmentally sensitive objectives.
Implement IVM
All laws and regulations governing IVM practices and specifications written by qualified
vegetation managers must be followed. Integrated vegetation management control
methods should be implemented on regular work schedules, which are based on
established objectives and completed assessments. Work should progress systematically,
using control measures determined to be best for varying conditions at specific locations
along a right-of-way. Some considerations used in developing schedules include the
importance and type of line, vegetation clearances, work loads, growth rate of predominant
vegetation, geography, accessibility, and in some cases, time lapsed since the last scheduled
work.
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NERC Standard FAC-003-2 Technical Reference
Clearances Following Work
Clearances following work should be sufficient to meet management objectives,
including preventing trees from entering the Minimum Vegetation Clearance Distance,
electric safety risks, service-reliability threats and cost.
Monitor Treatment and Quality Assurance
An effective program includes documented processes to evaluate results. Evaluations
can involve quality assurance while work is underway and after it is completed.
Monitoring for quality assurance should begin early to correct any possible
miscommunication or misunderstanding on the part of crewmembers. Early and
consistent observation and evaluation also provides an opportunity to modify the plan, if
need be, in time for a successful outcome.
Utility vegetation management programs should have systems and procedures in place
for documenting and verifying that vegetation management work was completed to
specifications. Post-control reviews can be comprehensive or based on a statistically
representative sample. This final review points back to the first step and the planning
process begins again.
Summary of A-300 example
Integrated Vegetation Management offers among others, a systematic way of planning and
implementing a vegetation management program as presented in ANSI A300 Part 7. This
methodology enables a program to comply with the NERC Transmission Vegetation
Management Program standard (FAC-003-2). Managers should select control options to best
promote management objectives.
Vegetation Inspections
As with the ANSI A-300 example, The Transmission Owner’s transmission vegetation
management program (TVMP) establishes the frequency of vegetation inspections based upon
many factors. Such local and environmental factors may include anticipated growth rates of the
local vegetation, length of the growing season for the geographical area, limited Active
Transmission Rights of Way width, rainfall amounts, etc.
Annual Work Plan
Requirement R7 of the Standard addresses the execution of the annual work plan. A
comprehensive approach that exercises the full extent of legal rights is superior to incremental
management in the long term because it reduces overall encroachments, and it ensures that future
planned work and future planned inspection cycles are sufficient at all locations on the Active
Transmission Line Right of Way. Removal is superior to pruning. Removal minimizes the
possibility of conflicts between energized conductors and vegetation. Since this is not always
possible, the Transmission Owner’s approach should be to use its prescribed vegetation
maintenance methods to work towards or achieve the maximum use of the Active Transmission
Line Right of Way.
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NERC Standard FAC-003-2 Technical Reference
Requirement R4
R4. Each Transmission Owner shall notify
the responsible control center when it
has verified knowledge of a vegetation
imminent threat condition. A vegetation
imminent threat condition is one which
is likely to cause a Sustained Outage at
any moment.
Rationale
To ensure rapid notification of the correct
personnel when an occurrence of a critical
situation is observed. Verified knowledge
includes observations by journeyman
lineman, utility arborist, or other qualified
personnel, or a report verified by these
personnel.
The term “imminent threat” refers to a
vegetation condition which is likely to
cause a Sustained Outage at any moment. An imminent threat requires immediate action
by the Transmission Owner to prevent the occurrence of a Sustained Outage.
M4. Each Transmission Owner that has experienced a verified vegetation imminent threat will
have evidence that it notified the responsible control center.
R4 is a risk-based requirement type. It focuses upon preventative actions to be taken by the
Transmission Owner for the mitigation of Sustained Outage risk when a vegetation imminent
threat is verified. R4 involves the expeditious notification to the responsible control center of
potentially threatening vegetation conditions to transmission lines.
The term “verified knowledge” implies reliable confirmation that an imminent threat actually
exists due to vegetation. Verification could be that the initial call-in came from a trained
employee able to identify such a threat or it could be verified by sending out such a trained
person to confirm a call-in from a citizen or an untrained employee.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that presents an imminent danger of
falling into the transmission conductor (a fall-in issue). A knowledgeable verification of the risk
would include an assessment of the possible sag or movement of the conductor operating
between no-load and its rating.
The term “responsible control center” refers to personnel with direct responsibility for operating
the transmission lines, such as the Transmission Owner’s local control center, Transmission
Operator, Independent System Operator, or other operating entity. In the case where the
responsible control center is not the Transmission Operator, the communication between the
responsible control center and the Transmission Operator will occur by the normal policies that
govern their relationship.
The Transmission Owner has the responsibility to ensure the proper communication between
field personnel and the responsible control center to allow the responsible control center to take
the appropriate action until the threat is relieved. Appropriate actions may include a temporary
reduction in the line loading, switching the line out of service or positioning the system in
recognition of the increasing risk of outage on that circuit.
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NERC Standard FAC-003-2 Technical Reference
The imminent threat notification should be communicated in terms of minutes or hours as
opposed to a longer time frame for interim corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions are not necessarily considered
imminent threats under this Standard. For example, some Transmission Owners may have a
danger tree identification program that identifies tree for removal with the potential to fall near
the line. These trees are not necessarily considered imminent threats under the Standard unless
they pose an immediate fall-in threat.
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NERC Standard FAC-003-2 Technical Reference
Requirement R5
R5. Each Transmission Owner shall take interim
corrective action when it is temporarily
constrained from performing planned vegetation
work, where a transmission line is put at
potential risk due to the constraint.
M5. Each Transmission Owner has evidence of
the interim corrective action taken for each
temporary constraint where a transmission line
was put at potential risk. Examples of acceptable
forms of evidence may include work orders,
invoices, or inspection records.
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
Transmission Owner from performing
planned vegetation maintenance work.
When this event occurs and the work is
essential to avoid risk to the transmission
line the Transmission Owner must establish
and act on a plan to prevent an imminent
threat. This is not intended to address
situations where a planned work
methodology cannot be performed but an
alternate work methodology can be used.
R5 is a risk-based requirement type. It focuses upon preventative actions to be taken by the
Transmission Owner for the mitigation of Sustained Outage risk when temporarily constrained
from performing vegetation maintenance. The intent of this requirement is to deal with situations
that prevent the Transmission Owner from performing planned vegetation management work
and, as a result, have the potential to put the transmission line at risk. Constraints to performing
vegetation maintenance work as planned could result from legal injunctions filed by property
owners, the discovery of easement stipulations which limit the Transmission Owner’s rights, or
other circumstances.
This requirement is not intended to address situations where the transmission line is not at
immediate risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
Transmission Owner is not under any immediate time constraint for achieving the management
objective, can easily reschedule work using an alternate approach, and therefore does not need to
take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the Transmission Owner is required to take an interim corrective action to mitigate the potential
risk to the transmission line. A wide range of actions can be taken to address various situations.
General considerations include:
•
•
•
•
Identifying locations where the Transmission Owner is constrained from performing
planned vegetation maintenance work which potentially leaves the transmission line
at risk.
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for each location.
In developing the specific action to mitigate the potential risk to the transmission line
the Transmission Owner could consider location specific measures such as modifying
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NERC Standard FAC-003-2 Technical Reference
•
the inspection and/or maintenance intervals. Where a legal constraint would not allow
any vegetation work, the interim corrective action could include limiting the loading
on the transmission line.
The Transmission Owner should document and track the specific corrective action
taken at each location. This location may be indicated as one span, one tree or a
combination of spans on one property where the constraint is considered to be
temporary.
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NERC Standard FAC-003-2 Technical Reference
Requirement R6
R6. Each Transmission Owner shall perform a
Vegetation Inspection of all applicable
transmission lines at least once per
calendar year
M6. Each Transmission Owner has evidence
that it conducted Vegetation Inspections at
least once per calendar year for applicable
transmission lines. Examples of acceptable
forms of evidence may include work
orders, invoices, or inspection records.
Rationale
The requirement is for once per calendar
year because that seems to be reasonable
length of time for a majority of situations.
Transmission Owners should consider local
and environmental factors that could warrant
more frequent inspections that may affect
reliability.
R6 is a risk-based requirement type. It focuses upon the preventative action of vegetation
inspections to be conducted by the Transmission Owner for the mitigation of Sustained Outage
risk. This requirement sets a minimum vegetation inspection frequency of once per calendar
year. A once per calendar year frequency is reasonable based upon average growth rates across
North America and common utility practice. Transmission Owners should consider local and
environmental factors that could warrant more frequent inspections that may affect reliability.
This requirement sets a minimum time period for the Vegetation Inspections. More frequent
inspections may be needed to maintain reliability levels, depending upon such factors as
anticipated growth rates of the local vegetation, length of the growing season for the
geographical area, limited Active Transmission ROW width, and rainfall amounts. Therefore
some lines may be designated with a higher frequency of inspections.
The VSL for Requirement R6 has VSL categories ranked by the percentage of the required ROW
inspections completed. To calculate the percentage of inspection completion, the Transmission
Owner lines may choose units such as: line miles or kilometers, circuit miles or kilometers, pole
line miles, ROW miles, etc.
For example, when a Transmission Owner operates 2,000 miles of 230 kV transmission lines this
Transmission Owner will be responsible for inspecting all 2,000 miles of 230 kV transmission
lines at least once during the calendar year. If one of the included lines was 100 miles long, and
if it was not inspected during the year, then the amount inspected would be 1900/2000 = 0.95 or
95%. The “Lower VSL” for R6 would apply in this example.
The standard allows Vegetation Inspections to be performed in conjunction with general line
inspections as per the definition.
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NERC Standard FAC-003-2 Technical Reference
Requirement R7
R7. Each Transmission Owner shall execute a
flexible annual vegetation work plan to
ensure no vegetation encroachments occur
within the MVCD.
M7. Each Transmission Owner has evidence
that it executed a flexible annual
vegetation work plan. Examples of
acceptable forms of evidence may include
work orders, invoices, or inspection
records.
Rationale
This requirement sets the expectation that
the work identified in the annual work plan
will be completed as planned. A flexible
annual vegetation work plan allows for work
to be deferred into the following calendar
year provided it does not have the potential
to become an imminent threat.
This is a risk-based requirement type. R7 focuses upon implementation of the annual vegetation
work plan to diminish risk of vegetation encroachments within the MVCD. This requirement sets
the expectation that the work identified in the annual vegetation work plan will be completed as
planned.
The flexibility to adjust the annual vegetation work plan must always ensure the reliability of the
electric Transmission system. Flexibility is meant to address changing conditions of the
vegetation on the Active Transmission Line ROW, emergencies, and other significant changing
conditions.
This standard requires that the annual vegetation work plan be flexible to allow the Transmission
Owner to change priorities during the year as conditions or situations dictate. For example,
weather conditions (drought) could make herbicide application ineffective during the plan year.
Other conditions may also result in adjustments to the annual vegetation work plan:
•
•
•
•
Environmental conditions such as excessive rainfall, infestation, disease, fire, etc.
Work-management related conditions such as revised work plan priorities,
rescheduled work to another time or selection of an alternative vegetation control
method.
Changes in land usage made by a property owner, such as timber clearing.
Redirection of local resources away from planned maintenance to render assistance
due to major storms, i.e., complying with mutual assistance agreements.
The work plan is not intended to be a “span-by-span” detailed description of all work to be
performed. It is intended to require the Transmission Owner to annually plan and schedule
vegetation work to prevent encroachment into the MVCD.
The Transmission Owner is required to implement the annual vegetation work plan to
accomplish the purpose of this standard. This means that maintenance should be performed to
the extent of the Transmission Owner’s easement, fee simple or other legal right. A
comprehensive approach that exercises the full extent of legal rights is superior to incremental
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NERC Standard FAC-003-2 Technical Reference
management in the long term by reducing overall encroachments. This approach emphasizes the
importance of maintaining all locations on the Active Transmission Line ROWs for reliability
purposes in lieu of making special exceptions.
Property owners, agencies and other interested parties occasionally request special
considerations to leave undesirable vegetation conditions. Historically, such special
considerations have led to outages (some of which became Cascading events) and can lead to
violations of the standard.
Documentation or other evidence of the work performed typically consists of signed off work
orders, signed contracts, printouts from work management systems, spreadsheets of planned
versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence
may include photographs, work inspection reports and walk-through reports.
When the annual vegetation work plan is adjusted or otherwise not completely implemented as
originally planned, the Transmission Owner is encouraged to document the change. The reasons
for the deferrals or changes and the expected completion date of postponed work should also be
documented.
When developing the annual vegetation work plan the Transmission Owner should allow time
for procedural requirements to obtain permits to work on federal, state, provincial, public, tribal
lands. In some cases the lead time for obtaining permits may necessitate preparing work plans
more than a year prior to work start dates. Transmission Owners may also need to consider those
special landowner requirements as documented in easement instruments.
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NERC Standard FAC-003-2 Technical Reference
Appendix One: Clearance Distance Derivation by the
Gallet Equation
The Gallet Equation is a well-known method of computing the required strike distance for proper
insulation coordination, and has the ability to take into account various air gap geometries, as
well as non-standard atmospheric conditions. When the Gallet Equation and conservative
probabilistic methods are combined, i.e. deterministic design, sparkover probabilities of 10-6 or
less are achieved. This approach is well known for its conservatism and was used to design the
first 500 kV and 765 kV lines in North America [1]. Thus, the deterministic design approach
using the Gallet Equation is used for the standard to compute the minimum strike distance
between transmission lines and the vegetation that may be present in or along the transmission
corridor.
Method Explanation (Gallet Equation)
In 1975 G. Gallet published a benchmark paper that provided a method to compute the critical
flashover voltage (CFO) of various air gap geometries [4]. The Gallet Equation uses various
“gap factors” to take into account various air gap geometries. Various gap factor values are
provided in [1]. If the vegetation in a transmission corridor, e.g. a tree, is assumed electrically to
be a large structure then the CFO of such an air gap geometry can be computed for dry or wet
conditions using a well established equation proposed by Gallet [1],[2],[4],
CFOA = k w ⋅ k g ⋅ δ m ⋅
3400
8
1+
D
(1)
Where:
kw
is defined as the factor that takes into account wet or dry conditions (dry = 1.0 and wet =
0.96) and phase arrangement (multiply by 1.08 for outside phase), e.g. outside phase and wet
conditions = (0.96)(1.08) = 1.037
kg
is defined as the gap factor (1.3 for conductor to large structure)
D
is the strike distance (m)
CFOA is the CFO for the relative air density (kV)
δ
is defined as the relative air density and is approximately equal to (2) where A is the altitude
in km
δ =e
A
8.6
(2)
=
m 1.25G0 ( G0 − 0.2 )
(3)
CFOs
500 ⋅ D
(4)
G0 =
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−
33
NERC Standard FAC-003-2 Technical Reference
CFOs = k w ⋅ k g ⋅
3400
8
1+
D
(5)
where CFOS is the CFO for standard atmospheric conditions (kV). Using (1)-(5), the required CFOA can be
computed using an iterative process.
Once the CFOA is known, deterministic methods can be used to determine the required clearance
distance. If we let the maximum switching overvoltage be equal to the withstand voltage of the
air gap (CFOA - 3σ) then the CFOA can be written as (6).
CFOA =
Vm
σ
1− 3
CFOA
(6)
Where:
Vm is equal to the maximum switching overvoltage, i.e. the value that has a 0.135% chance of being
exceeded
σ is the standard deviation of the air gap insulation
CFOA is the critical flashover voltage of the air gap insulation under non-standard atmospheric conditions
The ratio of σ to the CFOA given in (6) can be assumed to be 0.05 (5%) [1]. Thus, (6) can be
written as (7).
CFOA =
Vm
0.85
(7)
Substituting (7) into (1) we arrive at (8).
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ m ⋅
3400
8
1+
D
(8)
Equation 8 relates the maximum transient overvoltage, Vm, to the air gap distance, D. Using (8)
to compute the required clearance distance for the specified air gap geometry (conductor to large
structure) results in a probability of flashover in the range of 10-6.
Transient Overvoltage
In general, the worst case transient overvoltages occurring on a transmission line are caused by
energizing or re-energizing the line with the latter being the extreme case if trapped charge is
present. The intent of FAC-003 is to keep a transmission line that is in service from becoming
de-energized (i.e. tripped out) due to sparkover from the line conductor to nearby vegetation.
Thus, the worst case scenarios that are typically analyzed for insulation coordination purposes
(e.g. line energization and re-energization) can be ignored. For the purposes of FAC-003-2, the
worst case transient overvoltage then becomes the maximum value that can occur with the line
energized. Determining a realistic value of transient overvoltage for this situation is difficult
because the maximum transient overvoltage factors listed in the literature are based on a
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NERC Standard FAC-003-2 Technical Reference
switching operation of the line in question. In other words, these maximum overvoltage values
(e.g. the values listed in [2], [3] and [5]) are based on the assumption that the subject line is being
energized, re-energized or de-energized. These operations, by their very nature, will create the
largest transient overvoltages. Typical values of transient overvoltages of in-service lines, as
such, are not readily available in the literature because the resulting level of overvoltage is
negligible compared with the maximum (e.g. re-energizing a transmission line with trapped
charge). A conservative value for the maximum transient overvoltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 p.u.[2]. This value is a
conservative estimate of the transient overvoltage that is created at the point of application (e.g. a
substation) by switching a capacitor bank without a pre-insertion device (e.g. closing resistors).
At voltage levels where capacitor banks are not very common (e.g. 362 kV), the maximum
transient overvoltage of an “in-service” ac line are created by fault initiation on adjacent ac lines
and shunt reactor bank switching. These transient voltages are usually 1.5 p.u. or less [2]. It is
well known that these theoretical transient overvoltages will not be experienced at locations
remote from the bus at which they were created; however, in order to be conservative, it will be
assumed that all nearby ac lines are subjected to this same level of overvoltage. Thus, a
maximum transient overvoltage factor of 2.0 p.u. for 242 kV and below and 1.4 p.u. for ac
transmission lines 362 kV and above is used to compute the required clearance distances for
vegetation management purposes.
The overvoltage characteristics of dc transmission lines vary somewhat from their ac
counterparts. The referenced empirically derived transient overvoltage factor used to calculate
the minimum clearance distances from dc transmission lines to vegetation for the purpose of
FAC-003-2 will be 1.8 p.u.[3].
Example Calculation
An example calculation is presented below using the proposed method of computing the
vegetation clearance distances. It is assumed that the line in question has a maximum operating
voltage of 550 kVrms line-to-line. Using a per unit transient overvoltage factor of 1.4, the result
is a peak transient voltage of 629 kVcrest. It is further assumed that the line in question operates
at a maximum altitude of 7000 feet (2.134 km) above sea level.
The required withstand voltage of the air gap must be equal to or greater than 629 kVcrest. Since
the altitude is above sea level, (1) - (5) have to be iterated on to achieve the desired result.
Equation (9) can be used as an initial guess for the clearance distance.
Di =
(9)
8
3400 ⋅ k w ⋅ k g
Vm
0.85
−1
For our case here, Vm is equal to 629 kV, kw = 1.037 and kg = 1.3. Thus,
Di =
8
3400 ⋅ k w ⋅ k g
Vm
0.85
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=
−1
8
= 1.535m
3400 ⋅ 1.037 ⋅ 1.3
−1
629
0.85
(10)
35
NERC Standard FAC-003-2 Technical Reference
Using (2)-(5) and (8) the withstand voltage of the air gap is next computed. This value will then
be compared to the maximum transient overvoltage.
CFOS = k w ⋅ k g ⋅
−
3400
3400
= 1.037 ⋅ 1.3 ⋅
= 737.7 kV
8
8
1+
1+
D
1.535
A
−
2.134
8.6
8.6
=
δ e=
e =
0.78
GO =
(12)
CFOS
737.7
=
= 0.961
500 ⋅ D (500 ) ⋅ (1.535 )
(13)
m = 1.25 ⋅ GO (GO − 0.2 ) = 1.25 ⋅ 0.961(0.961 − 0.2 ) = 0.915
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ
m
(11)
3400
3400
0.915
⋅
= (0.85 )(1.037 )(1.3 )(0.78 )
8
8
1
1+
+
D
1.535
(14)
= 499.8 kV
(15)
The calculated Vm is less than 629 kV; thus, the clearance distance must be increased. A few
iterations using (2)-(5) and (8) are required until the computed Vm ≥ 629 kV. For this case it was
found that D = 1.978 m (6.49 feet) yielded Vm = 629.3 kV. Using this clearance distance the
following values were computed for the final iteration.
CFOS = k w ⋅ k g ⋅
−
3400
3400
= 1.037 ⋅ 1.3 ⋅
= 908.5 kV
8
8
1+
1+
D
1.978
A
−
2.134
8.6
8.6
=
δ e=
e =
0.78
GO =
(17)
CFOS
908.5
=
= 0.919
500 ⋅ D (500 ) ⋅ (1.978 )
(18)
m = 1.25 ⋅ GO (GO − 0.2 ) = 1.25 ⋅ 0.919(0.919 − 0.2 ) = 0.825
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ
FAC-003-2 Technical Reference
March 17, 2010
m
(16)
3400
3400
0.825
⋅
= (0.85 )(1.037 )(1.3 )(0.78 )
8
8
1+
1+
D
1.978
(19)
= 629.3kV
(20)
36
NERC Standard FAC-003-2 Technical Reference
Therefore, the minimum vegetation clearance distance for a maximum line to line ac operating
voltage of 550 kV at 7000 feet above sea level is 1.978 m (6.49 feet). Table 1 provides
calculated distances for various altitudes and maximum system operating ac voltages.
FAC-003-2 Technical Reference
March 17, 2010
37
NERC Standard FAC-003-2 Technical Reference
TABLE 1 — Minimum Vegetation Clearance Distances (MVCD)
For Alternating Current Voltages
( AC )
Nominal
System
Voltage
(kV)
( AC )
Maximum
System
Voltage
(kV)
765
800
500
550
345
362
230
242
161*
169
138*
145
115*
121
88*
100
69*
72
MVCD
feet
(meters)
Sea
level
8.06ft
(2.46m)
5.06ft
(1.54m)
3.12ft
(0.95m)
2.97ft
(0.91m)
2ft
(0.61m)
1.7ft
(0.52m)
1.41ft
(0.43m)
1.15ft
(0.35m)
0.82ft
(0.25m)
MVCD
feet
(meters)
3,000ft
(914.4m)
MVCD
feet
(meters)
4,000ft
(1219.2m)
MVCD
feet
(meters)
5,000ft
(1524m)
MVCD
feet
(meters)
6,000ft
(1828.8m)
8.89ft
(2.71m)
5.66ft
(1.73m)
3.53ft
(1.08m)
3.36ft
(1.02m)
2.28ft
(0.69m)
1.94ft
(0.59m)
1.61ft
(0.49m)
1.32ft
(0.40m)
0.94ft
(0.29m)
9.17ft
(2.80m)
5.86ft
(1.79m)
3.67ft
(1.12m)
3.49ft
(1.06m)
2.38ft
(0.73m)
2.03ft
(0.62m)
1.68ft
(0.51m)
1.38ft
(0.42m)
0.99ft
(0.30m)
9.45ft
(2.88m)
6.07ft
(1.85m)
3.82ft
(1.16m)
3.63ft
(1.11m)
2.48ft
(0.76m)
2.12ft
(0.65m)
1.75ft
(0.53m)
1.44ft
(0.44m)
1.03ft
(0.31m)
9.73ft
(2.97m)
6.28ft
(1.91m)
3.97ft
(1.21m)
3.78ft
(1.15m)
2.58ft
(0.79m)
2.21ft
(0.67m)
1.83ft
(0.56m)
1.5ft
(0.46m)
1.08ft
(0.33m)
MVCD
feet
(meters)
7,000ft
(2133.6m)
MVCD
feet
(meters)
8,000ft
(2438.4m)
MVCD
feet
(meters)
9,000ft
(2743.2m)
MVCD
feet
(meters)
10,000ft
(3048m)
MVCD
feet
(meters)
11,000ft
(3352.8m)
10.01ft
(3.05m)
6.49ft
(1.98m)
4.12ft
(1.26m)
3.92ft
(1.19m)
2.69ft
(0.82m)
2.3ft
(0.70m)
1.91ft
(0.58m)
1.57ft
(0.48m)
1.13ft
(0.34m)
10.29ft
(3.14m)
6.7ft
(2.04m)
4.27ft
(1.30m)
4.07ft
(1.24m)
2.8ft
(0.85m)
2.4ft
(0.73m)
1.99ft
(0.61m)
1.64ft
(0.50m)
1.18ft
(0.36m)
10.57ft
(3.22m)
6.92ft
(2.11m)
4.43ft
(1.35m)
4.22ft
(1.29m)
2.91ft
(0.89m)
2.49ft
(0.76m)
2.07ft
(0.63m)
1.71ft
(0.52m)
1.23ft
(0.37m)
10.85ft
(3.31m)
7.13ft
(2.17m)
4.58ft
(1.40m)
4.37ft
(1.33m)
3.03ft
(0.92m)
2.59ft
(0.79m)
2.16ft
(0.66m)
1.78ft
(0.54m)
1.28ft
(0.39m)
11.13ft
(3.39m)
7.35ft
(2.24m)
4.74ft
(1.44m)
4.53ft
(1.38m)
3.14ft
(0.96m)
2.7ft
(0.82m)
2.25ft
(0.69m)
1.86ft
(0.57m)
1.34ft
(0.41m)
*As designated by the Planning Coordinator
TABLE 1 (CONT.) — Minimum Vegetation Clearance Distances (MVCD)
For Direct Current Voltages
FAC-003-2 Technical Reference
March 17, 2010
38
NERC Standard FAC-003-2 Technical Reference
( DC )
Nominal Pole
to Ground
Voltage
(kV)
MVCD feet
(meters)
sea level
MVCD feet
(meters)
3,000ft
(914.4m)
Alt.
MVCD feet
(meters)
4,000ft
(1219.2m)
Alt.
MVCD feet
(meters)
5,000ft
(1524m) Alt.
MVCD feet
(meters)
6,000ft
(1828.8m)
Alt.
MVCD
feet
(meters)
7,000ft
(2133.6m)
Alt.
MVCD
feet
(meters)
(8,000ft
(2438.4m)
Alt.
MVCD
feet
(meters)
9,000ft
(2743.2m)
Alt.
MVCD
feet
(meters)
10,000ft
(3048m)
Alt.
MVCD
feet
(meters)
11,000ft
(3352.8m)
Alt.
±750
13.92ft
(4.24m)
15.07ft
(4.59m)
15.45ft
(4.71m)
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.9ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
±600
10.07ft
(3.07m)
11.04ft
(3.36m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
(13.54ft
4.13m)
±500
7.89ft
(2.40m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
±400
4.78ft
(1.46m)
5.35ft
(1.63m)
5.55ft
(1.69m)
5.75ft
(1.75m)
5.95ft
(1.81m)
6.15ft
(1.87m)
6.36ft
(1.94m)
6.57ft
(2.00m)
6.77ft
(2.06m)
6.98ft
(2.13m)
±250
3.43ft
(1.05m)
4.02ft
(1.23m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5ft
(1.52m)
5.17ft
(1.58m)
FAC-003-2 Technical Reference
March 17, 2010
39
NERC Standard FAC-003-2 Technical Reference
List of Acronyms and Abbreviations
ANSI
American National Standards Institute
IEEE
Institute of Electrical and Electronics Engineers
IVM
Integrated Vegetation Management
NERC
North American Electric Reliability Corporation
FAC-003-2 Technical Reference
March 17, 2010
40
NERC Standard FAC-003-2 Technical Reference
References
[1] Andrew Hileman, Insulation Coordination for Power System, Marcel Dekker, New York,
NY 1999
[2] EPRI, EPRI Transmission Line Reference Book 345 kV and Above, Electric Power Research
Council, Palo Alto, Ca. 1975.
[3] IEEE Std. 516-2003 IEEE Guide for Maintenance Methods on Energized Power Lines
[4] G. Gallet, G. Leroy, R. Lacey, I. Kromer, General Expression for Positive Switching
Impulse Strength Valid Up to Extra Long Air Gaps, IEEE Transactions on Power Apparatus
and Systems, Vol. pAS-94, No. 6, Nov./Dec. 1975.
[5] IEEE Std. 1313.2-1999 (R2005) IEEE Guide for the Application of Insulation Coordination.
[6] 2007 National Electric Safety Code
[7] EPRI, HVDC Transmission Line Reference Book, EPRI TR-102764 , Project 2472-03, Final
Report, September 1993
[8] ANSI. 2001. American National Standard for Tree Care Operations – Tree, Shrub, and
Other Plant Maintenance – Standard Practices (Pruning). Part 1. American National
Standards Institute, NY
[9] ANSI. 2006. American National Standard for Tree Care Operations – Tree, Shrub, and
Other Plant Maintenance – Standard Practices (Integrated Vegetation Management a.
Electric Utility Rights-of-way). Part 7. American National Standards Institute, NY.
[10] Cieslewicz, S. and R. Novembri. 2004. Utility Vegetation Management Final Report.
Federal Energy Regulatory Commission. Commissioned to support the Federal
Investigation of the August 14, 2003 Northeast Blackout. Federal Energy Regulatory
Commission, Washington, DC. pg. 39.
[11] Kempter, G.P. 2004. Best Management Practices: Utility Pruning of Trees.
International Society of Arboriculture, Champaign, IL
[12] Miller, R.H. 2007. Best Management Practices: Integrated Vegetation Management.
Society of Arboriculture, Champaign, IL.
[13] Yahner, R.H. and R.J. Hutnik. 2004. Integrated Vegetation Management on an electric
transmission right-of-way in Pennsylvania, U.S. Journal of Arboriculture. 30:295-300
[14] Results-based Initiative Ad Hoc Group. Acceptance Criteria of a Reliability Standard.
FAC-003-2 Technical Reference
March 17, 2010
41
Standards Announcement
Informal Comment Period Open
March 1–31, 2010
Now available at: http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
Project 2007-07: Transmission Vegetation Management
The Transmission Vegetation Management Standard Drafting Team is seeking comments on the following
documents until 8 p.m. Eastern on March 31, 2010:
FAC-003-2 — Transmission Vegetation Management Program
Mapping document (comparing this draft to previous)
Implementation plan
Special Notes for this Project
On January 14, 2010, the NERC Standards Committee endorsed the selection of FAC-003 as the proof-ofconcept for using “results-based” criteria for developing a reliability standard, and the drafting team has been
working with a consultant to apply a results-based approach to draft standard FAC-003-2. The overall approach
includes considerably more emphasis on the “concepts and assumptions” underlying the development of
requirements and goes beyond the steps most drafting teams use when developing a standard. Accordingly, the
“look and feel” of the vegetation management standard is quite different than NERC’s existing standards.
However, at the core is a set of mandatory and enforceable requirements with useful guidance supporting these
requirements, an approach NERC’s legal counsel has reviewed and finds acceptable.
In addition to the format changes, the Standards Committee authorized the drafting team to discontinue work in
developing a complete consideration of comments report for the comments received in response to the posting
of the second draft of FAC-003-2 (August 2009). Instead of posting an individual response to each comment,
the team has posted the comments along with a summary of the actions taken by the team in response to those
comments. The Standards Committee also authorized this approach going forward for this project, so this and
future postings will be considered informal comment periods. Please see the “Next Steps” section below and
the comment form for more information.
Instructions
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Lauren Koller at [email protected]. An off-line, unofficial copy of the comment
form is posted on the project page:
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
Next Steps
Since this is an informal comment period, the drafting team will post 1) the comments received, 2) a summary
of how the team used the comments, and 3) a redline version of the standard showing the changes made based
on the comments. More information about the scheduling for this project is available in the comment form for
this posting.
Project Background
The project is an update to FAC-003-1, which was approved in 2006. The items identified for revision include
the incorporation of FERC Order 693 comments related to applicability, procedural repairs to conform to the
current standards format and development procedure, technical updates and guidance to address stakeholder
suggestions, and the elimination of “fill-in-the-blank” components. More information is available on the project
page:
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
As mentioned, the NERC Standards Committee endorsed the use of Project 2007-07 Vegetation Management as
the prototype for the proof-of-concept for using the “results-based” criteria for developing a reliability standard.
More information about results-based standards can be found at:
http://www.nerc.com/filez/standards/Project2010-06_Results-based_Reliability_Standards.html
Applicability of Standards in Project
Transmission Owner
Specific facilities (see proposed standard for more information)
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards
development process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance,
please contact Shaun Streeter at [email protected] or at 609.452.8060.
Consideration of Comments on 3rd Draft of FAC-003-2 Transmission
Vegetation Management — Part of Project 2007-07 Vegetation
Management
The Vegetation Management Standard Drafting Team thanks all commenters who submitted
comments on the 3rd Draft of FAC-003-2 Transmission Vegetation Management. These
standards were posted for a 30-day public comment period from March 1, 2010 through
March 31, 2010. The stakeholders were asked to provide feedback on the standards
through a special Electronic Comment Form. There were 55 sets of comments, including
comments from more than 100 different people from over 60 companies representing 8 of
the 10 Industry Segments as shown in the table on the following pages.
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Gerry Adamski, at 609-452-8060 or at [email protected]. In addition, there is a
NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Index to Questions, Comments, and Responses
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
In response to comments received regarding potential for “double jeopardy”
and to provide differentiation between transmission lines designated as
having IROLs and Major WECC transfer paths from those that are not, the SDT
consolidated requirements R4 though R8 found in the August 2009 draft of
FAC-003-2 into two requirements in the latest draft of FAC-003-2 (new
requirements R1 and R2). Do you agree? Please explain. ............................... 10
The results-based reliability standard criteria focus on striving to achieve a
portfolio of performance-based, risk-based, and competency-based mandatory
reliability requirements that provide an effective defense-in-depth strategy for
achieving an adequate level of reliability of the bulk power system in lieu of
prescriptive requirements. Consequently, the SDT revised R1 and its subparts
found in the August 2009 draft of FAC-003-2 in favor of the text in the latest
draft of FAC-003-2 (new requirement R3). Do you agree? Please explain. ..... 20
Do you agree with the overall layout of the proposed template? If not, please
suggest an alternative layout. ........................................................................ 30
Do you agree with grouping the standard development timeline (previously
called roadmap) with the revision history, and the effective date(s) and
putting this administrative information up front before the Introduction
Section? Please explain. ................................................................................. 38
Do you agree with grouping the Requirements and Measures together, in one
Section now called Requirements and Measures? Please explain. .................. 44
Do you agree with grouping VRFs, Time Horizons and VSLs together, and
putting them in a table separate from the Requirements and Measures
Section? Please explain. ................................................................................. 51
Do you agree with the insertion of text boxes, where necessary, to help
readers better understand the basis of the Definitions and Requirements?
Please explain. ............................................................................................... 58
Do you agree with the addition of a Guideline and Technical Basis Section to
place technical materials and other related information that assists entities in
understanding how to comply with the standard but does not contain
mandatory actions/activities? Please explain. ............................................... 67
Do you prefer putting URL links to reference materials in the Guideline and
Technical Basis Section, or do you prefer putting the additional
technical/information materials in appendices, where needed, to supplement
the Guideline and Technical Basis Sections? Please explain. .......................... 76
Do you agree with the addition of the Background Section to allow provision
of background information, and to elaborate on the reliability-related drivers
for the standard/change? Please explain. ..................................................... 83
Do you agree with the addition of an Administrative Procedure Section to
place administrative/procedural requirements that are contained in the
existing standards but which do not meet the results-based or risk-based
criteria? Please explain. ................................................................................. 90
Is there any other information that should be included in the standard
document? If so, please explain why you feel that this information should be
included. ......................................................................................................... 98
Do you have any other comment regarding the draft FAC-003-2 Transmission
Vegetation Management standard that have not been addressed above? If yes,
please provide a reference to the section, requirement, or subrequirement
that you believe should be changed, added or deleted and the rationale for
your proposal. .............................................................................................. 105
2
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Commenter
1.
Group
Guy Zito
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
Northeast Power Coordinating Council
Additional Member
10
X
Additional Organization
Region
Segment Selection
1. Alan Adamson
New York State Reliability Council
NPCC
10
2. Gregory Campoli
New York Independent System Operator
NPCC
2
3. Roger Champagne
Hydro-Quebec TransEnergie
NPCC
2
4. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
5. Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
6. Ben Eng
New York Power Authority
NPCC
4
7. Brian Evans-Mongeon
Utility Services
NPCC
8
8. Mike Garton
Dominion Resources Services, Inc.
NPCC
5
9. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC
5
10. David Kiguel
Hydro One Networks Inc.
NPCC
1
11. Michael R. Lombardi
Northeast Utilities
NPCC
1
12. Randy MacDonald
New Brunswick System Operator
NPCC
2
13. Greg Mason
Dynegy Generation
NPCC
5
14. Bruce Metruck
New York Power Authority
NPCC
6
15. Michael Schiavone
National Grid
NPCC
1
3
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
16. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
10
17. Robert Pellegrini
The United Illuminating Company
NPCC
1
2.
Group
Jim Case
SERC OC Standards Review Group
Additional Member
X
Additional Organization
Region
SERC
1, 3
2. Alvis lanton
Southern Illinois Power Cooperative
SERC
1, 3, 5
3. Melinda Montgomery
Entergy
SERC
1, 3
4. Ken Parker
Entegra
SERC
5
5. Larry Rodriquez
Entegra
SERC
5
6. Gwen Frazier
Gulf Power
SERC
1, 3, 5
7. Stephen Mizelle
Southern
SERC
1, 3, 5
8. Brad Young
E.ON.US
SERC
1, 3, 5
9. John Troha
SERC
SERC
10
Louis Slade
Dominion
Additional Member
X
Additional Organization
X
Region
X
X
Segment Selection
1. Jalal Babik
Electric Market Policy
SERC
6, 5
2. Mike Garton
Electric Market Policy
MRO
6, 5
3. John Loftis
NERC compliance
SERC
1, 3
4. Angela Park
NERC compliance
SERC
1, 3
5. Aaron Jonas
Forestry
SERC
1
4.
Group
Carol Gerou
MRO's NERC Standards Review Subcommittee
Additional Member
10
Segment Selection
Ameren
Group
9
X
1. Gerald Beckerle
3.
8
X
Additional Organization
Region
Segment Selection
1. Chuck Lawrence
American Transmission Company
MRO
1
2. Tom Webb
Wisconsin Public Service Company
MRO
3, 4, 5, 6
3. Terry Bilke
Midwest ISO Inc.
MRO
2
4. Jodi Jenson
Western Area Power Administration
MRO
1, 6
5. Ken Goldsmith
Alliant Energy
MRO
4
6. Dave Rudolph
Basin Electric Power Cooperative
MRO
1, 3, 5, 6
4
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
7. Eric Ruskamp
Lincoln Electric System
MRO
1, 3, 5, 6
8. Joseph Knight
Great River Energy
MRO
1, 3, 5, 6
9. Joe DePoorter
Madison Gas & Electric
MRO
3, 4, 5, 6
10. Scott Nickels
Rochester Public Utilties
MRO
4
11. Terry Harbour
MidAmerican Energy Company
MRO
1, 3, 5, 6
5.
Group
Denise Koehn
Bonneville Power Administration
Additional Member
X
Additional Organization
X
Region
X
BPA Transmission Field Services
WECC
1
BPA Transmission Line Maintenance
WECC
1
Joe Spencer (SERC staff)
and Jack Gardner (VMS
chair)
10
Segment Selection
2. Don Swanson
Group
9
X
1. Chuck Sheppard
6.
8
X
SERC Vegetation Management Sub-committee
Additional Member
Additional Organization
Region
1. Randy Gann
Alabama Power Company
SERC
2. Gerald Beckerle
Ameren Services Company
SERC
3. Jeffrey Hackman
Ameren Services Company
SERC
4. John Neagle
Associated Electric Cooperative, Inc.
SERC
5. Billy George
Duke Energy Carolinas
SERC
6. Ron Adams
Duke Energy Carolinas
SERC
7. Robert Trimble
E.ON U.S. Services Inc. for LG&E & KU
SERC
8. Jim Case
Entergy
SERC
9. Ralph Hale
Entergy
SERC
10. Marc Tunstall
Fayetteville Public Works Commission
SERC
11. Reggie Wallace
Fayetteville Public Works Commission
SERC
12. Terry Wilson
PowerSouth Energy Cooperative
SERC
13. Jack Gardner
Progress Energy Carolinas
SERC
14. John Wolfmeyer
SERC Reliability Corporation
SERC
15. Jerry Lindler
South Carolina Electric & Gas Company
SERC
16. Richard Dearman
Tennessee Valley Authority
SERC
Segment Selection
5
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
7.
Group
Ben Li
Organization
Industry Segment
1
IRC Standards Review Committee
Additional Member
2
3
4
5
6
7
Additional Organization
Region
MRO
2
2. James Castle
NYISO
NPCC
2
3. Charles Yeung
SPP
SPP
2
4. Matt Goldberg
ISO-NE
NPCC
2
5. Mark Thompson
AESO
WECC
2
6. Patrick Brown
PJM
RFC
2
7. Steve Myers
ERCOT
ERCOT
2
Richard Kafka
Pepco Holdings, Inc. - Affiliates
Additional Member
X
Additional Organization
X
X
X
Region
Segment Selection
1. Pat Byrne
Pepco Holdings, Inc
RFC
1
2. Dave Paduda
Potojmac Electric Power Company
RFC
1
3. Steve Benn
Delmarva Power & Light
RFC
1
4. Olivia Watts
Atlantic City Electric
RFC
1
5. Steve Genua
Pepco Holdings, Inc
RFC
1
9.
Group
Sam Ciccone
FirstEnergy
Additional Member
X
Additional Organization
X
X
Region
X
X
Segment Selection
1. Rebecca Spach
FE
RFC
1
2. Katrina Schnobrich
FE
RFC
1
3. Dave Folk
FE
RFC
1, 3, 4, 5, 6
4. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
10.
Group
Carter B. Edge
Ad Hoc Group subteam formed to review draft
standard
Additional Member
10
Segment Selection
MISO
Group
9
X
1. Bill Phillips
8.
8
X
Additional Organization
Region
1. Peter Heidrich
FRCC
FRCC
2. Pat Huntley
SERC
SERC
3. Roman Carter
NERC
NA - Not Applicable
Segment Selection
6
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4. Steve Ruekert
WECC
WECC
5. Chris Hajovsky
RRI Energy
NA - Not Applicable
11.
Group
Frank Gaffney
Florida Municipal Power Agency (FMPA) and Some
Members
Additional Member
X
Additional Organization
X
4
5
6
X
X
X
Region
7
8
Segment Selection
1. Tim Byerle
New Smyrna Beach
FRCC
1, 3, 4
2. Jim Howard
Lakeland Electric
FRCC
1, 3, 5
3. Greg Woessner
Kissimmee Utilities Authority
FRCC
1, 3, 5
4. Lynne Mila
Clewiston
FRCC
1, 3, 4
5. Joe Stonecipher
Beaches Energy Services
FRCC
1, 3, 4
6. Cairo Venegas
Fort Pierce Utilities Authority
FRCC
1, 3, 4, 5
12.
Individual
Thomas Glock
Arizona Public Service Company
13.
Individual
Chip Turner
Tampa Electric Company
X
14.
Individual
Stephen Mizelle
Southen Company
X
15.
Individual
Silvia Parada Mitchell
TO/TOP
X
16.
Individual
John Buckley
Omaha Public Power District
X
17.
Individual
Howard Gugel
NERC Staff (12 staff members)
18.
Individual
Gary Cox
Tucson Electric Power Co.
X
19.
Individual
Edward Bedder
Orange and Rockland Utilities, Inc.
X
20.
Individual
Greg Lange
GCPD
21.
Individual
Christopher M. Crane
Westchester County Board of Legislators
22.
Individual
Robert Beadle
North Carolina EMC
23.
Individual
Mary Hetz
Ameren
X
24.
Individual
James W. Smith
ITC Holding
X
25.
Individual
Alan Gale
City of Tallahassee (TAL)
9
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
7
10
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
5
6
26.
Individual
Virginia Cook
JEA
X
27.
Individual
Weston Davis
Central Maine Power, Iberdrola USA
X
28.
Individual
Eric Senkowicz
FRCC Manager of Operations
29.
Individual
Samuel Stonerock
Southern California Edison Company
X
X
X
X
30.
Individual
Jon Kapitz
Xcel Energy
X
X
X
X
31.
Individual
Chris Scanlon
Exelon
X
X
X
X
32.
Individual
Jody Nelson
Ga Transmission Corp
X
33.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
X
X
34.
Individual
Greg Rowland
Duke Energy
X
X
X
X
35.
Individual
Laura Zotter
ERCOT ISO
Individual
Gerald T. Paulson
Western Area Power Administration - Upper Great
Plains Region
X
37.
Individual
Louis C. Guidry
Cleco
X
X
X
38.
Individual
Tom Hayes
East Kentucky Power Cooperative, Inc.
X
X
X
39.
Individual
Jack Gardner
Progress Energy Carolinas
X
X
X
40.
Individual
Kevin Howard
Western Area Power Administrtaion
X
41.
Individual
James Sharpe
South Carolina Electric and Gas
X
42.
Individual
George Czerniewski
Consolidated Edison Company of New York, Inc.
X
43.
Individual
Michael Pakeltis
CenterPoint Energy
X
44.
Individual
Darryl Curtis
Oncor Electric Delivery
X
45.
Individual
Thad Ness
American Electric Power (AEP)
X
46.
Individual
Dan Rochester
Independent Electricity System Operator
47.
Individual
Richard Dearman
Tennessee Valley Authority
36.
X
4
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
8
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
48.
Organization
Industry Segment
1
Individual
Jim Fulton
BGE (on behalf of parent/affiliate companies: CEG,
CPSG, CECG, CNE & CENG)
X
49.
Individual
Edward Davis
Entergy Services
X
50.
Individual
Jason Shaver
American Transmission Company
X
51.
Individual
David Rocchio
Utility Risk Management Corporation
52.
Individual
Earl Burnside
PPL Electric Utilities Corporation (NCR00884)
53.
Individual
Jianmei Chai
Consumers Energy
54.
Individual
John Humphrey
Nebraska Public Power District
55.
Individual
Christopher M. Crane
Westchester County Board of Legislators
56.
Individual
Mike Gammon
KCPL
X
2
3
X
5
6
X
X
7
8
9
X
X
X
4
X
X
X
X
9
10
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
1. In response to comments received regarding potential for “double jeopardy” and to provide differentiation
between transmission lines designated as having IROLs and Major WECC transfer paths from those that are
not, the SDT consolidated requirements R4 though R8 found in the August 2009 draft of FAC-003-2 into two
requirements in the latest draft of FAC-003-2 (new requirements R1 and R2). Do you agree? Please explain.
Summary Consideration:
Organization
Yes or No
Question 1 Comment
ERCOT ISO
Exelon
North Carolina EMC
Westchester County Board of
Legislators
Do not have enough knowledge on this to provide response.
Response:
Nebraska Public Power District
No
Although it does provide some flexibility to the TO, it will be difficult to determine an encroachment into the
MVCD. It would easier to implement if R1 and R2 were only applicable when there was an outage on the
transmission system.
No
Dominion does not agree with the inclusion of facilities that WECC designates as ‘major transfer paths’ in a
continent-wide standard. We suggest that, if the SDT wishes to include such reference and these facilities are
meant to be treated or synonymous with either IROL or SOL, that the SDT add a proposal to adopt and define
a suitable term for inclusion into the Glossary of Terms
No
Encroachment into the MCVD should require the owner to take immediate corrective action to mitigate the
threat. Such an encroachment should not be reportable as a violation. Owners may be hesitant to
Response:
Dominion
Response:
Cleco
10
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
communicate possible vegetation threat conditions to the TOP or proper authority if they believe it will be
reported as a violation. We recommend the SDT consider modifying the measure for R1 and R2 to be
applicable only in the interruption of the transmission facility.
Response:
NERC Staff (12 staff members)
No
NERC Staff does not see a need to have two requirements (R1 and R2) which differentiation between
transmission lines designated as having IROLs and Major WECC transfer paths from those that are not with
two different Violation Risk Factors. The standard as drafted applies to all 200kv and above lines. The
Violation Risk Factor for all 200 kV and above lines should be “High”. R2 should be deleted and R1 should be
rewritten to be:R1. The Transmission Owner shall prevent vegetation from encroaching within the Minimum
Vegetation Clearance Distance (MVCD) of applicable Transmission line conductors to avoid a Sustained
Outage.
No
Requirements 1 & 2 are identical except for their applicability (R1 for IROL elements and elements in the
WECC Transfer Paths; R2 for all other lines =>200 KV). It is not readily apparent as to why there is a need to
distinguish between the two. Referencing the Table 2 "VRF" and "VSL" matrix indicates that R1 has a "High"
VRF and R2 has a "Medium" VRF. If this is the only reason, then consider adding, at a minimum, a
"Rationale" box explaining that reasoning.Also, the definition of MVCD needs to be a defined term or included
in R 1 & 2, e.g., “Minimum Vegetation Clearance Distance is the calculated minimum distanced stated in feet
(meters) to prevent spark-over between conductors and vegetation for various altitudes and operating
voltages as set forth in Table 2.” See comments to # 7 and # 13.
No
This is a reliability standard for 230 kV and above and those lower voltages designated by the RRO. An
outage is an outage and the utility should be held accountable no matter if they are or are not designated.
No
While we agree with the development of a second requirement to provide for the distinction between line
segments that are critical for reliability, in R1, a regional distinction should not be embedded in a national
standard. We also strongly disagree that perfect compliance with R2, as stated, would improve reliability. If a
line is operated to avoid projected post contingent overloads, then the tripping thereof due to any cause has
Response:
Xcel Energy
Response:
Arizona Public Service Company
Response:
SERC OC Standards Review
Group
11
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
no effect on BES reliability. A more prudent approach for the lines covered by R2 could be the requirement to
achieve 3 sigma or 4 sigma performance over a year’s time. Requirement 2, as stated, is not cost effective,
and may produce an unjust and unreasonable outcome to rate payers.While this draft clarifies (from version
FAC-003-1) that sustained outages are compliance violations and eliminates the “double jeopardy” which was
errantly introduced in the last draft of FAC-003-2 (when sustained outages were clearly defined as
compliance violations), we suggest that the team adjust R2 as previously mentioned. This draft provides a
mechanism to address the difference in outages that have impact to grid reliability from those that have an
impact only to local lines and associated customer reliability. The use of observed MVCD as a violation and in
the violation severity level matrix: o drives the right behaviors for improving reliability (by proactively
identifying and removing vegetation before it can become an imminent threat or cause an outage) o
eliminates the need to perform detail engineering/surveying/theoretical calculations before cutting vegetation,
o formalizes the informal interpretations that have resulted from FAC-003-1 enforcement and o allows the
vegetation field operations to focus on facts and remain practical rather than theoretical.
Response:
American Transmission
Company
Yes
Bonneville Power Administration
Yes
Central Maine Power, Iberdrola
USA
Yes
City of Tallahassee (TAL)
Yes
Consumers Energy
Yes
Duke Energy
Yes
Florida Municipal Power Agency
(FMPA) and Some Members
Yes
FRCC Manager of Operations
Yes
12
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Ga Transmission Corp
Yes
GCPD
Yes
ITC Holding
Yes
Manitoba Hydro
Yes
Omaha Public Power District
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southen Company
Yes
TO/TOP
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Question 1 Comment
1. NSRS agrees with the revisions that the drafting team has made and agrees with the combining of four
requirements into two. NSRS prefers the MVCD methodology to the minimum clearance distance
methodology due to the fact that there is only one measurement to contend with versus two.2. If a company
has a line with a standing IROL could they be found in violation of both the requirements R1 and R2? If so,
the NSRS recommends combining R1 and R2.3. Please clarify the need for R1 and R2. Why were lines with
IROL separated out from lines without IROLs?
Response:
13
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
American Electric Power (AEP)
Yes or No
Question 1 Comment
Yes
American Electric Power agrees with this change.
Yes
Because real-time observation in Measurement 1 would require an actual measurement for comparison to
Table 2 to be defendable as a violation, the SRC suggests replacing observation with measurement.
The
SRC would suggest deleting the phrase "to avoid a sustained outage" as that phrase does not add any clarity
to either of the two requirements.
There do not seem to be any encroachments that the SDT will allow. If
there are encroachments that are considered allowable, who is responsible for making that consideration?
And what would be considered a "sustained" outage?Minimum Vegetation Clearance Distance (MVCD) is a
capitalized term used in Requirements 1, 2 and 7 but is not defined in the NERC Glossary of Terms Used in
Reliability Standards nor is a definition proposed in this standards action. Either a definition should be
proposed or the capitalization should be removed.
Yes
BGE agrees with the consolidation of R4 through R8 into two requirements in the FAC-003-2 draft.
Yes
Creating two specific requirements removes the potential for double jeopardy.
Yes
SCE agrees that the consolidation of Requirements R4-R* resolves the "double jeopardy" issue.
Yes
The change in the draft serves to consolidate, clarify and remove the “double jeopardy” as stated above. This
is an improvement in the standard.
Response:
IRC Standards Review
Committee
Response:
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Response:
Ameren
Response:
Southern California Edison
Company
Response:
Tampa Electric Company
Response:
14
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
CenterPoint Energy
Yes or No
Question 1 Comment
Yes
The differentiation in the Violation Risk Factor for R1 versus R2 seems appropriate.
Consolidated Edison Company of
New York, Inc.
Yes
The elements that comprise IROLs must be clearly communicated to each Transmission Owner and must be
consistent across North America.
Orange and Rockland Utilities,
Inc.
Yes
The elements that comprise IROLs must be clearly communicated to each Transmission Owner and must be
consistent across North America.
Yes
The most recent draft of the standard consolidated R4-R8 results in clearer requirements that meet the results
based criteria and addresses the “double jeopardy” issue. However, there is concern with the differentiation
of lines designated as having IROLs and Major WECC transfer paths from those that are not, as is proposed
in the Applicability section 4.2 and subsequently in requirements R1 and R2. As stated in the background
section: “This Standard focuses on transmission lines to prevent those vegetation related outages that could
lead to Cascading. It is not intended to prevent customer outages due to tree contact with lower voltage
distribution system lines. For example, localized customer service might be disrupted if vegetation were to
make contact with a 69kV transmission line supplying power to a 12kV distribution station. However, this
Standard is not written to address such isolated situations which have little impact on the overall Bulk Electric
System.” It must be recognized that in some systems, outages on lines operated at voltages greater than 69
kV, 200 kV for example, have localized impact only and do not lead to Cascading. Concurring with the
background, a line should be subject to this standard only if a vegetation related outage “could lead to
Cascading”, or could have a “significant impact” on the system. It does not depend on whether it is an IROL
line or not.A performance based methodology is used in NPCC to determine if an outage on a line can cause
a “significant impact” on the system. The lines identified by this methodology are not identified according to
their voltages, but rather by their impact on the system, regardless of the voltage.The introduction of “two”
subcategories of BES - an IROL and a non-IROL - appears to just differentiate between high VRF and
medium VRF. Furthermore, in the Applicability section, the IROL “variable” is mentioned only for lines
operated below 200 kV. What about lines operated at or above 200 kV lines? Why not have a single
Application item stating: overhead transmission lines operated at any voltage whose outages have a
significant impact on the system? A Table could define what is considered “significant”.There are standards
for vegetation management on the distribution system, and there are standards for higher voltage systems.
This standard should focus on lines with high impact on the system when a vegetation outage occurs.Utilities
will not let the vegetation encroach on other lines, but an importance will be given to vegetation management
Response:
Response:
Northeast Power Coordinating
Council
15
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
on “critical” lines for the reliability of the whole system. On other lines, if an outage occurs, it will have
localized impact.A “Results-Based Reliability Standard” should first focus on the “critical” lines.If it is the intent
of NERC or the industry to ensure that a vegetation outage causes no more than a fixed level of load loss, it
should say so in a requirement.If the IROL “variable” is retained, identification of the transmission elements
that comprise IROLs must be officially communicated to the Transmission Owners. This must be done either
through a requirement in this, or another standard.
Response:
Progress Energy Carolinas
Yes
The previous version (FAC-003-1) was not developed with individual outages listed as a requirement or a
violation. The previous drafts of version 2 (FAC-003-2) have improved on FAC-003-1 by defining sustained
outages from within the Right-of-Way as violations. However, the recent drafts of FAC-003-2 also introduced
a potential for ‘double jeopardy’ when clarifying that sustained outages and MVCD encroachments were
(‘binary’) requirements/violations. This latest draft clarifies the expected performance into two concise
requirements that provide for differentiation in severity levels and risk factors, eliminating the unintended
‘double jeopardy’. The inclusion of the use of observed MVCD as a violation of R1/R2 and in the violation
severity level matrix drives the right behaviors for improving reliability (by proactively identifying and removing
vegetation before it can become an imminent threat or cause an outage) , eliminates the need to perform
detail engineering/surveying/theoretical calculations before cutting vegetation, formalizes the informal
interpretations that have resulted from FAC-003-1 and allows the vegetation field operations to focus on facts
(and remain practical rather than theoretical). Progress Energy believes that the R1 and R2 changes to this
draft are a significant improvement over FAC-003-1. This version draft: clarifies real-time MVCD and
sustained outages as a requirement; provides for differentiation between grid impacting outage events and
outage events to lines primarily associated with customer reliability; introduces a performance barrier/defense
that is fact based - eliminating the need to determine compliance through theoretical calculations that rely on
design assumptions (e.g., mechanical behavior of aged conductor), prior design criteria/code versions (i.e.,
code clearances in effect at time of design) and detail site measurements (e.g., “survey” quality
measurements and local environmental conditions at time of measurement/event).
Yes
The simplification and clarification improves the ability of Registered Entities to comply thereby enhancing
reliability.
Response:
JEA
Response:
16
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Independent Electricity System
Operator
Yes or No
Question 1 Comment
Yes
This change addresses the perceived “double jeopardy” risk.
Yes
This does not reduce the Standards effectiveness on the cascading issue or discount any outage on
applicable lines subject to this Standard in the electric Transmission system.
Yes
This draft adequately addresses the "double jepoardy" issue. The use of the Minimum Vegetation Clearance
Distances simplifies recommended maintenance process for field personnel and eliminates the need to
perform costly and time consuming engineering studies prior to trimming or removing vegetation.
Yes
This draft clarifies (from version FAC-003-1) that sustained outages are compliance violations and eliminates
the “double jeopardy” which was errantly introduced in the last draft of FAC-003-2 (when sustained outages
were clearly defined as compliance violations). This draft provides a mechanism to address the difference in
outages that have impact to grid reliability from those that have an impact only to local lines and associated
customer reliability. The use of observed MVCD as a violation and in the violation severity level matrix: o
drives the right behaviors for improving reliability (by proactively identifying and removing vegetation before it
can become an imminent threat or cause an outage) o eliminates the need to perform detail
engineering/surveying/theoretical calculations before cutting vegetation, o formalizes the informal
interpretations that have resulted from FAC-003-1 enforcement and o allows the vegetation field operations
to focus on facts and remain practical rather than theoretical.
Yes
This is a very efficient and logical consolidation of requirements.
Yes
This is not a critical issue for the WAPA - UGPR.
Response:
Oncor Electric Delivery
Response:
East Kentucky Power
Cooperative, Inc.
Response:
SERC Vegetation Management
Sub-committee
Response:
Western Area Power
Administrtaion
Response:
Western Area Power
17
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
Yes
This method effectively recognizes the difference in reliabilty risks among various lines based on their value to
the transmission grid.
Yes
We agree that R1 and R2 are beneficial, but believe that they should be explained in greater detail for much
greater clarity to reflect their intent. Our understanding is that R1 applies to ALL IROL's and ALL Major
WECC Transfer Path lines, regardless of voltage, and R2 is centered around ALL lines operated at voltages
200 kV and above but are not classified as IROL/WECC lines. Our understanding of the term "applicable line
conductor" in R2 refers back to the facilities defined in Facilities - Section 4.2 and as modified by the phrase in
R2: "which are not elements of an IROL and are not a Major WECC transfer path, (operating within Rating
and Rated Electrical Operating Conditions)". However the appropriateness of our assumed reference back to
Section 4.2 and the modification contained in R2 is not clear. It also is not clear that the term "applicable line
conductor" in R2 is the same as "applicable line conductor" in R6. We suggest the term "applicable line
conductor" be specifically defined as that term is intended to be applied in R2, and the term "applicable line
conductor" be defined as that term is intended to be applied in R6.
Yes
We agree that the new R1 and R2 alleviate the potential double jeopardy issue as well as differentiate the
high and medium risk factor transmission lines. However, we offer the following comments and suggestions
for improvement:It is not clear how the Transmission Owner (TO) will determine which lines are associated
with IROLs. Upon reviewing standard FAC-014 Req. R5, which requires the communication of SOLs and
IROLs, the required communication of IROLs to the TO is not specified. There needs to be a tie between this
standard and the FAC-014 standard, which will require a revision to FAC-014. Unfortunately, this issue will
create a gap if FAC-014 is not revised and submitted to FERC in parallel with the submittal of FAC-003-2 to
FERC. This may require immediate action such as an urgent action SAR or other appropriate actions.If our
suggestion to revise FAC-014 is not possible at the present time, then we suggest an alternative course of
action to include language in R1 of FAC-003 to aid the TO in obtaining the information regarding lines
associated with IROLs. We propose adding the following sentence to R1: "The Transmission Owner can
request information regarding transmission lines associated with an IROL from its Planning Coordinator."
Administration - Upper Great
Plains Region
Response:
Tennessee Valley Authority
Response:
Entergy Services
Response:
FirstEnergy
18
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
Yes
We understand the differentiation to be around the intent that those transmission lines designated as having
IROLs and Major WECC transfer paths pose a more significant threat to the reliability of the BES and that
encroachment of the MVCD in these cases are relatively more significant. We suggest that this be clarified in
the rationale.
No
The measures for R1 and R2 are zero tolerance for encroachments into the MVCD that did not result in a
“contact” with the transmission facility. Considering the substantial number of miles of transmission involved,
the complexities in anticipation of vegetation growth with numerous growth variables, vegetation management
limitations imposed by other regulations or requirements, and unexpected transmission events that require
substantial efforts regarding physical restoration, it is not reasonable or practical for the measures here to
include encroachments that do not result in an interruption of transmission service. Recommend the SDT
consider modifying the measures for R1 and R2 to be applicable only in the interruption of a transmission
facility.
Response:
Ad Hoc Group subteam formed to
review draft standard
Response:
KCPL
Response:
19
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
2. The results-based reliability standard criteria focus on striving to achieve a portfolio of performance-based,
risk-based, and competency-based mandatory reliability requirements that provide an effective defense-indepth strategy for achieving an adequate level of reliability of the bulk power system in lieu of prescriptive
requirements. Consequently, the SDT revised R1 and its subparts found in the August 2009 draft of FAC-003-2
in favor of the text in the latest draft of FAC-003-2 (new requirement R3). Do you agree? Please explain.
Summary Consideration:
Organization
Yes or No
Question 2 Comment
American Transmission
Company
East Kentucky Power
Cooperative, Inc.
ERCOT ISO
Westchester County Board of
Legislators
Tampa Electric Company
No
A more in-depth technical review of this requirement is required. Our response is predicated upon the
following quote from the draft standard; “...considering all possible locations the conductor may occupy
assuming operation within Rating and Rated Electrical Operating Conditions.”
No
As written, R3 does not provide enough clarity as to what should be included in a documented transmission
vegetation management program. R3 should be expanded to include what should be included in the
transmission plan. Such as:R3. Each Transmission Owner shall have a documented transmission vegetation
management program that describes how it conducts work on its Active Transmission Line Rights of Way to
avoid Sustained Outages due to vegetation, considering all possible locations the conductor may occupy
assuming operation within Rating and Rated Electrical Operating Conditions. The transmission vegetation
management program shall:3.1 Specify the methodologies that the Transmission Owner uses to control
vegetation.[1] 3.2 Specify a Vegetation Inspection frequency of at least once per calendar year that takes
into account local[2] and environmental factors. 3.3 Require an annual work plan that identifies the
Response:
NERC Staff (12 staff members)
20
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
applicable lines to be maintained and associated work to be performed during the year. It shall be flexible to
adjust to changing conditions and to findings from Vegetation Inspections. Adjustments to the plan within the
year are permissible. The plan shall take into consideration permitting and scheduling requirements from
landowners or regulatory authorities. It shall support the objectives of the transmission vegetation
management program and utilize the methodologies outlined in the transmission vegetation management
program. 3.4 Require a process or procedure for response to imminent threats[3] of a vegetation-related
Sustained Outage. The process or procedure shall specify actions which shall include immediate
communication of the threat to the Transmission Operator or proper operating authority. The process or
procedure shall specify what conditions warrant a response.3.5 Specify an interim corrective action process
for use when the Transmission Owner is constrained from performing vegetation maintenance as planned.
3.6 Specify the maintenance approach used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that Table 1 clearances in Attachment 1 are never violated. The
maintenance approach shall consider the sag and sway of the conductor throughout its operating range under
rated conditions.[1] ANSI A300, Tree Care Operations - Tree, Shrub, and Other Woody Plant Maintenance Standard Practices, while not a requirement of this standard, is considered to be an industry best practice.[2]
Local factors include treatment cycle, extent and type of treatment, and their relationship to the normal growth
rate.[3] The term “imminent threat” refers to a vegetation condition which is placing the transmission line at a
significant risk of a Sustained Outage. Refer to Technical Reference for examples of imminent threat
procedures and conditions for implementation.
Response:
Consumers Energy
No
Consumers Energy strongly disagrees with the MVCD as presented in this version of the standard. These
distances do not provide an adequate safeguard to prevent outages since the conductor position relative to
the vegetation is sensitive to electric load and wind at any particular moment while vegetation height is not.
Measurements M1 and M2 require real-time observation of a violation of MVCD to be reportable. As
presented, vegetation growing beneath the conductor with a clearance of MVCD + 1 foot is not reportable.
However, this same conductor may sag due to load increase or move due to wind displacement within hours
of the real-time observation. If great enough, the sag or displacement may move the conductor in contact
with the vegetation resulting in an outage just hours after being deemed compliant.At a minimum the MVCD
should be designed to provide the Gallet clearance distance at maximum sag or wind displacement
(whichever is greater) at all times. No matter when the line is cleared of vegetation or inspected for
vegetative conditions, if the enhanced MVCD is being met an outage cannot occur until further vegetative
growth occurs. Furthermore, for line clearing operations, tree crews do not and cannot determine in the field
the maximum potential sag or wind displacement to know how much vegetation to clear. They require much
clearer instructions with a set amount of clearing distance to obtain at the time of work. This distance must
21
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
account for maximum sag, wind displacement and the Gallet distance at a minimum.
Response:
Cleco
No
Encroachment into the MCVD should require the owner to take immediate corrective action to mitigate the
threat. Such an encroachment should not be reportable as a violation. Owners may be hesitant to
communicate possible vegetation threat conditions to the TOP or proper authority if they believe it will be
reported as a violation. We recommend the SDT consider modifying the measure for R1 and R2 to be
applicable only in the interruption of the transmission facility.
No
Grant believes that R1 and R2 should be the entire standard and the rest of the requirements should be in
guidelines and supplementary materials to assist in meeting the two results based requirements. We
understand that some risk-based and competency based requirements are necessary for some standards.
Not this one. No grow-in caused outages is the objective. Requiring a specific plan does not show
competency, it just shows you have a plan. Feels very much like the existing standards. "Show us your
Documentation".
No
R3 specifies “...considering all possible locations the conductor may occupy assuming operation within Rating
and Rated Electrical Operating Conditions.” Although both “Rating” and “Rated Electrical Operating
Conditions” appear in the NERC Glossary, inspection of these definitions shows that they are very vague, and
“Rated Electrical Operating Conditions” uses the word “reasonably”, a term FERC has previously indicated as
being unacceptable. From a practical standpoint this seems to allow too much latitude to an entity to do the
least amount of trimming and not consider the extra sag and swing caused by some of the more extreme
operating conditions that “may” occur, such as loading to an STE or DAL limit during a higher velocity wind
than normal, coupled with a higher ambient temperature. An entity could potentially claim that vegetation was
trimmed to normal load levels, normal facility loading sag, and minimum velocity wind speed swings, and be
within the tolerance of the standard as we interpret it. The Drafting Team should clarify what the expectation
is with regard to line loading, sag, and swing due to wind speed and the types of operating conditions it
deems to be justified to create a more exact requirement.
Response:
GCPD
Response:
Northeast Power Coordinating
Council
Response:
22
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Nebraska Public Power District
Yes or No
Question 2 Comment
No
same concern as item 1.
No
The TVMP must include clearances bewteen trees and conductors at time of vegetation management
work.Suggest that the TVMP require the use of qualified personnel to manage this program.
No
This standard lacks accountability and transparency. This is a reliability standard and the industry is to
prevent outages within the active ROW. It doesn’t matter if the vegetation grows-in, blows-in or falls into the
conductor these are all outages. One is no less of an outage than the other one. They should be treated
equally and the utility should be held accountable for lack of maintaining the transmission system.
No
We agree that the previous R1 was too prescriptive and are in favor of the new Requirement R3. However,
we do not agree with all the wording of R3 as well as the Rationale box for R3. 1. Requirement R3 - The
phrase "considering all possible locations the conductor may occupy assuming operation within Rating and
Rated Electrical Operating Conditions" is confusing. We like the wording from the previous (Draft 2) of FAC003-2 and suggest the following rewording of this phrase: "considering all possible locations the conductor
may occupy throughout its operating range under all rated conditions."2. Rationale box for Req. R3 - We
suggest removing the first sentence in the Rationale box for R3. The need to provide a basis on the intent and
competency of the TO in maintaining vegetation is not explicitly stated in the requirement. Also, we are not
sure what is meant by "competency". If it is referring to minimum required competencies for personnel
performing vegetation management, that is outside the scope of this standard.
Response:
Central Maine Power, Iberdrola
USA
Response:
Arizona Public Service Company
Response:
FirstEnergy
Response:
Ameren
Yes
Bonneville Power Administration
Yes
City of Tallahassee (TAL)
Yes
23
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Consolidated Edison Company of
New York, Inc.
Yes
Duke Energy
Yes
Entergy Services
Yes
Exelon
Yes
FRCC Manager of Operations
Yes
Ga Transmission Corp
Yes
Manitoba Hydro
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
Orange and Rockland Utilities,
Inc.
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Tennessee Valley Authority
Yes
TO/TOP
Yes
Tucson Electric Power Co.
Yes
Question 2 Comment
24
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
Utility Risk Management
Corporation
Yes
Xcel Energy
Yes
MRO's NERC Standards Review
Subcommittee
Yes
1. NSRS agrees with the revisions to R3. With regard to operations within Ratings and Rated Conditions, are
operations after a contingency considered to be within Ratings and Rated Conditions?2. Could wording be
added to R3 to specify rated conditions include National Electric Safety Code conditions or assumptions?
Yes
Although FMPA agrees with the intent of the Measures, FMPA is concerned that the measures M1 and M2
may not meet the purpose of the measures as stated in the latest draft version of the Standard Processes
Manual, which states that that a Measure “(p)rovides identification of the evidence or types of evidence
needed to demonstrate compliance with the associated requirement.” Instead, M1 and M2 provide examples
of evidence that would be used to determine non-compliance, not used to determine compliance.
Yes
American Electric Power agrees with this change.
Yes
BGE agrees with the R3 text in the latest draft of FAC-003-2.
Yes
Dominion agrees and finds this approach superior to existing which sometimes appears to be more
administratively focused.
Yes
Given the basic performance required in R1 and R2 of this version, I agree that specifics about what is
Response:
Florida Municipal Power Agency
(FMPA) and Some Members
Response:
American Electric Power (AEP)
Response:
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Response:
Dominion
Response:
JEA
25
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
included in the plan are not needed. Each entity should be encouraged to write their plan so that the
occasional human errors and failures that are inevitable still lead to compliance with the performance aspects
of this standard. The team should be sure that the measures do not require unfailing perfect execution of this
procedure so that entities are encouraged to minimize this document.
Response:
ITC Holding
Yes
ITC feels that this draft is an improvement by clarifying the action expected by this requirement (“competencybased” program specific methodology documentation) and separating other implementing (“risk based”)
actions from FAC-003-1 as new requirements within this draft version. ITC also agrees with results-based
reliability, a standard principle that is driven by relevant reliability requirements and measureable results
rather than prescriptive requirements driven by documentation.The term “bulk power system” should not be
used in the comment form or any other documentation associated with FAC-003-2.
Yes
Old Requirement R1 has been distilled down to its essential elements with the removal of the detailed subrequirements that were previously included. This places the onus of developing an effective transmission
vegetation management program (TVMP) on the asset owners where it ought to be, since they have the
requisite expertise. Guidance is however provided in the Technical Reference document to assist
Transmission Owners in developing a TVMP that in their view works for them, and achieves the overall
objective of preventing those vegetation related outages that could lead to Cascading. By specifying the
“what” appropriately and leaving the “how” to the entity, the entity is now in the best position to determine the
most effective deployment of its resources for meeting the goals of the standard.
Yes
R3 focuses on its intended impact on Sustained Outages without being overly prescriptive.
Yes
SCE prefers the results-based approach to crafting reliability standards because it provides utilities with the
necessary flexibility to develop internal criteria based on widely accepted best practices and industry
innovations.
Response:
Independent Electricity System
Operator
Response:
CenterPoint Energy
Response:
Southern California Edison
Company
Response:
26
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Western Area Power
Administrtaion
Yes or No
Question 2 Comment
Yes
The old Draft 2 version of R1 was developed to give the regulatory entities substantial and tangible
information from which to judge the adequacy of a TO's overall approach to program management. The old
Draft 2 version of R1 was purposely crafted in this detailed manner as an alternative to attempting to manage
the problematic CCZ concepts contained in Draft 1. Industry strongly rejected the CCZ management
concepts contained in Draft 1 in the first comment period. It appears that the current Draft 3 version of R3
has lost some of the content needed to fully substitute for the management of Draft 1 CCZ concepts. The
addition of an implementation requirement intended to measure the full execution and success of the overall
management approach identified by a TO in response to the new R3 may help to address this shortcoming.
As currently worded, the requirement to simply execute a flexible annual work under the new R7 in Draft 3
does appear extensive enough to fulfill this need.
Yes
The RBS defense-in-depth strategy for this Standard does provide an adequate level of reliability. The
Standards purpose statement refers to the electric Transmission system and corresponding applicable lines
not the BPS or BES as currently defined in the NERC glossary or being proposed (NOPR) RM09-18-000.
Removing prescriptive requirements allows utilities flexibility to document their program and perform their
vegetation management to achieve the goal of no outages that lead to cascading.
Yes
The SRC agrees with the intent of R3, but questions the need for inspection postponements to be limited to
natural "disasters". A well-planned inspection may be delayed by a common lighting storm. While there is a
need to conduct the inspections and those inspections could be done anytime within the TO's own plans - the
SDT may want to modify the exception to be natural disasters or other conditions that are reported within 5
business days and agreed to as an excused condition by the Regional Reliability Organization.
Yes
The term “bulk power system” should not be used in the comment form or any other documentation
associated with FAC-003-2.
Yes
This separates implementing actions such as inspections, annual plans and imminent threat procedures from
TVMP methodology (which proves competency of the program).This draft is an improvement by clarifying the
Response:
Oncor Electric Delivery
Response:
IRC Standards Review
Committee
Response:
Southen Company
Response:
Progress Energy Carolinas
27
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
action expected by this requirement (“competency-based” program specific methodology documentation) and
separating other implementing (“risk based”) actions from FAC-003-1 as new requirements within this draft
version.
Response:
SERC OC Standards Review
Group
Yes
This separates implementing actions such as vegetation inspections, performing annual work plans and
responding to imminent threats from the required documentation of the TVMP methodology (which proves
competency of the program).This draft is an improvement by clarifying the action expected by this
requirement (program specific methodology documentation requirement) and separating other implementing
actions from FAC-003-1 as new requirements in this draft version.
SERC Vegetation Management
Sub-committee
Yes
This separates implementing actions such as vegetation inspections, performing annual work plans and
responding to imminent threats from the required documentation of the TVMP methodology (which proves
competency of the program).This draft is an improvement by clarifying the action expected by this
requirement (program specific methodology documentation requirement) and separating other implementing
actions from FAC-003-1 as new requirements in this draft version.
Yes
WAPA - UGPR agrees with a reliability based standard. In the plains states, we have fewer trees than many
utilities, so having prescriptive requirements that assume we have lines running through forested areas
seems to mandate an excessive amount of detail. We prefer to keep our program very simple -- perform
periodic inspections to identify vegetation problems and then direct applicable resources in to take care of the
problem. Our hope is that a results-based reliability standard will provide some flexibility for those utilities with
smaller scale vegetation encroachments.
Yes
While the new R3 is less prescriptive than the old R1, it appears to stray from criteria #4 for developing
results-based standards, as described in this comment form. It appears to require only the development of a
document. We understand that in some cases this cannot be avoided. We believe that this is one of those
cases where the reliability objective of building competency in considering all possible locations the conductor
may occupy and assuming operation within Rating and Rated Electrical Operating Conditions over-rides our
reluctance in requiring a registered entity to produce a document rather than a result. We suggest that in a
future revision to standard that this can be combined with R7 to create a comprehensive requirement that the
Response:
Western Area Power
Administration - Upper Great
Plains Region
Response:
Ad Hoc Group subteam formed to
review draft standard
28
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
entity have a vegetation management program that demonstrates it is able to perform those actions
necessary to keep vegetation out of the MVCD.
Response:
KCPL
No
The measures for R1 and R2 are zero tolerance for encroachments into the MVCD that did not result in a
“contact” with the transmission facility. Considering the substantial number of miles of transmission involved,
the complexities in anticipation of vegetation growth with numerous growth variables, vegetation management
limitations imposed by other regulations or requirements, and unexpected transmission events that require
substantial efforts regarding physical restoration, it is not reasonable or practical for the measures here to
include encroachments that do not result in an interruption of transmission service. Recommend the SDT
consider modifying the measures for R1 and R2 to be applicable only in the interruption of a transmission
facility.
Response:
29
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
3. Do you agree with the overall layout of the proposed template? If not, please suggest an alternative layout.
Summary Consideration:
Organization
Yes or No
Question 3 Comment
No
a.) ATC believes that the “Guideline and Technical Basis” section does not belong within the NERC Standard.
ATC feels there are parts of this section that appear to obligate the TO with additional mandatory
requirements. (please refer to additional details in Question #8 below) b.) ATC believes the “Measures”
section immediately following the Requirement is helpful and placement is appropriate, however, the
introductory statement in R1 and R2 is poorly worded. For example, M1 currently states: “ Evidence of
violation of Requirement R1 is limited to:” ATC feels this is a negative approach and recommends that it be
stated in a positive manner such as”” Evidence of compliance to R1 would be to: o Not have any vegetationrelated Sustained Outages due to a grow-in.” c.) ATC would like to clarify whether the “Rational” boxes
remain within the final standard. It seems appropriate to have this information but that it would be better to
have this information appear in the “Guideline and Technical Basis” section.
No
Don't need all the extra requirements beyond R2.
No
FMPA appreciates the improvements and has additional suggestions. Please see responses to the remainder
of the questions, and below, for suggestions:The evidence retention should be grouped with the Measures for
ease of creating a records retention schedule for the standards and requirements.Do we really need a
“Compliance Monitoring and Enforcement Processes” section of the standards? Are there any standards that
don’t have all of these activities?
TO/TOP
Westchester County Board of
Legislators
American Transmission
Company
Response:
GCPD
Response:
Florida Municipal Power Agency
(FMPA) and Some Members
Response:
30
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
City of Tallahassee (TAL)
Yes or No
Question 3 Comment
No
I would delete the Rationale in favor of keeping the Guideline and Technical Basis. The Guideline appears to
be more in-depth than the Rationale. This makes the Rationale unnecessary.
No
NPCC participating members want to thank the drafting team for the hard work devoted to developing this
standard, and recognize the difficult issues of producing the first “results based” proof of concept standard
and offer the following, not as criticism, but as helpful suggestions for their consideration based on a cross
section of stakeholder reactions to the draft. 1) Measures are compliance related elements and should not
appear immediately after the requirements. The older template had the compliance elements grouped
together in a separate section, and we suggest this continues. In the past there have been instances of
RSAW (Reliability Standards Audit Worksheets) not clearly matching the standard’s requirements or
measures. We suggest that this initiative with a results based requirement consistently involve the
development of the associated RSAWs to ensure coordination, and also that the requirement results in a
performance based, competency, or risk based reliability criterion. 2) Effective dates have become a
complex issue. We suggest that rather than having an effective date table in the standard, this type of
information be restricted to the implementation plan and ultimately reside in a NERC relational database
which is currently under discussion/development. NPCC participating members suggest that the “Effective
Dates” section be replaced with “NERC BOT Adopted Date”. Due to their complexities, FERC and Provincial
approvals are something best left to implementation plans and databases. 3) “Rationale” boxes appearing in
the Requirements section are problematic. If a “Rationale” box is required to explain part of the requirement
then the requirement needs to be revised. For example, in R7 the requirement states that a TO shall execute
a flexible annual vegetation management plan. Flexible in this context could have many different
interpretations, yet in the “Rationale” box the use of the word flexible is clearly delineated to mean work may
be deferred if not an imminent threat. In general we believe these boxes add little value, and if the
requirement can’t be understood without the “Rationale” then the requirement needs to be worded
appropriately. Suggest these types of explanatory statements go into guidance documents, or supporting
technical documents, and do not appear in the “Requirements” sections. 4) Also, there seems to be some
confusion regarding the Administrative Procedure section. There seems to be requirements embedded within
it, e.g. “The Transmission Owner will submit a quarterly report to its Regional Entity, or the Regional Entity’s
designee, identifying all Sustained Outages of transmission lines determined by the Transmission Owner....”
Is this an enforceable aspect of the standard? If so, are there any other documents such as the NERC Rules
of Procedure “ROP” or compliance related documents such as the CMEP that have to be changed? NPCC
participating members recognize that this is a results based standard. Administrative requirements should be
removed from the standards, and dealt with elsewhere (such as the ROP). 5) The Guideline and Technical
Basis section contains valuable information, but this adds to the volume of the document. The Drafting Team
Response:
Northeast Power Coordinating
Council
31
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
should consider moving this to a separate document. In viewing the standards as a whole, the FAC-003
standard is relatively straightforward when compared to the developing of other standards such as the TPL
standard. A similar approach, if applied to the TPL would result in a standard with potentially hundreds of
pages. If the type of work appearing in this section is envisioned for other more complex standards such as
TPL, the DT should consider separating out this section as a single supporting document. 6) Do FERC and
the Provincial governmental authorities approve just the requirements in the Standard, or the whole package?
Response:
FRCC Manager of Operations
No
See responses to #8, 10, 11 and 13.
No
The proposal to move the time horizon and the VRF to a separate independent section is not useful. Take
for example R1 and R2 of the proposed standard. A careful read of the two requirements and measurements
would indicate that there is no difference between them and that it would be better to have one requirement
for all conductors. It is not until the reader gets to the compliance section does the VRF difference show up.
There is no savings to removing the previous format's parenthetical inclusion of time horizon and VRF at the
end of the requirement. The Independent Section can contain all of the proposed information but don't remove
it from the requirement. The format of the standard would not be an issue if NERC would develop a
standards database. Then, the database could be queried in any format the user desires.
No
The Standard itself is several pages into the document. The VRFs/VSLs should be in the
Requirements/Measures Section. The Background, Rationale, Administrative Procedures are additional
information and should be located in an Appendix so it doesn’t clutter the Standard.
No
We suggest combining and moving the Rationale, Background, Guideline and Technical Basis, and Technical
Reference to a consolidated appendix because there is much duplication in the wording within each of these
sections, and independently they may be misinterpreted as being an integral part of the Requirements and
Measurements which they are not. The Requirements and Measurements should stand clearly on their own.
The appendix should contain examples of how to meet the requirements under various circumstances. The
appendix should be supplementary and optional to the Standard.It is also not clear if the Administrative
Response:
IRC Standards Review
Committee
Response:
ERCOT ISO
Response:
CenterPoint Energy
32
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
Procedure is a mandatory activity. It would be helpful if the intent of this section was stated within the
Standard.
Response:
NERC Staff (12 staff members)
No
We suggest using two colors for explanatory information - yellow for information that is temporary - such as
the information explaining the difference between the approved and proposed definitions of “Vegetation
Inspection” - and using blue for all boxes that are intended to remain in the approved standard.We feel that
the Standards Committee Process Subcommittee should pursue adding a statement from NERC’s legal
department indicating which parts of the standard are enforceable. In the meantime, we suggest using the
standard template in order to clearly define the enforceable parts of the standard. The section identified as
“Guideline and Technical Basis” is not really a guideline (typically a proposed process for completing work)
and is not really a “technical basis” (typically a summary of research or engineering judgment, etc. used to
explain the reasoning for something). The information in this section is explaining how the drafting team
expects compliance with the requirements to be measured. We suggest revising the heading to “Application
Guidelines.” This is the term that was originally proposed by the Results-based team and is the heading
identified in the proposed Standard Processes Manual.
Response:
Ad Hoc Group subteam formed to
review draft standard
Yes
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
Central Maine Power, Iberdrola
USA
Yes
Cleco
Yes
Consumers Energy
Yes
Duke Energy
Yes
33
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Entergy Services
Yes
Exelon
Yes
Independent Electricity System
Operator
Yes
Manitoba Hydro
Yes
Nebraska Public Power District
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Orange and Rockland Utilities,
Inc.
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southen Company
Yes
Southern California Edison
Company
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Question 3 Comment
34
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
Xcel Energy
Yes
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE is supportive of the proposed template.
Yes
Coupling the measures and rationale with each requirement make the standard easier to follow and to
implement.
Yes
Dominion agrees, but suggests that reference(s) to figure(s) and table(s) contain links that can take reader to
that section of the document. This is superior to having to scroll through document. If the reference(s) is
external to this standard document, links may be harder to manage but should at least reference a common
webpage(s) used by NERC for the posting of such documents.
Yes
ITC feels that the overall layout of the standard (a) improves readability, (b) clarifies expectations, (c) reduces
confusion associated with referencing between pages, and (4) allows for background information and the SDT
rationale to accompany the standards but we would suggest locating Guideline and Technical Basis after
Requirements and Measures for better reference accessibility.
MRO's NERC Standards Review
Subcommittee
Yes
N/A
Tampa Electric Company
Yes
None
Western Area Power
Administration - Upper Great
Plains Region
Yes
None
Response:
JEA
Response:
Dominion
Response:
ITC Holding
Response:
35
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
Yes
Overall, we like the layout of the standard, especially the Effective Date table in the front of the standard, the
combination of Requirements and Measures, and the grouping of the VRF, Time Horizons, and VSL into one
table. However, we would like to see a clearer delineation between the mandatory requirements and the
guidance and rationale information. The standard should explicitly be clear as to what is mandatory and what
is not, which may even require moving the "Rationale" text boxes out of the Requirements and Measures
section. FE believes the information presented in the Rationale text boxes can be effectively covered in the
"Guidelines and Technical Basis".
Yes
The format could be enhanced by moving the Guidelines and Technical Basis section forward to be included
with the corresponding Requirement, Measure, and Rationale. This would be helpful because it is awkward
flipping back and forth between these two sections when trying to fully understand a requirement.
Yes
The general layout is quite effective. Still, it would be good to keep the VRFs and time horizons within the text
of the requirement.
Yes
The layout is adequate but many things are needing further explanation such as the MVCD.
Yes
The overall layout improves readability, clarifies expectations, reduces confusion associated with referencing
between pages, and allows for background information and SDT rationale to accompany the standards
(reducing the need for interpretation).
SERC OC Standards Review
Group
Yes
The overall layout improves readability, clarifies expectations, reduces confusing references between pages,
and allows for background and rationale to accompany standards.
SERC Vegetation Management
Yes
The overall layout improves readability, clarifies expectations, reduces confusing references between pages,
FirstEnergy
Response:
Western Area Power
Administrtaion
Response:
Pepco Holdings, Inc. - Affiliates
Response:
Ga Transmission Corp
Response:
Progress Energy Carolinas
Response:
36
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Sub-committee
Question 3 Comment
and allows for background and rationale to accompany standards.
Response:
East Kentucky Power
Cooperative, Inc.
Yes
The overall layout is greatly improved. This draft is easier to read and understand and clarifies the expected
actions required in the standard.
Yes
The overall template layout is acceptable
Yes
This aids the understanding of the standard.
Yes
This draft is much more user friendly and easier to follow; appreciate the follow up information.
Yes
We do believe the overall layout is effective but the SDT should consider putting the Background Section
before the Applicability Section in the Introduction and also try to reduce any redundant verbiage in the
Background Section and the Guideline and Technical Basis Section. A twenty-one page Standard is too
lengthy and the supporting Technical Reference document properly addresses many of the issues mentioned
in the Guideline and Technical Basis Section.
Response:
American Electric Power (AEP)
Response:
Tennessee Valley Authority
Response:
Ameren
Response:
Consolidated Edison Company of
New York, Inc.
Response:
KCPL
Yes
37
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
4. Do you agree with grouping the standard development timeline (previously called roadmap) with the revision
history, and the effective date(s) and putting this administrative information up front before the Introduction
Section? Please explain.
Summary Consideration:
Organization
Yes or No
Question 4 Comment
No
For this standard one must read through 7 pages before getting to the reason for the posting. The
administrative information should be relegated to the end of the posting not the beginning.Under exceptions in
the Effective Dates section of the standard, IROLs are referenced as only being created by the Planning
Coordinator. Because Reliability Coordinators must also establish IROLs per FAC-011 and FAC-014, we
suggest that reference to the Planning Coordinator should be redacted and IROLs should be discussed
regardless of whether the Planning Coordinator or Reliability Coordinator creates them.
Consolidated Edison Company of
New York, Inc.
No
The only issue we have with the administrative information being before the Introduction Section is with the
Definition of Terms Used in the Standard Section. We feel this should be part of the Introduction and not a
stand alone section.
Orange and Rockland Utilities,
Inc.
No
The only issue we have with the administrative information being before the Introduction Section is with the
Definition of Terms Used in the Standard Section. We feel this should be part of the Introduction and not a
stand alone section.
No
This information should be located at the end so that it doesn’t distract from the main purpose of the
Standard. It is cumbersome to read through several pages before getting to the actual language of the
FRCC Manager of Operations
TO/TOP
Westchester County Board of
Legislators
IRC Standards Review
Committee
Response:
Response:
ERCOT ISO
38
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
Standard.
Response:
Ad Hoc Group subteam formed to
review draft standard
Yes
American Transmission
Company
Yes
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
Central Maine Power, Iberdrola
USA
Yes
City of Tallahassee (TAL)
Yes
Cleco
Yes
Consumers Energy
Yes
Duke Energy
Yes
Exelon
Yes
GCPD
Yes
JEA
Yes
Manitoba Hydro
Yes
Nebraska Public Power District
Yes
39
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
NERC Staff (12 staff members)
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southen Company
Yes
Tennessee Valley Authority
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Western Area Power
Administrtaion
Yes
Ameren
Yes
Appreciate the ability to reference up front.
Yes
BGE agrees with the proposed grouping and placement of these items.
Response:
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
40
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
Yes
Dominion agrees that the new format is superior to the old. However, we suggest a table of contents be
added to include at a minimum, sections for (1) Definitions of Terms Used in Standard (2) Effective dates, (3)
Introduction, (4) requirements and measures (5) Compliance (6) Time Horizons, VRF and VSLs (7)
Administrative (8+) guidelines, technical basis, tables or figures referenced in standard.
Yes
Easy to follow.
Yes
I do not see a problem with this change.
Yes
It is acceptable to do so, however it is not clear as to how the effective date portion will be incorporated in a
final version of the standard. Will there be some kind of cover page to at least indicate the standard or will it
just be a small title bar at the top? (i.e. - what does page 1 of the standard look like?)
Yes
ITC agrees with locating the revision history and administrative information before the introduction. This
alignment improves clarity and readability by providing a single location for this information.
Yes
Just a question, when the standard becomes effective, how will it be posted? FMPA assumes that this section
will move to the end of the standard instead of the front when approved.
Yes
No preference.
Response:
Dominion
Response:
Entergy Services
Response:
Ga Transmission Corp
Response:
Xcel Energy
Response:
ITC Holding
Response:
Florida Municipal Power Agency
(FMPA) and Some Members
Response:
CenterPoint Energy
41
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
Tampa Electric Company
Yes
None
Northeast Power Coordinating
Council
Yes
NPCC participating members believe this is acceptable. However our previous response to question 3 above
still applies regarding the Effective Date section. It should be removed from the standard, and either appear
in an implementation plan, or more effectively in a NERC relational database.
Yes
Since in this case the effective dates of all requirements are all the same, we believe the effective dates table
could be significantly condensed.
Yes
The format provides for better clarification and is easier to read and comprehend.
Yes
The NSRS likes the way the standards is now formatted and finds it more user friendly.
Yes
These changes make sense to American Electric Power.
SERC OC Standards Review
Group
Yes
This format adds clarity and improves readability.
SERC Vegetation Management
Sub-committee
Yes
This format adds clarity and improves readability.
Response:
Independent Electricity System
Operator
Response:
East Kentucky Power
Cooperative, Inc.
Response:
MRO's NERC Standards Review
Subcommittee
Response:
American Electric Power (AEP)
Response:
Response:
42
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Progress Energy Carolinas
Yes or No
Question 4 Comment
Yes
This grouping improves clarity and readability by providing a single location for this information.
Yes
WAPA - UGPR is neutral on location of these items.
Yes
We agree that grouping the administrative information up front is logical and makes for a cleaner
presentation.
Yes
We agree with having a detailed table showing the effective dates of each requirement. However, we would
like to see NERC go back into the table and specify the dates of NERC and FERC effective dates once they
are known. Having the statement "1st day of the 1st quarter one year after applicable regulatory approval" in
the standard does not help the user of the standard when they are working towards compliance, and requires
them to go elsewhere to find when the approvals took place. All this information should be in the standard
when available and NERC staff should be afforded the latitude to do so even without needing to use its Errata
process. Placing the dates directly within the standard is more convenient for the end user.
Response:
Western Area Power
Administration - Upper Great
Plains Region
Response:
Southern California Edison
Company
Response:
FirstEnergy
Response:
KCPL
Yes
43
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
5. Do you agree with grouping the Requirements and Measures together, in one Section now called Requirements
and Measures? Please explain.
Summary Consideration:
Organization
Yes or No
Question 5 Comment
Westchester County Board of
Legislators
Xcel Energy
We are indifferent as to the placement of the Measures, however it does appear to create awkward shaped
paragraphs when Requirements and Measures are place around Rationale boxes.
Response:
Northeast Power Coordinating
Council
No
As commented earlier in question 3, this is a compliance related issue and should be in the Compliance
section. NPCC participating members believe clear concise requirements should be the focus, and inserting
measures immediately after the requirements adds little value. In addition, RE compliance staffs who use the
metrics find no value to moving it as well. This format would ease working with the document as a working
draft, but should not be in an adopted document. Consider moving Measures back to the compliance section,
and add a reference to a Measure’s wording stating which requirement the measure refers to. Only adding a
statement when the Requirement and Measure numbering don’t line up could be considered.
Response:
Bonneville Power Administration
Yes
Cleco
Yes
Duke Energy
Yes
IRC Standards Review
Committee
Yes
Manitoba Hydro
Yes
44
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Nebraska Public Power District
Yes
NERC Staff (12 staff members)
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southen Company
Yes
Southern California Edison
Company
Yes
TO/TOP
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Western Area Power
Administrtaion
Yes
Central Maine Power, Iberdrola
USA
Yes
Question 5 Comment
Adds clarity between requirements and measures .
45
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
Response:
Arizona Public Service Company
Yes
APS doesn’t agree with all of the requirements.
Yes
BGE agrees it makes sense to group these two sections together.
Yes
Coupling the measures and rationale with each requirement make the standard easier to follow and to
implement.
Yes
Dominion finds this format improved over the existing as reader can more easily correlate the requirement
(process/procedures) to the measure (evidence).
Yes
Exelon agrees this is a good practice that will help ensure Requirements and Measures are aligned
Yes
FMPA agrees that grouping the Requirements and Measures together in one section is a great idea; however,
to realize even more benefit, we now have the opportunity to eliminate redundant wording, e.g., M3 can be
shortened to: “A documented transmission vegetation management program” and eliminate the rest of the
words that are redundant with R3.
Yes
Great addition and improvement!! Much clearer and easier to follow.
Response:
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Response:
JEA
Response:
Dominion
Response:
Exelon
Response:
Florida Municipal Power Agency
(FMPA) and Some Members
Response:
Entergy Services
46
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
Response:
City of Tallahassee (TAL)
Yes
However, if you keep the Rationale text boxes, keep the Measures in the same column as the requirement.
This will result in a more consistent “look and feel” to all the requirements (M3 for R3 is the example).
Yes
In addition the DT could also eliminate redundant wording in the standard requirement, e.g., M3 can be
shortened to: “A documented transmission vegetation management program” and eliminate the rest of the
words that are redundant with R3 or use words in the measure that refer back "to the requirement above".
Yes
Including a specific measure with each requirement adds clarity; however, it isn’t clear whether each measure
is exclusive to the requirement that it follows. Is it possible that some requirements will have multiple
measures that are not listed immediately following the requirement?
Yes
ITC agrees with Requirements and Measures grouped together
Yes
Makes the standard template much easier to read and use.
Yes
Much easier to follow in this format.
Yes
Much more user friendly to be able to see the requirement and the measurement together for clarification.
Response:
FRCC Manager of Operations
Response:
ERCOT ISO
Response:
ITC Holding
Response:
GCPD
Response:
Consumers Energy
Response:
Ameren
Response:
47
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
CenterPoint Energy
Yes
No preference.
MRO's NERC Standards Review
Subcommittee
Yes
NSRS prefers to have the requirements, measures, VRFs, VSLs and Time Horizons together instead of
referencing to another page or part of the standard.
Yes
See ATC’s comment on “Measures” in Question #3 above.
Yes
This aides in understanding of the standard. Grouping the VSL and VRF for each requirement along with the
measurement could be beneficial too.
Yes
This also is OK no problem with the layout.
Yes
This change also improves readability and improves understanding of the requirement.
SERC OC Standards Review
Group
Yes
This format adds clarity and improves readability.
SERC Vegetation Management
Sub-committee
Yes
This format adds clarity and improves readability.
Yes
This format provides for better readability and clarification.
Response:
American Transmission
Company
Response:
Tennessee Valley Authority
Response:
Ga Transmission Corp
Response:
Progress Energy Carolinas
Response:
Response:
East Kentucky Power
48
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
Cooperative, Inc.
Response:
Tampa Electric Company
Yes
This improves the clarity and understanding to the requirements.
Yes
This is useful to avoid having to move back and forth between separate sections to find out what is needed to
show that a requirement is met. We do not have a strong preference for this re-grouping however.
Yes
WAPA - UGPR believes this makes it easier to identify the requirement and what we need to provide to
demonstrate with are in compliance with the requirement.
Yes
We agree that grouping the Requirements and Measures together is convenient when utilizing the document
for compliance.
Yes
We agree with grouping the Requirements and Measures together since it does add another level of clarifying
description for our field forces who are ensuring compliance during vegetation management activities. The
Measures for R1 and R2 describe evidence of violation while the Measures for the remaining Requirements
R3 - R7 describe evidence of compliance. All Measures should be written consistently as either evidence of
compliance or evidence of violation.
Yes
We agree with grouping the Requirements and Measures together since it does add another level of clarifying
description for our field forces who are ensuring compliance during vegetation management activities. The
Measures for R1 and R2 describe evidence of violation while the Measures for the remaining Requirements
R3 - R7 describe evidence of compliance. All Measures should be written consistently as either evidence of
Response:
Independent Electricity System
Operator
Response:
Western Area Power
Administration - Upper Great
Plains Region
Response:
FirstEnergy
Response:
Consolidated Edison Company of
New York, Inc.
Response:
Orange and Rockland Utilities,
Inc.
49
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
compliance or evidence of violation.
Response:
Ad Hoc Group subteam formed to
review draft standard
Yes
We agree with the understanding that the specific requirements of the standard are the enforceable elements
of the standard. The rationale and measures add clarity to support a results-based requirement.
Yes
Yes, this is a more readable format.
Response:
American Electric Power (AEP)
Response:
KCPL
Yes
50
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
6. Do you agree with grouping VRFs, Time Horizons and VSLs together, and putting them in a table separate from
the Requirements and Measures Section? Please explain.
Summary Consideration:
Organization
Yes or No
Question 6 Comment
Westchester County Board of
Legislators
Pepco Holdings, Inc. - Affiliates
No
Agree that the grouping of the subject material is appropriate, but it is not necessary to also remove the
VRFs and time horizons from the requirement.
No
I would prefer to have the VRF’s and time horizons together with the requirements and measures section. The
VSL’s separate is appropriate as that is not information needed while complying, but only after a failure.
No
If the VRF’s Time Horizons and VSLs were listed in with each requirement and measure section, it would
eliminate the need for cross referencing 2 sources of information.
No
It would be nice to see the associated VRF’s and Time Horizon with the requirements. No text, but
referenced.
No
The associated VRFs/Time Horizons/VSLs should be identified alongside each Requirement so that all
relevant criteria for a given Requirement are organized together.
Response:
JEA
Response:
Manitoba Hydro
Response:
Oncor Electric Delivery
Response:
ERCOT ISO
Response:
51
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
IRC Standards Review
Committee
Yes or No
Question 6 Comment
No
While we agree that the grouping of the subject material is appropriate, it is not necessary to also remove the
VRFs and time horizons from the requirement.
No
While we like grouping VRFs, Time Horizons and VSLs together in a table, we would also like to see each
VRF and Time Horizon listed with its requirement. It’s a small amount of information that we think adds value
in both places.
Response:
Duke Energy
Response:
Ad Hoc Group subteam formed to
review draft standard
Yes
Ameren
Yes
American Transmission
Company
Yes
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
Central Maine Power, Iberdrola
USA
Yes
Cleco
Yes
Consolidated Edison Company of
New York, Inc.
Yes
Consumers Energy
Yes
Dominion
Yes
52
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
East Kentucky Power
Cooperative, Inc.
Yes
Exelon
Yes
FRCC Manager of Operations
Yes
Independent Electricity System
Operator
Yes
Nebraska Public Power District
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
Orange and Rockland Utilities,
Inc.
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southern California Edison
Company
Yes
TO/TOP
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Question 6 Comment
53
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
Western Area Power
Administrtaion
Yes
Xcel Energy
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Again it is good to have this information together in place of referencing some other page or part of the
Standard.
Yes
Also please consider parsing out a copy of each VSL/VRF with in each individual requiremnt and measure
part of the standard as mentioned in question 5 above.
Yes
BGE supports grouping VRFs and VSLs together in a separate table.
Yes
Consider putting the appropriate line from the table with each requirement in the body of the standard in
addition to the table format. This does make the standard longer and does introduce some redundancy, but it
would make each requirement easier to read and interpret on a “standalone” basis.
Yes
I believe this makes it easier to follow the Requirements.
Yes
ITC Agree's
Response:
Tennessee Valley Authority
Response:
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Response:
Southen Company
Response:
City of Tallahassee (TAL)
Response:
ITC Holding
Response:
54
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Florida Municipal Power Agency
(FMPA) and Some Members
Yes or No
Question 6 Comment
Yes
Much easier to find and understand
CenterPoint Energy
Yes
No preference.
Entergy Services
Yes
This grouping helps to clarify the manner in which the violations will be ranked.
Yes
This grouping improves the template used by previous versions by providing a single view of the impact and
risk that has been associated with each requirement. Progress Energy believes that this change would also
be improved if the applicable VRF/VSL/Time Horizon table rows were also listed with each requirement
(consolidating pertinent info with the requirement). Another improvement would be including the penalty
matrix (or including a URL link) to facilitate Transmission Owner discussions with property owners and other
governmental agencies.
Yes
This improves the template used by previous versions by providing a single view of the impact consideration
of each requirement. An improvement would be also listing the applicable table rows with each requirement
which consolidates all pertinent info with the requirement. Also, adding the penalty matrix would facilitate
discussions with property owners/agencies resisting maintenance activates.
Yes
This improves the template used by previous versions by providing a single view of the impact consideration
of each requirement. An improvement would be also listing the applicable table rows with each requirement
which consolidates all pertinent info with the requirement. Also, adding the penalty matrix would facilitate
discussions with property owners/agencies resisting maintenance activates.
Yes
This is audit stuff that does need to stay together.
Response:
Response:
Progress Energy Carolinas
Response:
SERC OC Standards Review
Group
Response:
SERC Vegetation Management
Sub-committee
Response:
GCPD
55
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
Yes
This is consistent with FERC’s determination that these are compliance elements and not part of the standard
requirements. It will also assist with compliance determinations.
Yes
WAPA - UGPR is neutral on location of these items.
Yes
We agree with grouping these items together. It may also be beneficial to include links directly in the table to
explanations of VRFs, Time Horizons, and VSLs so that someone unfamiliar with, for instance, what a "LongTerm Planning" horizon means, they could look it up.
Yes
We agree with the idea behind the grouping. However, according to the Reliability Standard Development
Procedure - Version 7, although a non-binding poll is taken of the VRFs and VSLs, it appears that the Time
Horizons are part of the standard that is still subject to stakeholder ballot. The SDT should explain how this
will be made clear to balloters. Is there intent to modify the standards process to remove the time horizons
from the portions of the standard that are subject to ballot? This issue needs to be addressed by the
Standards Committee Process Subcommittee.
Yes
With all of the VRFs, Time Horizons and VSLs grouped together it facilitates the overall understanding of
these factors as they relate to the standard.
Yes
Yes this was a good change.
Response:
Northeast Power Coordinating
Council
Response:
Western Area Power
Administration - Upper Great
Plains Region
Response:
FirstEnergy
Response:
NERC Staff (12 staff members)
Response:
Tampa Electric Company
Response:
Ga Transmission Corp
56
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
Response:
American Electric Power (AEP)
Yes
Yes; this format is more user-friendly.
Response:
KCPL
Yes
57
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
7. Do you agree with the insertion of text boxes, where necessary, to help readers better understand the basis of
the Definitions and Requirements? Please explain.
Summary Consideration:
Organization
Yes or No
Question 7 Comment
Westchester County Board of
Legislators
Exelon
No
Additional clarifications should be included in appendices or reference documents. Including them with the
requirements and measures will cause confusion concerning what the compliance obligation is. This will
introduce uncertainty to the compliance monitoring process.
No
Although the test boxes provide some addition help, ATC believes that these text boxes should appear in the
Guideline and Technical Basis section and that whole section should appear in a companion document to the
standard but not be included as part of the standard. Also, see ATC’s comment on Rational in Question #3
above.ATC believes that guidance information should not be reviewed and approved by FERC and the
inclusion of such information within the standard opens this language up to FERC’s oversight and approval.
No
As stated in question 3 above, NPCC participating members believe crisp, clear results based requirements
require no further explanation. Requirements must be written so they are clearly understood. Text boxes
clutter up the standard. Questions could arise if these add “pseudo” requirements to the standards, and there
is any inconsistency in what is stated about requirements. NPCC strongly suggests their removal in favor of
clear, measurable, and high quality results based requirements.
No
I would delete the Rationale in favor of keeping the Guideline and Technical Basis. The Guideline appears to
be more in-depth than the Rationale. This makes the Rationale redundant and unnecessary.
Response:
American Transmission
Company
Response:
Northeast Power Coordinating
Council
Response:
City of Tallahassee (TAL)
58
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
No
It is not clear how the information in the text boxes will be used to determine compliance with the
Requirements and Measures. It appears that in the Definition of Terms Used in Standard section that the text
boxes add to the definitions or are footnotes to historical information. The Definitions should stand on their
own and be robust enough to ensure they are helpful in determining compliance with the Requirements and
Measures. In the Requirements and Measures section, the text boxes appear to contain partial information
from the Guideline and Technical Basis, and Technical Reference. In all cases the information is not helpful
and provides incomplete information. The text boxes should be deleted and pertinent information to
compliance should be incorporated into the Definitions, Requirements, and Measures. Any explanatory text
or examples should be moved to an appendix as supplementary and optional to the Standard.
No
It is not clear whether the information in the text boxes is “For Information Only.” While the additional
information may be helpful, it appears to add sub-requirements within the Standard. This information could
be included under a “Rationale” section in an Appendix. However, if the information clouds the purpose of the
Requirements or dictates how to comply, then it should be eliminated completely.
No
Not necessary given the “Guidelines and Technical Basis”.
No
Text boxes and other supporting information are a benefit to the reader as a clarification guide, but should be
placed in something other than the Standard.
No
The concept of text boxes needs further discussion. The idea of using text boxes for clarity and explanation is
valuable, but is the material in the text box mandatory? If it includes mandatory material than it is not a good
idea - all mandatory requirements must be in the requirement. If the text boxes are retained to explain how a
phrase is being used (e.g. to make clear what compound actions apply to what compound time frames), then
yes, this approach can be invaluable.
Response:
CenterPoint Energy
Response:
ERCOT ISO
Response:
Consumers Energy
Response:
Nebraska Public Power District
Response:
IRC Standards Review
Committee
59
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
Response:
Cleco
No
The inclusion of the text implies additional requirements. Keep quidance to a separate paper.
Response:
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
Consolidated Edison Company of
New York, Inc.
Yes
Duke Energy
Yes
FRCC Manager of Operations
Yes
Manitoba Hydro
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Orange and Rockland Utilities,
Inc.
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
Southen Company
Yes
Tennessee Valley Authority
Yes
60
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
TO/TOP
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
MRO's NERC Standards Review
Subcommittee
Yes
1. We agree. The rationale boxes will cut down on interpretations. 2. Are the rationale boxes part of the
approved standards for which registered entities will be audited. Are the rationale boxes federal law?3. Under
R3, a reference to the National Electric Safety Code in the rationale box would be helpful. (The goal is to
verify that utilities will not be held in violation of this standard when operating beyond the NESC conditions.)
Yes
Additional background in the test boxes is very helpful.
Yes
BGE agrees this would help clarify the basis of the Definitions & Requirements.
Yes
Dominion agrees, but suggests that reference to figure(s) and table(s) contain links that can take reader to
that section of the document. This is superior to having to scroll through document. If the reference(s) is
external to this standard document, links may be harder to manage but should at least reference a common
webpage(s) used by NERC for the posting of such documents.
Yes
However, the boxes should be adding clarity, not "defining' terms or stipulating further requirements/criteria
that must be met. See MVCD in R1 & R2 and the incorporated Table 2, and comments to #1 & #13 in this
form. The standard should be able to convey the requirements without the text boxes or, if the text boxes are
used, the purpose and legal import of such boxes should be clarified. Further, it should be clarififed that for
Response:
North Carolina EMC
Response:
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Response:
Dominion
Response:
Xcel Energy
61
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
text boxes that provide examples (e.g., the boxes on page 2 in the definitions section), such boxes should
clearly state that the examples are in no way limitations.
Response:
Ga Transmission Corp
Yes
I do like the text boxes.
Yes
ITC agrees, but would like to suggest that the text boxes include additional pertinent information from the
Technical Reference that would be helpful as reliability talking points to the public. Example: (R3): The
following is a sample description of one combination of strategies which may be utilized by a Transmission
Owner. A Transmission Owner’s basic maintenance approach could be to remove all incompatible vegetation
from the right of way if it has the right to do so and has no constraints
Yes
It's helpful to understand the SDT's logic for requirements, clarification is always appreciated.
Yes
May help in cutting down the volume of SAR interpretation requests.
Yes
R3 - this may be a good place to describe clearances at time of vegetation management work
Yes
The clarification is important and will reduce the number of requests for interpretation if interpretation is
already provided to some extent. Just a caution about how the text boxes will be used in the audit process,
clarification concerning their use during compliance monitoring would be great.
Response:
ITC Holding
Response:
Ameren
Response:
GCPD
Response:
Central Maine Power, Iberdrola
USA
Response:
Florida Municipal Power Agency
(FMPA) and Some Members
Response:
62
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
Yes
The explanatory information posted with the proposed definitions, like the definitions, is only relevant to this
standard, and some of the information is only relevant to the point where the definition becomes enforceable.
What is the expectation for what will happen to this information in the future? We suggest that the text boxes
associated with requirements include a reference to that requirement. (Change “Rationale” to “Rationale for
R1”)
Yes
The format could be enhanced by moving the "Guidelines and Technical Basis" section forward to be included
with the corresponding Requirement, Measure, and Rationale. Perhaps the "Guidelines and Technical Basis"
could also be combined with the corresponding "Rationale" text box. This would be helpful because it is
awkward flipping back and forth between these two sections when trying to fully understand a requirement.
SERC OC Standards Review
Group
Yes
This format adds clarity and improves readability.
SERC Vegetation Management
Sub-committee
Yes
This format adds clarity and improves readability.
Yes
This format is simpler, easier to read, understand and implement.
Yes
This format provides clarity and improves readability. Progress Energy believes that having SDT basis
information for a requirement in the standard will reduce the need for interpretation and improve the
interpretation process for a requirement, if necessary.
Yes
This improves the clarity and understanding to the requirements.
NERC Staff (12 staff members)
Response:
Western Area Power
Administrtaion
Response:
Response:
East Kentucky Power
Cooperative, Inc.
Response:
Progress Energy Carolinas
Response:
Tampa Electric Company
63
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
Response:
American Electric Power (AEP)
Yes
This is a good change.
Yes
This is extremely helpful in understanding the intent of the requirement
Yes
WAPA - UGPR believes that the expanations within the text boxes provided additional useful information.
Yes
We agree that text boxes being used for additional clarity is a benefit if used in a correct and clear manner. It
needs to be specifically stated in the document that the text boxes are to be used for reference only, entities
will not be required to specifically follow the language in the Rationale box, and that each utility should specify
their own process for addressing each Requirement. For example....the Rationale box for R4 states that
"Verified knowledge includes observations by journeyman lineman, utility arborist, or other qualified
personnel.......". Our process will specify exactly who that qualified personnel is (Transmission Specialist or
another qualified Entergy Employee in the Transmission Vegetation Group, for example). We will specify this
in our internal processes.
Yes
We agree that text boxes can be useful for requirements and definitions. However, the SDT may want to
consider eliminating the text boxes since this information is already provided in the Guidance and Technical
Basis section. Also, we have the following additional comments:General:1. With respect for the rationale text
boxes for definitions, it is not clear if these boxes will be retained once the definitions are moved out of the
standard and added to the NERC Glossary.2. The rationale text boxes can be beneficial for the
requirements, but some of the text boxes in this current draft of FAC-003-2 seem to include prescriptiveness
that is not found in the requirement. An example is in the text box for Req. R4, which implies timeliness of
notification of an imminent threat with the use of the word "rapid". In the case of R4, the requirement should
state that notification be carried out immediately (see our suggested rewording of R4 in Question 13). 3.
Response:
JEA
Response:
Western Area Power
Administration - Upper Great
Plains Region
Response:
Entergy Services
Response:
FirstEnergy
64
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
Although these text boxes are not enforceable for compliance, we are not convinced that an auditor will view
this as simply guidance.Specific:1. Definition for Active Transmission Line ROW - Example 3 of Inactive
ROW - Consider removing this example; situations where vegetation is left unmanaged on portions of the
ROW where double-circuit structures exist with only one circuit strung with conductors poses an unnecessary
increased risk for vegetation related outages. 2. Rationale box for Req. R3 - See our comments in Question
23. Rationale box for Req. R4 should be revised to state: "To ensure rapid notification of the responsible
control center when an occurrence of an imminent threat condition is verified. Evidence of verified knowledge
includes observations by journeyperson, lineperson, utility arborist, or other qualified personnel, or a report
verified by these personnel. This notification allows the responsible control center to take the appropriate
action until the threat is relieved. Appropriate actions may include a temporary reduction in the line loading or
switching the line out of service."4. Rationale box for Req. R5 - (1) The last statement of this box seems
incomplete. It should be revised to state: "This requirement is not intended to address situations where the
transmission line is not at immediate risk and the work event can be rescheduled or re-planned using an
alternate work methodology."; and (2) We suggest revising the first statement to "Legal actions filed by
property owners, easement restrictions and other events...."
Response:
Southern California Edison
Company
Yes
We agree that the insertion of text boxes aids readers in understanding the basis for the Definitions and
Requirements.
Yes
We agree that the side-bars give useful contextual information that is not part of standard. This is good and
avoids the reader’s attention being completely redirected to a reference document when seeking clarification
of the intent of a requirement. We believe however that these text boxes should be used sparingly and the
content should also be brief to minimize possible distractions to the reader.It should also be made clear in the
standard that these text boxes are not intended to impose additional requirements and in the event of any
perceived conflict, the text of the requirement will take precedence.
Yes
We agree, however we would like clarification on whether entities can be held accountable for rationale
portions of the standard as they are for interpretations that are added to a standard.
Response:
Independent Electricity System
Operator
Response:
South Carolina Electric and Gas
Response:
65
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Ad Hoc Group subteam formed to
review draft standard
Yes or No
Question 7 Comment
Yes
We understand this question to refer to the “rationale” text boxes in this standard. Additional information such
as this is useful to the entity in explaining and clarifying the understanding of the drafting team in articulating
the requirement and thus supports a fuller understanding of the entity in achieving compliance with the
requirement.
No
I like information that helps to “guide” and “provide guidance”, however, we already having trouble with
information from FAQ’s, White Papers, and other guiding documents creeping into the requirements by
auditing teams. The inclusion of “guiding information” in the text of the Standard itself may promote adding to
requirements. Although helpful, I recommend removing this text from within the body of the Standard.
Response:
KCPL
Response:
66
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
8. Do you agree with the addition of a Guideline and Technical Basis Section to place technical materials and other
related information that assists entities in understanding how to comply with the standard but does not
contain mandatory actions/activities? Please explain.
Summary Consideration:
Organization
Yes or No
Question 8 Comment
No
Although FMPA agrees that a Guideline and Technical Basis document is important, FMPA has concerns
about how this section might be used in compliance monitoring and enforcement. For instance, R4 has a time
requirement somewhat embedded in the Guideline and Technical Basis that is not in the requirement in the
standard: “The imminent threat process should be implemented in terms of minutes or hours as opposed to a
longer time frame for interim corrective action plans”. How many minutes or hours? This adds ambiguity to the
standard. If a time limit is desired, it should be in the requirement. There are other examples of items that
could be interpreted as requirements in the Guidelines. It should be made clear what the purpose of the
Guidelines is in compliance monitoring and enforcement. FMPA suggests publishing two documents in the
same fashion that the Functional Model has two documents, one for the standards (e.g., the requirements),
and another for technical guidance to the standards (e.g., the Guideline and Technical Basis section) to
parallel the structure of the Functional Model and Functional Model Technical Document, which will help
make the distinction between CMEP and guidance more distinct.
No
ATC disagrees with the above statement that it only assists in understanding how to comply. ATC believes
that parts of this section are written so they could be interpreted to contain mandatory actions/ activities. To
demonstrate, see example on pg.15, R4, 2nd paragraph states...Two key elements of an acceptable
imminent threat procedure are outlined below:..........) It should not be more than a preferred method for
implementation or supporting how the TO can meet the standard. NERC needs to clarify how this section
was intended to be used. (This as written could become part of a Compliance Audit process)Also, refer to
ATC’s comment on this section in Question #3 above.
Westchester County Board of
Legislators
Florida Municipal Power Agency
(FMPA) and Some Members
Response:
American Transmission
Company
Response:
67
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Bonneville Power Administration
Yes or No
Question 8 Comment
No
Consider referencing ANSI A300 part 7 as best management practices for R3. It is currently referenced in the
White Paper, and would lend more credibility to the standard if it was inserted in the text box for R3.
No
For the same reasons stated in the comments to Question 7, it should be expressly stated that this section is
for information purposes only and is not part of the Standard Requirements. Compiling all of the “Information
Only” materials into an Appendix would be the preferred method of organization.
No
NPCC participating members do not believe that publishing more information as part of the standard is
appropriate. For the same reasons as stated in the preceding response related to “Text Boxes” in question 7,
any inconsistency may result in a conflict with a requirement. The information in the Guideline and Technical
Basis section is valuable, however, and should be available to the industry in the form of guidelines. NPCC
participating members suggest that NERC assemble a comprehensive set of “Guideline” documents into one
bookmarked pdf publication to be updated as standards change. This will afford the industry a knowledge
base that is not directly sanctionable for non-compliance, but a set of industry best practices, background,
and reference for the standards development activities. Also, concern exists that FERC and Provincial
governmental authorities will have jurisdiction over “Guidelines”, and when the standard is approved it will
become a mandatory “rule”.
No
Same as item 7.
No
See answer to Q3.
No
Should be separate documents. If located with the standard it will get used by the auditors as compliance
issues. NO matter how much text you provide to the contrary it will become part of the standard over time.
Response:
ERCOT ISO
Response:
Northeast Power Coordinating
Council
Response:
Nebraska Public Power District
Response:
CenterPoint Energy
Response:
GCPD
68
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
Response:
Consolidated Edison Company of
New York, Inc.
No
Since the SDT has developed a complete Technical Reference Document for this Standard, there seems to
be redundancy with the Guideline and Technical Basis Section. This Standard has become too lengthy with
all of the additional details and information that has been added. We prefer to have a shorter Standard and a
more detailed stand alone supporting reference document.
No
Since the SDT has developed a complete Technical Reference Document for this Standard, there seems to
be redundancy with the Guideline and Technical Basis Section. This Standard has become too lengthy with
all of the additional details and information that has been added. We prefer to have a shorter Standard and a
more detailed stand alone supporting reference document.
No
The inclusion of the text implies additional requirements. Keep quidance to a separate paper.
No
This change also requires some additional explanation. What level of importance will be given to such
materials? If an SDT inserted a Best Practices document, does that allow auditors to refer to that document
for purposes of holding an entity non-compliant?
Are these materials there to help entities who do not
know how to comply? If these materials are self-help guides, then it would be better to include them as URL
references that are stored in the NERC library. That way there can be not confusion about whether the
material is there as a self-help guide, or as a reference for auditors.
No
We agree that this is valuable information and important to convey with the standard. This should be a
separate companion document balloted, approved and posted with the standard but not be a part of the
standard.
Response:
Orange and Rockland Utilities,
Inc.
Response:
Cleco
Response:
IRC Standards Review
Committee
Response:
FRCC Manager of Operations
Response:
69
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
TO/TOP
Yes or No
Question 8 Comment
No
We agree that this is valuable information and important to convey with the standard. This should be a
separate companion document balloted, approved and posted with the standard but not as part of the
standard.
No
We recommend that the text “grid reliability” be substituted for “Bulk Electric System” on page 6 of the
draft.The inclusion of non-mandatory guidelines in a standard that will ultimately be approved by FERC gives
undue credence to “guidelines” that will lead undoubtedly to mis-application by future compliance auditors.
We suggest separation of this information from the mandatory reliability standard that will be filed at FERC. It
could be held in a repository on the NERC website.
Response:
SERC OC Standards Review
Group
Response:
Arizona Public Service Company
Yes
Central Maine Power, Iberdrola
USA
Yes
Consumers Energy
Yes
Duke Energy
Yes
Exelon
Yes
Manitoba Hydro
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Pepco Holdings, Inc. - Affiliates
Yes
70
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Tennessee Valley Authority
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Tampa Electric Company
Yes
Aids in improved understanding of FAC-003-2.
Yes
Although we agree that guidelines are good to have and agree that having them in the body of the standards
is convenient, we question how this section will be viewed from a compliance standpoint. We understand this
section is not intended to be mandatory, but does that mean that regulatory authorities will only approve the
other sections of the standard and not this section? Also, it should be clear and explicitly stated in the lead-in
to this section that this is guidance which is not mandatory and enforceable. Additionally, terms such as
"shall", "should", and "require" should not be used in the guidance section because the information presented
in this section could be construed as mandatory by an auditor. An example of this is in the guidance
information for Requirement R7 which states "Documentation is required when the annual work plan is
adjusted...". This mandatory-type language should not be included in the Guidelines section.
Yes
Another good addition to the standard and will help clarify parts of the standard without referring to another
document or set of guidelines.
Yes
Assuming that the "Guideline and Technical Basis Section" will be retained and revised in future revisions to
the standard, such information should prove very useful.
Response:
FirstEnergy
Response:
MRO's NERC Standards Review
Subcommittee
Response:
Southern California Edison
Company
71
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
Response:
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE agrees with the addition of a Guidance & Technical Basis section.
Yes
Having the information in the same document makes the information more accessible to the entity attempting
to comply with the standard.
Yes
I do however believe that each utility should have the flexibility to manage there program the way they feel is
the most effective method. I do not want the technical basis section to limit options. Should this be in a white
paper format?
Yes
I have no preference one way or the other on this issue.
Yes
ITC agrees with Guidelines and Technical Basis section, but recommend including useful Technical
Reference actions and activities that would support defense-in-depth strategy. We also feel that to avoid any
confusion with the applicability section and interpretations in the future, any references to the Bulk Electric
System in the standard sections and guidance/technical reference document should be reviewed and
changed.
Yes
Language should be added to the Guideline and Technical Basis Section to clarify or re-state that this section
is for assisting entities in understanding how to comply with the standard but does not contain mandatory
actions/activities, and a statement that entities are not required to use the information in the Guideline and
Response:
JEA
Response:
Ga Transmission Corp
Response:
East Kentucky Power
Cooperative, Inc.
Response:
ITC Holding
Response:
Entergy Services
72
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
Technical Basis Section.
Response:
Western Area Power
Administrtaion
Yes
The format could be enhanced by moving the "Guidelines and Technical Basis" section forward to be included
with the corresponding Requirement, Measure, and Rationale. Perhaps the "Guidelines and Technical Basis"
could also be combined with the corresponding "Rationale" text box. This would be helpful because it is
awkward flipping back and forth between these two sections when trying to fully understand a requirement.
Yes
There is no language in the body of the standard to clarify that the information in the Guideline and Technical
Basis Section of the standard is not subject to enforcement. We suggest revising the heading to “Application
Guidelines.” This is the term that was originally proposed by the Results-based team and is the heading
identified in the proposed Standard Processes Manual.
Yes
This format adds clarity and improves readability.
Yes
This is all good information to add a depth of understanding for the user. It's not clear as to how modifications
to the Guideline and Technical Basis would come about - it is the same as the standards revision process?
Does this section replace the white paper? Will it actually be deemed to be part of the Standard? We are
curious as to the legal weight if this is not part of the Standard and believe that key provisions are in this
section. It seems it should be part of the Standard.
Yes
This is helpful information to have that does not clutter up the requirements and measurements. Under R6,
the third paragraph, there is a typo: ..."230kv transmission lines at least once 'line' during the calendar year".
Response:
NERC Staff (12 staff members)
Response:
SERC Vegetation Management
Sub-committee
Response:
Xcel Energy
Response:
Ameren
Response:
73
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
City of Tallahassee (TAL)
Yes or No
Question 8 Comment
Yes
This is very useful information and will minimize misinterpretations by the entities and the compliance teams.
Yes
This new section provides additional information and SDT rationale that is critical to understanding how to
comply with the requirements in the standard and will also provide SDT intent/basis for the interpretation
process when necessary. Progress Energy believes that any references to the Bulk Electric System in the
standard sections and guidance/technical reference document should be reviewed and changed (e.g. “grid
reliability”) to avoid confusion with the applicability section in this draft and avoid the potential for applicability
interpretations once this version is adopted.
Yes
This section should be placed in an appendix preceded by a statement that clearly states the purpose of the
Section and indicates that the Guideline and Technical Basis Section does not in any way add to the
requirements of the standard. Also, this section appears to be a summary of the Technical Reference
Document but we could find no reference to the Technical Reference within the standard. This reference
should be cited for the benefit of anyone seeking further detail.
Yes
WAPA - UGPR agrees with the concept of placing the background technical information in a separate section.
We were a bit concerned with the Guideline for R7 because it seems to mandate many more items than were
called for in the actual requirement in the body of the standard. Our belief is that the Guideline section should
not infer or list any more requirements than the actual requirement dictates.
Yes
We agree with the additional material as an aide to entities to further understand the basis for the
requirements. In this spirit the information should support compliant behavior and thus the reliability
objectives of the standard.
Yes
While we agree that these can be useful, we are concerned about the ‘last minute’ change (March 24th) to the
Response:
Progress Energy Carolinas
Response:
Independent Electricity System
Operator
Response:
Western Area Power
Administration - Upper Great
Plains Region
Response:
Ad Hoc Group subteam formed to
review draft standard
Response:
Dominion
74
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
technical reference document being used by those reviewing the materials for this project.
Response:
Southen Company
Yes
Would it be better to have an official white paper associated with the standard rather than having this
information in the standard? A white paper can be changed without seeking industry comments and approval
from NERC, while information in the standard must go through the entire approval process. As it is
structured now, information-only updates to the Technical Basis Section would require the entire standards
approval process to be completed.
Yes
Yes, although American Electric Power does question whether auditors will be able to avoid reading and
applying such text.
No
I like information that helps to “guide” and “provide guidance”, however, we already having trouble with
information from FAQ’s, White Papers, and other guiding documents creeping into the requirements by
auditing teams. The inclusion of “guiding information” in the text of the Standard itself may promote adding to
requirements. Although helpful, I recommend removing this text from within the body of the Standard.
Response:
American Electric Power (AEP)
Response:
KCPL
Response:
75
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
9. Do you prefer putting URL links to reference materials in the Guideline and Technical Basis Section, or do you
prefer putting the additional technical/information materials in appendices, where needed, to supplement the
Guideline and Technical Basis Sections? Please explain.
Summary Consideration:
Organization
Yes or No
Question 9 Comment
Central Maine Power,
Iberdrola USA
Westchester County Board of
Legislators
MRO's NERC Standards
Review Subcommittee
If there is background information contained in a URL link pertaining to a particular Requirement, that
link should be with the Requirement that it pertains to.
Response:
Ad Hoc Group subteam
formed to review draft
standard
Judicious and correct use of citations should allow the proper documentation of references without the
hazard of expired URLs or expansion from using appendices.
Response:
Tennessee Valley Authority
No preference, either way will work.
Response:
Consumers Energy
Prefer appendices
Exelon
Prefer appendices
PPL Electric Utilities
Corporation (NCR00884)
Prefer appendices
76
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 9 Comment
South Carolina Electric and
Gas
Prefer appendices
TO/TOP
Prefer appendices
Tucson Electric Power Co.
Prefer appendices
Western Area Power
Administrtaion
Prefer appendices
Xcel Energy
Prefer appendices
GCPD
Prefer appendices
Actually we prefer that they are separate from the standard entirely. See question 8.
Prefer appendices
An appendix ensures the information is available and original at the time the document it supports was
prepared.
Prefer appendices
An Appendix would probably be easier to use, but either type of reference would suffice. Regardless of
which is used, it should include a footnote that the information is “For Information Purposes Only” and
are not a part of the Standard’s Requirements. If the information causes confusion, then it should be
eliminated completely. Also, what types of materials are contemplated to be “reference materials”?
Prefer appendices
Appendices would memorialize documents vs URL links to reference materials that may change over
time. This Standard was crafted from “todays” point of view and background information. Reference
material might change and the URL would point to material not validating the current form, logic, and
background of the Standard.
Response:
Cleco
Response:
ERCOT ISO
Response:
Oncor Electric Delivery
Response:
77
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Entergy Services
Yes or No
Question 9 Comment
Prefer appendices
Appendices, or reference to a single site for all referenced material, would be the most helpful from the
standpoint of keeping the information together and more readily available.
Prefer appendices
BGE prefers that such materials be included in the appendices.
Prefer appendices
It is not clear what part of the standard is being balloted and what part is not. In addition, it is not clear
what process will be used to modify the guideline/technical basis section of the standard. This needs to
be determined before this standard can be balloted.
Prefer appendices
Links can get broken - official records (ie. standards) need to stand alone.
Prefer appendices
The fewer places I have to navigate to the better I like it. I find too many “broken” URLs. This will also
make it easier when I download a “complete set” of standards from the NERC website.
Prefer appendices
Unless a ‘failsafe’ process is developed to insure URL links are keep up-to-date, preference is to locate
all referenced materials within the standard (same URL). However, there are a number of ways that
URL linkage could be done. One would be to locate all Guideline and Technical Basis documents on a
webpage dedicated to such documents. This would allow URL linkage at a higher level than if there is
URL linkage for each Guideline or Technical Basis document. This is probably the easiest to maintain.
Another would be to link each Guideline or Technical Basis document referenced in a standard to the
same URL as that standard. Maintaining URL linkage is probably medium. Yet another is to have the
URL link to a webpage created specifically for that Guideline or Technical Basis document. This is likely
Response:
BGE (on behalf of
parent/affiliate companies:
CEG, CPSG, CECG, CNE &
CENG)
Response:
NERC Staff (12 staff
members)
Response:
FRCC Manager of Operations
Response:
City of Tallahassee (TAL)
Response:
Dominion
78
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 9 Comment
to be the hardest (require most effort) to maintain.
Response:
CenterPoint Energy
Prefer appendices
URL links tend to change over time due to administrative requirements. Moving them to the appendix
will avoid revisions to the Standard. See also answer to Q3 regarding the Guideline and Technical
Basis Section.
Prefer appendices
URLs can break
Prefer appendices
URLs change periodically.
Prefer appendices
Will need to put something in place to make sure that the links get properly updated if they change.
Response:
Florida Municipal Power
Agency (FMPA) and Some
Members
Response:
Nebraska Public Power District
Response:
North Carolina EMC
Response:
Ameren
Prefer the inclusion
of URL links
Arizona Public Service
Company
Prefer the inclusion
of URL links
Bonneville Power
Administration
Prefer the inclusion
of URL links
Consolidated Edison Company
of New York, Inc.
Prefer the inclusion
of URL links
79
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 9 Comment
Duke Energy
Prefer the inclusion
of URL links
Ga Transmission Corp
Prefer the inclusion
of URL links
IRC Standards Review
Committee
Prefer the inclusion
of URL links
Manitoba Hydro
Prefer the inclusion
of URL links
Omaha Public Power District
Prefer the inclusion
of URL links
Pepco Holdings, Inc. Affiliates
Prefer the inclusion
of URL links
Southern California Edison
Company
Prefer the inclusion
of URL links
Utility Risk Management
Corporation
Prefer the inclusion
of URL links
Progress Energy Carolinas
Prefer the inclusion
of URL links
Additional reference documents provide additional information that may be needed to understand how
to comply and the basis of requirements, but they should not be included as appendices. The use
appendices could result in a SDT process/effort for minor revisions to the reference document.
Prefer the inclusion
of URL links
Also see ATC’s comment on “Guideline and Technical Basis Section” in Question #3 above.
Response:
American Transmission
Company
Response:
80
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Independent Electricity System
Operator
Yes or No
Question 9 Comment
Prefer the inclusion
of URL links
In general the additional reference materials may make the document extremely voluminous so we
prefer URL links.
Prefer the inclusion
of URL links
Links are preferable to alleviate the concerns expressed in question 8 above, especially with respect to
FERC approval.
JEA
Prefer the inclusion
of URL links
No strong preference.
Tampa Electric Company
Prefer the inclusion
of URL links
None
Western Area Power
Administration - Upper Great
Plains Region
Prefer the inclusion
of URL links
None
Orange and Rockland Utilities,
Inc.
Prefer the inclusion
of URL links
Prefer the inclusion of URL links
Prefer the inclusion
of URL links
Provides for clarity and readability.
Prefer the inclusion
of URL links
See answer to number 8.
Response:
Northeast Power Coordinating
Council
Response:
Response:
East Kentucky Power
Cooperative, Inc.
Response:
Southen Company
Response:
81
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
American Electric Power
(AEP)
Yes or No
Question 9 Comment
Prefer the inclusion
of URL links
The use of URL links is probably most appropriate for an increasingly web-based reference repository.
Prefer the inclusion
of URL links
This format adds clarity and improves readability.
Prefer the inclusion
of URL links
This format adds clarity and improves readability.
Prefer the inclusion
of URL links
URL links provide immediate access, are less cumbersome, and usually provide additional research
material when accessed.
Prefer the inclusion
of URL links
We prefer URL links. Although, we are not clear what this question is asking regarding "additional
technical/information materials". Is the team referring to "supplemental" reference documents such as
the technical reference white paper that was recently posted for stakeholder review on March 24,
2010? If so, we agree that supplemental reference material be included through URL links, perhaps at
the end of the "Guidelines and Technical Basis" section of the standard.
Prefer appendices
Although a good idea generally, too many times URL links change name or something else that makes
the imbedded link unusable or takes you to the wrong place. Having an appendix ensures the
information is available and original at the time the document it supports was prepared.
Response:
SERC OC Standards Review
Group
Response:
SERC Vegetation
Management Sub-committee
Response:
ITC Holding
Response:
FirstEnergy
Response:
KCPL
Response:
82
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
10.
Do you agree with the addition of the Background Section to allow provision of background information, and
to elaborate on the reliability-related drivers for the standard/change? Please explain.
Summary Consideration:
Organization
Yes or No
Question 10 Comment
Westchester County Board of
Legislators
ERCOT ISO
No
Again, it is preferable to include this type of information in an Appendix as long as it is made clear that this is
additional information and is not a part of the Standard’s Requirements. However, if there is a chance that
the additional information included in the Appendix is going to cloud the Requirements spelled out in the
Standard, then our preference is to eliminate the additional information completely.
No
Inclusion of a background section in a document that will be approved wholly by FERC give undue credence
and weight to statements which may be included that are not necessarily factual 100% of the time. For
example, the first sentence of the last paragraph of the background section reads as follows: “Since
vegetation growth is constant and always present, unmanaged vegetation poses an increased outage risk,
especially when numerous transmission lines are operating at or near their Rating.” Obviously, woody stems
do not grow during the dormant season, yet the background asserts that it does. There are other areas in this
sentence that are not completely factual and should not be in a reliability standard. We recommend that the
text “grid reliability” be substituted for “Bulk Electric System” on page 6 of the draft.
No
Not necessary.
No
NPCC participating members believe this is more informational and appropriate on the individual standard’s
NERC Website “Under Development” page, in an announcement, cover letter, or to be distributed with the
standard drafts.
Response:
SERC OC Standards Review
Group
Response:
Consumers Energy
Response:
Northeast Power Coordinating
Council
83
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
Response:
Nebraska Public Power District
No
Same as item 7.
No
See answer to Q3.
No
The background belongs in the Guidelines and not as part of the standard.
No
The background section should be re-named "Technical Basis". Trim content and leave only the first and last
paragraphs. In addition, all 5 paragraphs of the section as written should be moved to the front of the
Guidelines and Technical Basis document as a "Background" section of that separate document. NERC
should limit its use of "background" information within the reliability standard itself.
No
The background section should be re-named "Technical Basis". Trim content and leave only the first and last
paragraphs. In addition, all 5 paragraphs of the section as written should be moved to the front of the
Guidelines and Technical Basis document as a "Background" section. NERC should limit its use of
"background" information in reliability standards.
No
The inclusion of the text implies additional requirements. Keep quidance to a separate paper.
No
This information should be in appendices or reference documents available on the NERC standards site.
Response:
CenterPoint Energy
Response:
Florida Municipal Power Agency
(FMPA) and Some Members
Response:
FRCC Manager of Operations
Response:
TO/TOP
Response:
Cleco
Response:
Exelon
84
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
Response:
Ameren
Yes
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
Central Maine Power, Iberdrola
USA
Yes
City of Tallahassee (TAL)
Yes
Duke Energy
Yes
East Kentucky Power
Cooperative, Inc.
Yes
Ga Transmission Corp
Yes
JEA
Yes
Manitoba Hydro
Yes
MRO's NERC Standards Review
Subcommittee
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Pepco Holdings, Inc. - Affiliates
Yes
85
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southen Company
Yes
Tennessee Valley Authority
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Western Area Power
Administrtaion
Yes
SERC Vegetation Management
Sub-committee
Yes
Allows for a more informed interpretation of the standard.
Yes
American Electric Power agrees with this change.
Yes
ATC agrees that the Background Section is helpful; however, NERC should define its purpose and goal.
What is currently written is more than necessary to be included in this standard.
Yes
Dominion agrees but suggests it be moved towards end (suggest between Administrative and
Guideline/Technical basis sections).
Response:
American Electric Power (AEP)
Response:
American Transmission
Company
Response:
Dominion
86
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
Response:
Ad Hoc Group subteam formed to
review draft standard
Yes
Great help in showing intent and reliability goal of the standard.
Yes
Including a background section should prove useful for future editions. However, at some point such
information could be made accessible through URL links.
Yes
ITC agrees with the addition of Background Section
Yes
May help in iterpretations and in explaining to stakeholders in our organizations.
Tampa Electric Company
Yes
None
Western Area Power
Administration - Upper Great
Plains Region
Yes
None
Progress Energy Carolinas
Yes
Progress Energy agrees and believes that the background section will allow relevant background information
that provided direction/guidance for the SDT to be readily available after the standard revision is adopted.
Yes
The Background Section is helpful, but the last sentence states....."Thus, this Standard's emphasis is on
vegetation grow-ins.". This statement seems to conflict with the outage Category 2 "Fall In" classification,
even though it is a fall in from within the ROW.
Response:
Southern California Edison
Company
Response:
ITC Holding
Response:
GCPD
Response:
Response:
Entergy Services
87
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
Response:
Xcel Energy
Yes
The Background section should be moved to the back, in front of the Guideline and Technical Basis.
Yes
This background is important for insertion at the beginning of a SAR. But for a standard-posting, it is
suggested that this section is redundant and better inserted after the requirement and measures with the
other Administrative materials.
Yes
This makes sense to BGE.
Yes
This provides a context for the requirements and is very beneficial in understanding the intent of the standard.
Yes
This section expands on the purpose statement and will promote a uniform understanding of the fundamental
drivers for the standard and its requirements, as well as its philosophy and scope.
Yes
We agree but believe the Background Section should be situated before the Applicability Section in the
revised Standard and redundant verbiage should be removed.
Yes
We agree but believe the Background Section should be situated before the Applicability Section in the
revised Standard and redundant verbiage should be removed.
Response:
IRC Standards Review
Committee
Response:
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Response:
NERC Staff (12 staff members)
Response:
Independent Electricity System
Operator
Response:
Consolidated Edison Company of
New York, Inc.
Response:
Orange and Rockland Utilities,
Inc.
88
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
Response:
FirstEnergy
Yes
We agree that a Background section is beneficial. However, we believe it may be more appropriate to move
this information to the Guidelines section as a lead-in. Also, we suggest a rewording of the first sentence of
the first paragraph on Pg. 2 which states: "Major outages and operational problems have resulted from
interference between overgrown vegetation and transmission lines located on many types of lands and
ownership situations". We agree that vegetation can contribute to outages, but it cannot be the sole cause of
major outages. Major outages can be prevented if other measures required by other NERC standards are
implemented when vegetation causes a line or other equipment to malfunction. We suggest a rewording of
this statement as follows: "Interference between vegetation and transmission lines located on many types of
land have contributed to significant outages and operational challenges."
No
I like information that helps to “guide” and “provide guidance”, however, we already having trouble with
information from FAQ’s, White Papers, and other guiding documents creeping into the requirements by
auditing teams. The inclusion of “guiding information” in the text of the Standard itself may promote adding to
requirements. Although helpful, I recommend removing this text from within the body of the Standard.
Response:
KCPL
Response:
89
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
11.
Do you agree with the addition of an Administrative Procedure Section to place administrative/procedural
requirements that are contained in the existing standards but which do not meet the results-based or riskbased criteria? Please explain.
Summary Consideration:
Organization
Yes or No
Question 11 Comment
ERCOT ISO
North Carolina EMC
Westchester County Board of
Legislators
Consumers Energy
No
Nebraska Public Power District
No
Administrative requirements should not be included in the Standard, they may be construed unintentionally as
a requirement.
No
Anything not directly associated with the compliance requirements or for help with interpretations should not
be in the standard.
No
As stated earlier, NPCC participating members don’t understand if this section holds sanctionable
requirements, and if so under what authority. Administrative items are best left to the ROP or Compliance
documents. A results based standard’s primary focus should be on the requirements, and the goal or
reliability objective. Taking administrative requirements out of the formal requirements section, adding them
to another section, and still deeming them to be requirements is of no value to reducing the administrative
burden on the industry. This makes the implementation of the standard more burdensome due to the fact that
these additional “requirements” now reside in different places in the standard document. NPCC participating
members suggest if these are truly valid requirements they need to be together with the other requirements.
If they do not meet the results based criteria, and were included in this “Administrative Procedure” section
Response:
GCPD
Response:
Northeast Power Coordinating
Council
90
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 11 Comment
strictly because of that, then they need to reside in another document. Their continued appearance in the
document dilutes the integrity of the results based standard initiative.
Response:
Exelon
No
Exelon is concerned this will raise questions concerning what criterion separates an administrative
requirement from a results or risk based requirement. How are administrative requirements to be treated in
the CMEP?
No
It is not clear if the Administrative Procedure is a mandatory activity. It would be helpful if the intent of this
section was stated within the Standard.Also, this section in not parallel with the Rating and Rated Electrical
Operating Conditions exception contained in R1 and R2. We recommend the following parallel wording for
the first paragraph of this section:”The Transmission Owner will submit a quarterly report to its Regional
Entity, or the Regional Entity’s designee, identifying certain Sustained Outages of the categories defined
below, while operating within the Rating and Rated Electrical Operating Conditions, determined by the
Transmission Owner to have been caused by vegetation that includes, as a minimum, the following:”Also, the
categories listed in this section do not have parallel language to M1 and M2. We recommend that this section
should adopt the wording in M1 and M2 for the Sustained Outages to be reported. Currently, Category 2 and
Category 4 do not distinguish between an IROL and Major WECC Transfer Path. This may become a
tracking problem since they have different Violation Risk Factors. If this is not important, then Category 1A
and 1B can be combined.
Consolidated Edison Company of
New York, Inc.
No
It is somewhat confusing to have sanctionable requirements located in other sections of the Standard outside
of 'Requirements and Measures.' The section title 'Administrative Procedure' is somewhat misleading; if it was
renamed 'Administrative Requirements' we feel it would be clearer to the industry.
Orange and Rockland Utilities,
Inc.
No
It is somewhat confusing to have sanctionable requirements located in other sections of the Standard outside
of 'Requirements and Measures.' The section title 'Administrative Procedure' is somewhat misleading; if it was
renamed 'Administrative Requirements' we feel it would be clearer to the industry.
Response:
CenterPoint Energy
Response:
Response:
91
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
SERC OC Standards Review
Group
Yes or No
Question 11 Comment
No
Reporting Outages is not a part of Vegetation Mgmt. Therefore, this reporting belongs in an Administrative
Section or possibly via a NERC 1600 request. In no circumstance should it be a Requirement of the standard.
In the last paragraph this section appears to place a requirement on a regional reliability entity: “The Regional
Entity will report the outage information provided by Transmission Owners, as per the above, quarterly to
NERC, as well as any actions taken by the Regional Entity as a result of any of the reported Sustained
Outages.” Was this really intended? What if the RE fails to make a report?
No
Some additional explanation is needed.
If the requirement is to do inspections, and compliance is
measured on that basis only then the Administrative Section is OK.
If the entity is mandated to also meet
the actions specified in the Administrative Section, then the change is not acceptable. This standard's
example administrative section is introducing new requirements into the standard, and those requirements
should be in the standard. In short, if there is a reliability requirement than that is what should be mandated.
The idea of mandating administrative items that are often designed to make auditing (not operations or
planning) simpler should not be mandated.
No
The "Administrative" section needs to be streamlined - remove the first 2 paragraphs - quarterly reporting is
no longer required and would be an administratively redundant process to the self-reporting of outages.
Leave the outage categories to support consistent self-reports. Delete last paragraph - reporting by the
Regional Entities to NERC is a delegated function that should be governed by the delegation agreements,
rules of procedure or other internal ERO process, not within a reliability standard since REs and the EROs are
not users, operators, etc of the BPS.
No
The "Administrative" section needs to be streamlined - remove the first 2 paragraphs - quarterly reporting is
no longer required and would be an administratively redundant process to the self-reporting of outages.
Leave the outage categories to support consistent self-reports. Delete last paragraph - reporting by the
Regional Entities to NERC is a delegated function that should be governed by the delgation agreements,
rules of procedure or other internal ERO process, not a reliability standard.
Response:
IRC Standards Review
Committee
Response:
FRCC Manager of Operations
Response:
TO/TOP
Response:
92
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Ad Hoc Group subteam formed to
review draft standard
Yes or No
Question 11 Comment
No
The administrative procedure section is appropriate under results-based requirements. However, we believe
that reporting requirements established under other methods, such as the CMEP, may be confused by
including it. It is unclear how non-conformance with administrative procedures would be handled. Perhaps
administrative procedures would be better handled under ROP Section 1600 data requests or other Rules.
No
The inclusion of the text implies additional requirements. Keep quidance to a separate paper.
No
The reporting requirements really boil down to a self-reporting or self-certification process since the only items
to report would be violations to the standard. If such quarterly reporting is desired, it is really a selfcertification process and should be governed by that process and not through a separate Administrative
Procedure.FMPA recommends deleting the last paragraph - reporting by the Regional Entities to NERC is a
delegated function that should be governed by the delegation agreements, rules of procedure or other internal
ERO process, not within a reliability standard since REs and the EROs are not users, operators, etc of the
BPS, and are not designated in the Applicability section.
Response:
Cleco
Response:
Florida Municipal Power Agency
(FMPA) and Some Members
Response:
Ameren
Yes
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
Central Maine Power, Iberdrola
USA
Yes
City of Tallahassee (TAL)
Yes
Dominion
Yes
Entergy Services
Yes
93
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Ga Transmission Corp
Yes
Manitoba Hydro
Yes
MRO's NERC Standards Review
Subcommittee
Yes
NERC Staff (12 staff members)
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southen Company
Yes
Southern California Edison
Company
Yes
Tennessee Valley Authority
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Xcel Energy
Yes
Question 11 Comment
Are we to understand that the requirements listed in the Administrative section are not sanctionable from a
NERC compliance perspective?
94
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 11 Comment
Yes
ATC feels this adds good will on the part of the entity to submit necessary reports, however, ATC requests
clarification whether this section is subject to NERC violations. (Currently not listed in Table 1 Time Horizons,
VRFs and VSLs)
Yes
BGE agrees with addition of an Administrative Procedure section.
Yes
During the WEBINAR, a question was raised regarding how failure to meet an Administrative/Procedural
requirement would be addressed by the Regional Entity. Can the Standard Drafting Team prepare a response
to the question?
Yes
However, it needs to be made clear whether this is subject to audit, and whether failure to meet the
requirement is subject to the same or different enforcement procedures as the numbered requirements in the
standard.
Yes
I do not believe that reporting of outages is a part of development and implementation of a Vegetation
Management Plan. I fail to see how it brings value to the standard.
Yes
ITC agrees that the “administrative role” such as outage reporting; shouldn’t be a reliability requirement and
are more appropriately defined as an administrative procedure. We would also like some clarification on
whether this section of the standard is subject to NERC violations. Currently it’s not listed in Table 1 Time
Horizons, VRFs and VSLs
Response:
American Transmission
Company
Response:
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Response:
Duke Energy
Response:
JEA
Response:
East Kentucky Power
Cooperative, Inc.
Response:
ITC Holding
95
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 11 Comment
Response:
Western Area Power
Administration - Upper Great
Plains Region
Yes
None
Tampa Electric Company
Yes
Not sure why separating 1.A & 1.B is preferred over 1,2,3,4?
Yes
Progress Energy agrees that “Administrative” functions such as outage reporting should not be listed as a
reliability requirement and are more appropriately defined as an administrative procedure. (Outage reporting
is an administrative function that does not directly improve reliability which should be the focus of reliability
standard requirements.)NERC has other formal information request procedures in place (such as a NERC
1600 request), if that becomes necessary to ensure outage reporting.
Yes
Reporting Outages is not a part of Vegetation Mgmt. Therefore, this reporting belongs in an Administrative
Section or possibly via a NERC 1600 request. In no circumstance should it be a Requirement of the standard.
Yes
The Administrative Procedure section could be moved forward following the Background section to better
introduce the general administrative overview for what would then become the following Requirements,
Measures, etc. These general administrative and procedural requirements are more easily overlooked when
they included at the back of the Standard.
Yes
This addition is acceptable
Yes
This section imposes an additional reporting requirement but there is no associated VRF or VSL. Is this
Response:
Progress Energy Carolinas
Response:
SERC Vegetation Management
Sub-committee
Response:
Western Area Power
Administrtaion
Response:
American Electric Power (AEP)
Response:
Independent Electricity System
96
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Operator
Question 11 Comment
intentional? How will failure to report on time be treated? This is unclear as is the significance of any such
Administrative “Requirements” within the standard, in general. Is the intention to establish separate
procedures to govern the administrative and reporting obligations of registered entities under the Rules of
Procedure?
Response:
FirstEnergy
Yes
We agree with the Administrative Procedure Section. Monetary fines should not be imposed for
noncompliance with administrative requirements.
No
It is too easy to unintentionally infer or introduce something that is not intended to be a requirement, but gets
interpreted as a requirement in this section. Standards should be clear in what is a requirement and what is
helpful information. If these are requirements, then propose them as requirements. If not, then remove to
another guiding document.
Response:
KCPL
Response:
97
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
12.
Is there any other information that should be included in the standard document? If so, please explain why
you feel that this information should be included.
Summary Consideration:
Organization
Yes or No
Question 12 Comment
ERCOT ISO
FRCC Manager of Operations
North Carolina EMC
TO/TOP
Westchester County Board of
Legislators
Ad Hoc Group subteam formed to
review draft standard
No
American Transmission
Company
No
Bonneville Power Administration
No
City of Tallahassee (TAL)
No
Cleco
No
Consolidated Edison Company of
New York, Inc.
No
Consumers Energy
No
98
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Dominion
No
Duke Energy
No
East Kentucky Power
Cooperative, Inc.
No
Exelon
No
Florida Municipal Power Agency
(FMPA) and Some Members
No
Ga Transmission Corp
No
Independent Electricity System
Operator
No
ITC Holding
No
JEA
No
Manitoba Hydro
No
Nebraska Public Power District
No
NERC Staff (12 staff members)
No
Northeast Power Coordinating
Council
No
Oncor Electric Delivery
No
Orange and Rockland Utilities,
Inc.
No
Question 12 Comment
99
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 12 Comment
Pepco Holdings, Inc. - Affiliates
No
PPL Electric Utilities Corporation
(NCR00884)
No
South Carolina Electric and Gas
No
Southern California Edison
Company
No
Tennessee Valley Authority
No
Tucson Electric Power Co.
No
Utility Risk Management
Corporation
No
Western Area Power
Administrtaion
No
Tampa Electric Company
No
All areas have been addressed and clarified as needed.
No
BGE feels no other information is necessary for inclusion.
American Electric Power (AEP)
No
None
Western Area Power
Administration - Upper Great
No
None
Response:
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Response:
100
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 12 Comment
Plains Region
GCPD
No
Too much already.
Response:
Omaha Public Power District
Yes
SERC OC Standards Review
Group
Yes
As suggested in comment six, an improvement would be also listing the applicable table rows with each
requirement which consolidates all pertinent info with the requirement. Also, adding the penalty matrix would
facilitate discussions with property owners/agencies resisting maintenance activates. This standard indicates
a lack of recognition that vegetation outages are not necessarily reliability events. In the quest for improved
reliability, spending the money necessary to achieve perfect compliance with R2, as stated, either will
increase customer rates unnecessarily or cause the misallocation of maintenance funding away from
maintenance activities that have a substantially higher impact on reliability.
Yes
As suggested in comment six, an improvement would be also listing the applicable table rows with each
requirement which consolidates all pertinent info with the requirement. Also, adding the penalty matrix would
facilitate discussions with property owners/agencies resisting maintenance activates.
Yes
Clearance 1 needs to be put back into this requirement as written. This is a vegetation management standard
and there needs to be clear direction on how the system is going to be maintain at the time of maintenance.
This ensures a clear direction to the utility the system has to be maintained. ANSI A-300 part 1 and 7 needs
to be a requirement within the standard. Following this consensus agreement within the Professional Utility
Vegetation Management sector outlines a process for providing a reliable transmission system. At a
minimum ANSI A-300 part 1 and 7 should be incorporated into the Guideline and Technical Basis Section as
a resource for compliance with this standard. Prudence would dictate that it be adopted into this draft as the
foundation of any transmission vegetation management program as it is the accepted standard for
professionals who are responsible for managing vegetation for electric utilities.Personnel qualifications need
to be included in the standard and should include minimum measures such that there is consistency across
the industry. This ensures that personnel are qualified and will have ongoing training and education in utility
vegetation management. For example: The person who manages the field operation should have at least 5
Response:
SERC Vegetation Management
Sub-committee
Response:
Arizona Public Service Company
101
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 12 Comment
years experience in vegetation management be an International Society of Arboriculture Certified Arborist and
a Utility Specialist.
Response:
Ameren
Yes
In 4.3.1, suggest that "ice" be included in circumstances beyond the reasonable control of a TO in addition to
the other "acts of God".
Yes
More clarifying language throughout the document would be helpful.
Yes
None, other than the comment about potential improvements in question #6.
Yes
Regarding the new format, the idea of using “Informal Comment Periods” may be useful in speeding up the
process of developing standards, but it also introduces a potential for a given Team to ignore valuable
comments (either because the issue is unknown to them, or because the issue does not agree with their
ideas).
How will the Standards Committee or others ensure the quality of the process does not suffer in
this way? What type of review process is contemplated to detect such behavior?
Having the Formal
comments at the end of the process may prevent subject matter experts (SME) from seeing the comments
and perspectives of other SMEs. The SRC suggests that all comments (both formal and informal) be posted
immediately for all to review.
Yes
See comments to #1, #7 and #13 of this form
Yes
See our other comments.
Response:
Entergy Services
Response:
Progress Energy Carolinas
Response:
IRC Standards Review
Committee
Response:
Xcel Energy
Response:
FirstEnergy
102
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 12 Comment
Response:
Central Maine Power, Iberdrola
USA
Yes
Table 2 expand footnote - State that table 2 is intended as a buiding block to develop clearance at time of
vegetation management work. See TVMP for clearances.
Yes
The detailed rationale for the required one year inspection cycle in R6 should be included in the Technical
Reference. The explanation provided in the Rationale that it “seems to be reasonable” and in the Technical
Reference that it is “reasonable based on upon average growth rates across North America and common
utility practice” are unfounded and arbitrary without a specific reference to a North American study. The
Technical Reference should contain an example diagram of “the portion of the ROW where the corridor edge
zones are designated by regulatory bodies for vegetation to exist” taken from the examples in the Definition of
Terms Used in Standard section. It is unclear how this example should be interpreted for compliance should
a Sustained Outage occur from vegetation growing within this zone. It is common for regulatory bodies to
push utilities to plant trees or maintain trees within transmission rights of way to “hide the lines”, and it is
unclear if this example is attempting to encourage such practice by regulatory bodies at the sacrifice of
reliability.In general, the Technical Reference should contain more specific examples of violations of the
Requirements and highlight specific exceptions related to vegetation related outages.The background and
basis for adding the term “Active Transmission Line Right-of-Way” should be added to the Technical
Reference.The background and basis for 4.2.4 that excludes the Standard from applying to fenced
substations should be added to the Technical Reference.Just as the force majeure statement (4.3.1) was
moved to the Applicability section of the Standard, the exception for applicability beyond the Rating and Rated
Electrical Operating Conditions should be included in the Applicability section as well. Currently, it is only
included in R1 and R2. It should be made clear if the other Requirements and Measurements must consider
conditions beyond the Rating and Rated Electrical Operating Condition.Within the Requirements and
Measures section there should be subheadings for each type of Requirement, performance-based, risk
based, and competency-based. This classification is only indicated in the Technical Reference.
Yes
The NSRS believes a section for definitions and abbreviated terms such as, Active ROW, MVCD, and WECC
is needed. Also, See comment above in Question 9 on URL links.
Response:
CenterPoint Energy
Response:
MRO's NERC Standards Review
Subcommittee
Response:
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Southen Company
Yes or No
Yes
Question 12 Comment
We feel a definition of Category 3 outages (non reportable outages) should be included under the
administrative procedures. Although these outages are not reportable, this would provide a mechanism for
classifying these outages so the utility can maintain evidence of its investigation and the rationale for not
reporting them.
Response:
KCPL
No
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
13.
Do you have any other comment regarding the draft FAC-003-2 Transmission Vegetation Management
standard that have not been addressed above? If yes, please provide a reference to the section, requirement,
or subrequirement that you believe should be changed, added or deleted and the rationale for your proposal.
Summary Consideration:
Organization
Yes or No
Question 13 Comment
Entergy Services
ERCOT ISO
TO/TOP
American Electric Power
(AEP)
American Electric Power suggests replacing the term "Minimum Vegetation Clearance Distance" with "Critical
Vegetation Clearance Distance." The use of "minimum" suggests that the minimum is acceptable. However, in
dealing with landowners or land managers, we may not be able to negotiate any more than the minimum. "Critical"
would help convey the sense that the distance borders on dangerous unacceptability.
Response:
Central Maine Power,
Iberdrola USA
No
Consumers Energy
No
East Kentucky Power
Cooperative, Inc.
No
IRC Standards Review
Committee
No
Manitoba Hydro
No
Pepco Holdings, Inc. -
No
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
Affiliates
PPL Electric Utilities
Corporation (NCR00884)
No
South Carolina Electric
and Gas
No
Southern California
Edison Company
No
Tennessee Valley
Authority
No
Tucson Electric Power
Co.
No
Tampa Electric Company
No
None
FRCC Manager of
Operations
Yes
- Applicability Section 4.3 - use the term "Exemptions" instead of "Other" as it is more descriptive.- As noted earlier Applicability Section 5 - use the term "Technical Basis" instead of "Background" and streamline by removing
paragraphs 2, 3 and 4.- R
Yes
(a) R1 and R2 (pg.7) - What is meant by “to avoid a Sustained Outage”. Could be argued that a grow-in that does not
cause a Sustained Outage is acceptable. (Could this be a FERC issue?)(b) R5 (pg.9) - ATC believes the term
“temporarily” should be stricken from the requirement. This leaves too much to interpretation and does not add to the
requirement(c) R6 (pg.9) - The descriptive timeframe “at least once per calendar year” is used. What does this mean?
Every 365 days or a 12 month period within a calendar year? NERC needs to define this.(d) R4 (pg.15 in the
Guideline and Technical Basis) - The term “verified knowledge” is used which does not seem consistent with the
definition of “Verified Knowledge” in R4 Rationale on pg.8.(e) R4 (pg.16 in the Guideline and Technical Basis) - The
term “responsible control center” is used and further defined. ATC believes this is the Transmission Operator. This
should either be moved to the “Definitions of Terms” section or to R4 of the standard where the term is used.
Response:
American Transmission
Company
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
Yes
1) It is suggested that the word "located" in the third bullet in Measure 1 and Measure 2 be replaced with the word
"originating". As worded, M1 or M2 could be interpreted to mean that vegetation originating outside of the right-of-way
which blows or sways into contact with conductors “located inside the ... right-of-way” would be evidence of a violation
of R1 or R2. Utilities generally are very limited in their ability to manage vegetative conditions outside of their right-ofways.2) Please reference the comments under Question 2 above regarding the incompleteness of requirements R3
and R7 in fully replacing the CCZ management concepts utilized in the Draft 1 version of the proposed FAC-003-2.3)
The requirement R4 Guidelines and Technical Basis narrative is inconsistent with requirement R4. Specifically, in the
Guidelines and Technical Basis section the second paragraph’s introductory sentence identifies a requirement for an
imminent threat procedure, and the second bullet in this paragraph identifies a need to identify vegetation related
conditions that warrant a response. Neither of these items are a requirement of R4 as currently written. R4 only
speaks to the notification of the responsible control center when it has verified knowledge of a vegetation imminent
threat condition.4) The requirement R7 Guidelines and Technical Basis section is written with an inappropriate bias
towards very extensive or time based vegetation maintenance programs. Comments received from previous draft
standard reviews have revealed that there are many other effective program approaches being utilized by the industry.
It is suggested that this section be revised to broaden its scope to incorporate these other program approaches.
Yes
1) I would like further examples of inactive portions of corridors. For example would a ten foot buffer strip that is in
addition to a normal width to stay off a property line but is included in an easement plat but not cleared be considered
inactive corridor or not? 2) The MVCD definition may not be realistic in its wording. Many utility companies may not be
able to maintain these clearances at “design of Transmission Facility”. This needs further definition maybe “NESC
moderate wind”. Many utilities in coastal areas will design lines for high sustained winds due to hurricanes these
clearances may not be possible to maintain under these conditions however the line may be designed to with stand
these winds.
Yes
1. Requirements R1 and R2 - We do not agree with the "zero tolerance" for real-time observation of encroachments
that do not cause an outage. When discovered, most Transmission Owners (TO) take immediate action to alleviate
encroachments and it is not appropriate to be fined for taking immediate action when no outage has occurred.
Therefore, a violation should only occur when the TO has not immediately alleviated the situation within 24 hours. We
suggest the following change to the first bullet in Measures M1 and M2: "Real-time observation of encroachment into
the MVCD that is not corrected within 24 hours."2. Measurement M1 and M2 - For additional clarity, we suggest
Response:
Western Area Power
Administrtaion
Response:
Ga Transmission Corp
Response:
FirstEnergy
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Organization
Yes or No
Question 13 Comment
adding the following wording from Guideline and Technical Basis into M1 and M2 - "Brief encroachment by falling
vegetation are not considered a violation."3. Requirement R4 - Since the intent of this requirement is the immediate
notification of an imminent threat, we suggest adding the word "immediately" between "shall" and "notify".4.
Requirement R5 - We suggest removing the term "temporarily" in the requirement. Some constraints faced by
Transmission Owners are permanent and appropriate alternate action is permanently implemented. 5. Requirement
R7 - Although we agree that the TO should be allowed to adjust the plan, the use of the term "flexible" is subjective.
Additionally, the phrase "to ensure no vegetation encroachments occur within the MVCD" is redundant with the other
requirements of the standard. Therefore, we suggest revising the wording of Requirement R7 to the following: "Each
Transmission Owner shall implement an annual vegetation work plan. Adjustments to the work plan to defer work
beyond the calendar year are acceptable and shall be documented."6. Coordination between Project 2007-07 and
2010-07 - Since the TO-GO interface team has identified the need for Generator Owner (GO) applicability in the FAC003 standard, we believe that these two drafting teams should coordinate the addition of the GO into this Version 2 of
FAC-003. It would not seem sensible to revise Version 1 of FAC-003 to include the GO while Version 2 is developed
and approved without applicability to the GO.7. Compliance Section - Under "Additional Compliance Information", we
suggest removing the parenthetical phrase "See Administrative Procedure" and replace with "None". Since the
Administrative Procedure is not part of the requirements, it is not sanctionable and should not be included in the
Compliance Section.
Response:
MRO's NERC Standards
Review Subcommittee
Yes
1. Need definition for the phrase “Major WECC Transfer Paths”.2. In question 2 of the comment form, it refers to the
“bulk power system.” This standard does not cover the bulk power system, it covers lines above 200kV and certain
ones below 200kV.
Yes
4.2.4 States that the Standard is not applicable to “...to Facilities .... located inside the fenced area of a switchyard,
station or substation”. This implies that anything within the fenced area of a switchyard, substation or power plant does
not fall within the jurisdiction of FAC-003-2. Some fenced in areas could be very large and susceptible to vegetation
encroachments issues.4.3.1 Suggest including in the Force Majeure government a phrase referencing government
interference, such as “Federal, State or other regulatory interference, including legal or other legislative actions, that
prevents performance to comply with this reliability standard.”M1 & M2 bullet: “Real-time observation of encroachment
into the MVCD” implies that real-time observation of vegetation encroachment ensures reliable operation the Bulk
Electric System. The reliability standard objective states;”To improve the reliability of the electric Transmission system
by preventing those vegetation related outages that could lead to Cascading.”However, real time observation of
current operating conditions provides no assurance that vegetation will not lead to outages. BGE recommends
removing the language. If an inspector finds vegetation encroaching into the MVCD during a visual inspection he / she
Response:
BGE (on behalf of
parent/affiliate
companies: CEG, CPSG,
CECG, CNE & CENG)
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
should immediately initiate an Immediate Threat Notification. Therefore, this measure has no value.Disagree with R6.
- Inspection Frequency. Very prescriptive. Please consider allowing TO’s to select an annual frequency that best fits
their requirements, such as calendar year, every growing season, every non-growing season, etc. BGE currently
defines their inspection frequency as annually during the non-growing season, October 1 to May 1. BGE believes
inspecting during the dormant season is a best practice due to the ability of the inspector to identify vegetation
defects, especially off the ROW, which could be hidden during the growing season due to foliage, canopy cover, etc.
Also, if a utility elects to leverage an advance technology, such as LiDAR, it provides the most effective results when
LiDAR is utilize during the growing season, therefore allowing the results of the advance technology to enhance the
fall to spring inspection cycle. All of the above comments are submitted on behalf of:
- Baltimore Gas & Electric
Company - Constellation Energy Group, Inc. - Constellation Power Source Generation, Inc. - Constellation
Energy Commodities Group, Inc. - Constellation New Energy, Inc. - Constellation Energy Nuclear Group, Inc.
Response:
Arizona Public Service
Company
Yes
APS objects to number 3 Objectives statement. This is the only reliability standard that has at its Objective to prevent
vegetation related outages that could lead to cascading. This is a reliability standard and its objective needs to be:
“To improve the electric Transmission system by preventing vegetation related outages.” Requirement 6: To ensure
reliability the TO’s are responsible for doing an annual inspection. You either do it or don’t and if you don’t finish it
you should be held accountable. There shouldn’t be a lower VSL because you didn’t finish all of it. This is poor
planning on the utilities part.Requirement R7: When developing the annual work plan the Transmission Owner should
allow time for procedural requirements to obtain permits to work on federal, state, provincial, public, tribal lands. In
some cases the lead time for obtaining permits may necessitate preparing work plans more than a year prior to work
start dates. Transmission Owners may also need to consider those special landowner requirements as documented in
easement instruments. There needs to be parameters for the TO to show they allowed time for procedural
requirements. An example, some land agencies will give you permission to perform work in as little time as two weeks
and others can take two years. Even within the same land agency the timing of approvals is a moving target. APS
recommends the TO must show documentation it submitted their Vegetation Management Plan to the land agency at
least 120 days prior to the required start date. If the land agency doesn’t respond within this time frame and the utility
can not perform the work they shouldn’t be held responsible.
Yes
Generally, I believe this document is a huge improvement. The requirements are much clearer and easier to
implement than some versions from the past. I do not understand why R7 is still in this standard however. It appears
to be a requirement whose purpose is only to dictate HOW an entity must document its implementation of its
vegetation management program. Thus, I believe this requirement should be removed.
Response:
JEA
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
Yes
In R5, the SDT should better define the phrase 'where a transmission line is put at potential risk due to the constraint.'
This is rather vague and could lead to inconsistent practices between utilities. Con Edison defines all undesirable
species on the full width of the ROW as 'potential risks to the transmission line' regardless of height or location at the
time of vegetation management. Interim corrective action should only be required when the potential risk is
approaching the imminent threat classification.
Yes
In R5, the SDT should better define the phrase 'where a transmission line is put at potential risk due to the constraint.'
This is rather vague and could lead to inconsistent practices between utilities. ORU defines all undesirable species on
the full width of the ROW as 'potential risks to the transmission line' regardless of height or location at the time of
vegetation management. Interim corrective action should only be required when the potential risk is approaching the
imminent threat classification.
Yes
In the Applicability section, the use of the term “Other” should be changed to another term, such as Force Majeure,
since its purpose is not to include scope into the standard, but exclude scope from the standard.R4 uses the term
“responsible control center”, which seems inappropriate. Consider using the term “responsible operating entity”. The
M4 is simply a restatement of R4 without an example of types of evidence, e.g., such as voice recording, operator
logs, etc.R5, consider using a different term than “constrained”, which has other transmission related connotations.
Possibly “limited” or “hindered”.FMPA disagrees with a 3 year retention schedule for all of the Requirements and
Measures. R4 and M4 would seem to be supported by operator logs, voice recordings and such and three year
retention for such evidence is inconsistent with other standards.
Yes
In the previous draft the VRF’s R6 and R7 were listed as Medium; and in the latest revision they are listed as High
VRF’s, what is the reason for this change or is this just a mistake?”Temporarily” should be removed from the
requirement (R5 pg.9) this will be an interpretation issue and doesn’t add to the requirement.
Response:
Consolidated Edison
Company of New York,
Inc.
Response:
Orange and Rockland
Utilities, Inc.
Response:
Florida Municipal Power
Agency (FMPA) and
Some Members
Response:
ITC Holding
Response:
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Northeast Power
Coordinating Council
Yes or No
Question 13 Comment
Yes
NPCC participating members recognize the hard work the drafting team has done and appreciate the efforts to
address the issues presented. An issue seems to be a recurring theme with the advent of the MVCD. Some believe
that the eventual adoption of this standard with MVCD will result in the reduction of current trimming cycles and
clearance distances. Opinions have been expressed that this may result in increased vegetation contacts and trips.
After reviewing some of the MVCD distances, for example 3.12 feet at sea level for 345kV, some expressed the
opinion that this is much less than what typical trim practices are today, and may actually “lower” the bar for trimming
practices, and effectively allow a TO to trim less and reduce the margin of clearance.Requirement R1 discusses
encroachment. M1 bullet 1 states one way to violate encroachment would be:”Real-time observation of encroachment
into the MVCD...”From a practical standpoint what is meant here? Who would determine this and how would it be
done? The intent is certainly to avoid a sustained outage. However, if a TO was in the process of trimming after an
active growing season, and noticed a slight encroachment while trimming, would it be considered a reportable
violation? How would the RE measure compliance with avoiding something, with the absence of a sustained outage
reported? A statement should be added to the “Definition of Terms Used in Standard” section to indicate how terms
defined in the NERC Glossary and used in the standard are identified (for example capitalizing the first letters of the
term or using italics or bold font). To avoid confusion when a term might be used at the beginning of a sentence,
bolding or italicizing the term should be considered. The Guideline and Technical Basis section should be a separate
document, and not part of the standard (mentioned previously in question 8). It should be included in the Technical
Reference Document.Applicability 4.2.4--A fenced area of a switchyard, station or substation can have vegetation that
could present a potential risk to facilities. What is the reason for this exclusion, and the exclusion in Applicability
Section 5--Background paragraph 3 “...this Standard does not apply...to line sections inside an electric station
boundary.”Referring to our previous responses to questions 1 and 2 for Requirements R1, R2, and R3, what rating is
used? It is possible to operate above a facility’s normal rating for a prescribed time (for example a transmission line
may be operated above its normal rating but below its LTE rating for up to 4 hours). Operating at emergency ratings
should be considered. During emergencies transmission lines might be loaded to their emergency ratings, thus
increasing the sag, thus increasing the likelihood of a vegetation caused trip if the required clearances don’t take into
account the increased loading. Especially in an emergency loading scenario, operating into an avoidable potential risk
is very undesirable. Referring to FAC-003 - Table 2 - Minimum Vegetation Clearance Distances (MVCD), for 345kV
(line to line), 3.12 foot (assuming to ground) clearance is required at sea level. IEEE Std 516-2003 IEEE Guide for
Maintenance Methods on Energized Power Lines dated July 29, 2003, Table 5 (p. 20), lists the MAID (minimum air
insulation distance) for 345kV phase to phase equipment at altitudes below 900 meters (2953 feet) to be 2.88 meters
(9.45 feet) phase to ground. It is understood that MAID is “The shortest distance in air between an energized
electrical apparatus and/or a line worker’s body at different potential...”, but the clearance differences at the various
voltage levels seem very significant. If a figure is referenced in a requirement (R3), it would be preferable to have
that figure positioned within that requirement. If that is not possible, it should be explicitly stated where the figure can
be found. Requirement R5--Legal actions and other events that prevent vegetation maintenance work be included in
the Introduction Section 4.3.1. What does “interim corrective action” mean specifically? The requirement as written
needs to be made clearer. Without the Rationale box it loses its meaning (refer to the question 3 response).Interim
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
Corrective Actions are explained on page 28 of the separate Technical Reference Document, with examples such as
modifying the inspection interval, or limiting the loading on the line (effectively changing its rating) to minimize sag.
“Interim corrective action” should be defined and added to the Glossary.Are voltages referred to in the Standard
(Applicability Section) line to line or line to ground for ac systems? (345kV line to line is 199kV line to ground, below
the 200kV threshold in the standard). Are the voltages also applicable to DC equipment?
Response:
Xcel Energy
Yes
On page 6, in paragraph 5 ("Background"), we suggest enhancing the 3rd paragraph by inserting the words "Active
Transmission Right-of-Way", as follows: "...addresses vegetation management in the Active Transmission Right-ofWay along applicable overhead lines..." This change emphasizes that this does not apply to areas outside of the
Active Transmission Right-of-Way. Comments to Requirments and Measures Section (pages 7 -9)The term Minimum
Vegetation Clearance Distance (MVCD) should be explicitly defined as a new "definition" rather than explained in a
"rationale" box. Additionally, formalizing the definition would give weight to how "Table 2" is supposed to be used. As
it is currently drafted, the requirements of the standard don't refer to Table 2 at all. (i.e., - our understanding is that the
rationale boxes are for clarification and the requirements should be able to convey what is necessary on their
own.)MVCD - while we understand this as an 'engineering term', the terminology is difficult to convey since land
owners tend to question the need to do anything more than the "minimum". We recommend revising the term to
"Critical Clearance Distance (CCD)". M1 & M2 should be revised to insert the concept of "verified knowledge" (that is
used in R4). This is because M1 & M2 do not clarify whose real-time obseration it is referencing. As such, we
recommend stating "Real time verified knowledge of encroachement into the MVCD..." instead of just the term
"observation" to make it clear that a trained, knowledgeable individual is making this determination. Also, it may make
sense to turn "verified knowledge" into a defined term since it will be used in M1, M2 and R4. If it is not made a
defined term, then the meaning in M1 & M2 must be clarified in those sections (maybe a cross refefrence to as
defined in R4 and on page 15 will work). However, we think it is best to make it a defined term.R5: Rationale box:
consider enhancing the second sentence by adding the word "significant", to read "...avoid significant risk..."R5:
Requirement & Measure: consider adding exception language when the constraint is known to be longer than
"temporary". e.g. - stand offs can occur on right of ways that cross federal and tribal lands and the entity cannot force
the federal government to do do something.R6: Xcel Energy still believes the requirement in R6 that mandates an
annual inspection is too onerous and is at odds with the results-based approach of these revisions. Xcel Energy
urges the retention of the provision in the existing standard that allows the Transmission Owner to set the frequency of
inspection. In some areas of the country, annual inspections may not be adequate. Yet in other areas, a longer
inspection frequency may be perfectly reasonable and practical. Our point is that inspection frequency should not be
treated as if it were “one size fits all”. If treated this way, we feel this could pose a risk to reliability and is not likely to
be cost-effective. The Transmission Owner should be allowed some flexibility. However, if the drafting team
disagrees and determines that an annual inspection is to be mandated, Xcel Energy believes that an exception to the
annual inspection is appropriate when a non-subjective advanced technology such as LIDAR is utilized to achieve
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
actual clearance distances. This places the Transmission Owner in a situation where it can rationally determine that
the objectively measured distances result in a situation where an inspection need not be performed within the next
year. It is suggested that R6 be revised to read as follows: Each Transmission Owner shall perform a Vegetation
Inspection of all applicable transmission lines at least once per calendar year, unless the Transmission Owner, based
on a non-subjective advanced technology, such as LIDAR, determines that a longer inspection period is
appropriate.R7: Revise the requirement to eliminate the superfulous language at the end of the sentence that says "...
to ensure no vegetation encoachments occur wihtin the MVCD", i.e., R7 would read as "Each Transmission Owner
shall execute a flexible annual vegetation work plan."
Response:
Independent Electricity
System Operator
Yes
Our comments to this point have focussed exclusively on the proof-of-concept for using the results-based criteria for
developing a reliability standard. We have one comment on the specifics of Requirement R7 and its Measure M7.
The rationale for M7 states that a flexible annual vegetation work plan allows for work to be deferred into the following
calendar year provided it does not have the potential to become an imminent threat. This will evidently require some
kind of assessment in each case. Will entities be expected to document those assessments as evidence in support of
its view that the associated vegetation did not have the potential to become an imminent threat, or would it be
sufficient to look at the outcomes of these decisions to defer items in the work plan - i.e. there were no imminent
threats and sustained outages? Finally, we applaud the drafting team for its efforts in developing this draft. The
industry has often commented about overly prescriptive requirements and I believe this draft has focused on the
“what” of the requirements and left the “how” up to the appropriate entities. In our view this draft, with its succinctly
stated requirements, represents an important first step in the right direction. Thank you.
Yes
Page 9, M7 - what are the limits of flexibility in executing "a flexible annual vegetation work plan"?
Yes
Please review the VRF Guideline because we believe that the VRF’s for R6 and R7 should possibly be changed to
“Medium” instead of “High”. They were “Medium” in the last draft of FAC-003-2.
Yes
Please see e-mail sent to [email protected]. Thank you.
Response:
Ameren
Response:
Duke Energy
Response:
Westchester County
Board of Legislators
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Organization
Yes or No
Question 13 Comment
Yes
Progress Energy believes that the VRFs for R6 and R7 should be returned to “medium” since no singular “risk-based”
requirement in a defense in depth strategy should be depended upon to eliminate/prevent risk to grid reliability. In a
defense in depth strategy, no one specific “risk-based” or “competency” requirement should be “high” unless failure to
complete that singular requirement will result in an immediate “high” risk to grid reliability (if that is the case, then the
standard is not truly employing a defense in depth approach). Also, R6 and R7 (which have a zero tolerance) have no
differentiation between grid impacting facilities (IROL) and facilities primary impacting local customer reliability (i.e.,
radial lines to load, etc).
Yes
R4: The requirement to notify the responsible control center of an imminent threat may potentially result in confusion
at the control center if the transmission lines in question are not part of the control center's actively monitored grid. As
an example, NCEMC has a few short radial 230kV lines that fall under the requirements of this standard, but these
lines are not shown on the BA's control center system because they are downstream from a protective device located
at a tap off networked transmission lines. A vegetation-related outage on these lines would not result in any of the
transmission elements continuously monitored by the control center being outaged, and the operator receiving a call
notifying the imminent threat may not have any familiarity with the line section being identified, since it is not on their
system. If prompt action to respond to any imminent threat is the intended goal, why not consider making it a
significant part of the mitigating factors of an actual outage.
Yes
Recommend deleting the “to avoid a Sustained Outage” in R1 and R2. Has a violation occurred if a momentary
(successful reclose) outage occurs but the TO did not “observe(s) vegetation within the” MVCD? While it may not
have to be reported on the quarterly report, Table 1 for the Lower VSL seems to suggest a violation of the MVCD has
occurred, even if it was not “observed” as “required” in the Guideline and Technical Basis.In the Guideline and
Technical Basis, the final paragraph for R1 and R2, line 3 contains an extra word “...encroachment is not be a
violation...”In the Guideline and Technical Basis, the third paragraph for R6, line 2/3 contains an extra word “...230kV
transmission at least once line during the calendar year.”
Yes
Requirement 4:Recommend the SDT consider modifying to make it clear the requirement applies to threats within the
right of way (ROW).Requirement 4.3.1:Recommend adding human activities to the list of causes. Logging activities
Response:
Progress Energy
Carolinas
Response:
North Carolina EMC
Response:
City of Tallahassee
(TAL)
Response:
Cleco
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Organization
Yes or No
Question 13 Comment
are listed but other human activities such as private property owner tree care operations are not.
Response:
Exelon
Yes
See R6. Exelon prefers “annual” to “calendar” but notes the requirement runs counter to the results based approach
and could be interpreted to be inconsistent with R7.The Rationale for R6 is ambiguous and without justification
suggests shorter but not longer cycles are acceptable. If local factors can shorten a cycle, they could also increase it.
The Rational is in conflict with the prescriptive nature of the requirement.
Yes
Standard Development TimelineThe Development Steps Completed section of the standard is incomplete. This
section should include the dates of previous postings. Draft 1 of revised standard was posted for stakeholder
comment from 10/27/08 - 11/25/08. Draft 2 of revised standard was posted for stakeholder comment from 09/10/09 10/24/09.Definitions of Terms Used in StandardThe definition of Active Transmission Right-of-Way is ambiguous and
subject to interpretation. This definition need to be revised to add clarity. It is unclear what “active transmission
facilities” are. In the gray box, the SDT should explain what “active portions of corridors” are, and how that is different
than the “land that is occupied by active transmission facilities.” The terminology should be consistent. The example
should state whether the width is the portion that has been cleared or should be cleared and if it was not maintained
and should have been. The SDT should explain the reference to the National Electrical Safety Code in the gray box,
and how it differs from the IEEE clearances. In addition, the team should explain why the Table 2 clearances set forth
in the standard itself are not referenced. The examples in the “inactive portion” suggest that there are active
transmission facilities (see references to conductors and circuits). The SDT should provide the rationale for excluded
them from vegetation management. While vegetation is permitted to exist at the corridor edge, the SDT should
address why there is no obligation to maintain it. The revised definition of Vegetation Inspection does not seem
necessary. It appears that the SDT is using the definition to set an expectation for enforcement by adding “which may
be combined with a general line inspection.” If both vegetation and general line inspections are to occur concurrently,
there should be minimum background requirements to perform such inspections. We recommend that the last portion
of the draft definition be moved to the Application Guideline section so the definition of Vegetation Inspection should
be “The systematic examination of vegetation conditions on an Active Transmission Line Right of Way.”The team
should consider making Minimum Vegetation Clearance Distance a defined term.Effective DatesThe effective date for
Ontario needs to be tied to the effective date in the U.S.With respect to the second exception, the team should provide
the rationale behind the exception for the effective date for “existing transmission line operated at 200kV or higher that
is newly acquired by an asset owner and was not previously subject to this standard”. All existing transmission lines
operated at 200 kV or higher are currently subject to vegetation management. Please explain why a new owner would
get an exception for this.Based on the wording in the Exceptions section, it appears that some lines in the US could be
brought into this standard prior to regulatory approval. (i.e. Lines operated below 200kV, designated by the Planning
Response:
NERC Staff (12 staff
members)
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Coordinator as an element of an IROL or as a Major WECC transfer path, become subject to this standard 12 months
after the date the Planning Coordinator or WECC initially designates the lines as being subject to this standard. An
existing transmission line operated at 200kV or higher that is newly acquired by an asset owner and was not
previously subject to this standard, becomes subject to this standard 12 months after the acquisition date of the
line(s))ObjectiveThe purpose of this standard should not be limited to outages that lead to Cascading, but prevention
of all vegetation related outagesApplicabilityThis standard should apply to Generation Owners.The term Facilities is
defined to exclude those in a fenced area of a switchyard, station or substation. The SDT should provide the basis for
the exclusion.Footnote 1 needs to be clarified. It is too cursory.The “Other” section should not be included in this
section. It is the expectation that the Compliance Enforcement Authority will not expect the Transmission Owner to
prevent tree contacts that the TO could not prevent. This might be better suited in the Application Guideline section.In
the “Other” section, the SDT should provide rationale for why the standard is not intended to address “human
errors”.The SDT might consider rewording the “Other” section as:”This Standard shall not apply in circumstances
where a requirement of this Standard was not complied with due to Acts of God, flood, drought, earthquake, major
storms, fire, hurricane, tornado, landslides, logging activities, animals severing trees, lightning, epidemic, strike, war,
riot, civil disturbance, sabotage, vandalism, terrorism, wind shear, or fresh gales that restricts or prevents performance
to comply with this Reliability Standard's requirements, so long as the non-compliance was not caused by the fault or
negligence of the Transmission Owner.”The team should provide justification for the applicability criteria they have
selected; specifically why a 200 kV cutoff was chosen.The team should provide justification for eliminating fall-ins from
outside the ROW.BackgroundAs a general comment, the background section seems repetitive.The fourth paragraph
of the background section notes that this standard is not intended to prevent customer outages due to tree contact
with lower voltage distribution systems. It is clear from the applicability section that this pertains to 200 kV and higher,
although the standard contemplates that some lower voltage facilities could be subject to the standard. The SDT
should address whether this paragraph also address customer outages due to tree contacts with respect to 200 kV or
higher facilities.Requirements R1 and R2:R1If an auditor were to assess compliance with R1, they would need to have
the list of conductors that were associated with an IROL or a Transfer Path. This list should be identified in the list of
evidence that must be retained.R1 & R2 In the Rationale box, the term “a proven transmission design method” is
used. Please describe what this refers to, and whether these refer to the IEEE minimum clearances. The SDT should
state what the method was and what changes, if any, were made to it.The SDT should address why the requirements
only reference line conductors and not transmission facilities or transmission lines (the VSLs refer to transmission
lines).The word “encroaching” should be replaced with another word/phrase that clearly defines the concept for
compliance purposes. The word, “encroach” could be interpreted differently by different people (how close can
vegetation grow before it enters the MVCD and is it a violation of R1/R2 - is it 2”, 2’, 10”, 10’?), whereas the word
“enter” is explicit.Guidance is offered in the Guideline section of the standard that implies that all TOs should retain
this evidence, yet the evidence is not identified anywhere in the Measures or evidence retention sections of the
standard.We suggest adding the phrase, “of its” to clarify that the TO is only responsible for facilities it owns. “In
addition, the Transmission Owner should maintain detailed records of the findings of its planned inspections. This
documentation constitutes evidence that the Transmission Owner had no encroachments into the MVCD Table
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distances.”Immediately after the phrase MVCD, we suggest including the text “as specified in FAC-003-2
Transmission Vegetation Management Table 2 - Minimum Vegetation Clearance Distances (MVCD). Table 2 is not
referenced in any of the requirements. If you require entities to use the MVCD as stated in Table 2, then this should
be referenced in at least R1 and R2.M1 & M2Overall, it appears that these measures are asking for evidence of noncompliance. The initial item under M1 & M2 (shown below) should be rephrased with the addition of the words “verbal
or written report of a,” otherwise the measure doesn’t seem as though it could be used objectively. In addition, the
words Real-time should be removed, as they ad confusion to the issue.”Verbal or written report of a observation of
encroachment into the MVCD, or”The phrase “Multiple Sustained Outages on an individual line, if caused by the same
vegetation, will be reported as one outage regardless of the actual number of outages within a 24-hour period” should
be changed to a footnote that reads “Consider Multiple Sustained Outages on an individual line, if caused by the same
vegetation, as one outage regardless of the actual number of outages due to the same piece of vegetation”Momentary
outages due to vegetation are also a violation of R1. Momentary outages from tree contacts may not result in a
sustained outage but are evidence of a tree within the MVCD. The requirement should not be limited to only
sustained outages. Consider this scenario: An entity self-reports a violation of the standard. Does that mean that if
there is no actual "real-time observation" or a "Sustained Outage" there is no violation? Who must do the observing?
Please explain.Requirement R3 Consider this scenario: A Sustained Outage occurs on a location that was not
considered and therefore was not part of the TO’s TVMP. Would this result in a violation simply because the location
was not considered when the entity developed a TVMP?Requirement R4 Each requirement should identify “who shall
do what under what conditions, for what reliability outcome.” R4 has no identified reliability outcome. What is the
reason for making a prompt notification? Is it to give the real-time system operator information on which to develop
and implement an action plan if there is an outage on the line with the imminent threat? Then that should be stated in
the requirement. R4 contains explanatory information. The sentence “A vegetation imminent threat condition is one
which is likely to cause a Sustained Outage at any moment” should be moved to the blue box.Please explain what
“verified knowledge” means. The Rationale section does not really address this. While this is in the Guidelines and
Technical Basis section, it defines it as “implies reliable confirmation.” This should be clarified and put in the
measures section.”Imminent threat” should be defined so that it does not evolve into an enforcement issue.”Notify the
responsible control center” should be clarified so that it does not evolve into an enforcement issue.Application
Guideline for R4 should contain provisions in the imminent threat procedure for notification of the land owner.M4
should provide examples of acceptable evidence.Requirement R5 This requirement does not include a reliability
outcome. The requirement should be rewritten to include a reliability outcome.Requirement R6 The Rationale for R6
is that one year “seems to be reasonable.” The SDT should address how this relates to the practice in place now, and
whether it is consistent with current practice or is more or less than current practice. If inconsistent, the SDT should
provide an explanation.The Rationale states the TOs should consider other factors that could warrant more frequent
inspections. If so, the SDT should explain whether we are requiring them to do so if such factors exist.This
requirement does not include a reliability outcome. The requirement should be rewritten to include a reliability
outcome.Requirement R7 R7 is ambiguous; it is not clear how this could be enforced objectively. The rationale for the
“flexible” plan indicates that the owner can delay work as long as it will not pose an “imminent threat.” The SDT
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should explain what the Compliance Enforcement Authority would look at to determine that the work that was delayed
was not causing an “imminent threat.” The SDT should address whether it would ever be acceptable to delay work on
a critical line (covered under R1).In Requirement R7, please explain what “execute a work plan” means. Did the SDT
mean implement a work plan? As drafted, it could be read to just have one in place. The SDT should explain what
“flexible” means. Does it mean there will never be a FAC-003 violation if you fail to implement the plan? The
Rationale says the work can be deferred if it does not have the potential to become an imminent threat. Please
explain. Corresponding clarification changes should be made to the VSLs for this requirement.Either M7 or the
evidence retention for M7 needs to include the annual work plan. Without that the Compliance Enforcement Authority
can’t determine if the plan was executed. The VSLs for R7 imply that the entire annual plan will be accomplished. . .
not a “flexible” amount of the plan - the VSLs don’t line up with the use of the word “flexible.”According to the VSL
Guidelines the VSLs should be stated in language that identifies the degree of noncompliance in language that
identifies the amount that was noncompliant, rather than the amount that was compliant. VSLs for R6 and R7 are
stated in terms of the % of the required performance that was compliant and should be rephrased. GuidelinesThe
following guidance is offered in the Guideline section of the standard:Documentation or other evidence of the work
performed typically consists of signed-off work orders, signed contracts, printouts from work management systems,
spreadsheets of planned versus completed work, timesheets, work inspection reports, or paid invoices. Other
evidence may include photographs, work inspection reports and walk-through reports.Documentation is required when
the annual work plan is adjusted or not completely implemented as originally planned. The reasons for the deferrals or
changes and the expected completion date of postponed work should be documented.This implies that all TOs should
retain this evidence, yet the evidence is not identified in nearly this level of detain in the Measures section of the
standard. In addition, no part of the requirement or measure is clear in indicating that documentation is required to
support the need for a work plan adjustment. Evidence Retention The evidence retention periods specified don’t
reflect the guidance in the SDT Guidelines. Should the evidence retention be the later of three years or three years
from the last audit? The second paragraph should be stricken because it seems to contradict the first paragraph
retention period.VSLsThe SDT should verify that the VSLs for Requirement 3 are properly calibrated.Administrative
ProcedureThe Administrative Procedure does not require prompt reporting of sustained outages; rather it requires
only a quarterly report. This appears to be less stringent than the current requirements as employed today.The SDT
should explain what “blowing together” means, and how this is different from a tree that grows into a
line.FootnotesFootnote 1 should be deleted or modified. It is only relevant in explaining the proposed modifications to
the standard. In footnote 4 the word, “substantially” adds ambiguity.Guideline and Technical BasisIn the Guidelines
and Technical Basis section, it states “Requirements 1 and 2 state if the TO observes vegetation within the distances
prescribed in FAC-003 - Table 2 it is in violation of this Standard.” This is actually in the Measures 1 and 2 and not the
requirements.General commentsThere seems to be a lot of information not captured in the Requirements but rather
are in various other sections. The SDT should clearly delineate whether these other sections are considered part of
the Standard or just informational.With the next posting of the standard, the drafting team should include the following
four points for stakeholder review:1. Justification for selection of the applicable lines. 2. Table listing each FERC
directive and stakeholder issue (from the Issues Database) associated with the standard and identification of how the
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team addressed each of these3. Table listing each VRF and identification of how the proposed VRF meets both
NERC criteria for setting VRFs and FERC’s five Guidelines for approving VRFs4. Document identifying how the
proposed VSLs meet both NERC criteria for setting VSLs and FERC’s four Guidelines for approving VSLs.There is a
significant concern with the use of the Gallet equations in this standard. This standard eliminates Clearances 1 and 2
from the previous version and replaces it with a single Minimum Vegetation Clearance Distance (MVCD) based on the
Gallet equations. This approach reflects the most basic lowest common denominator and significantly lowers the bar
versus the performance expected from the existing standard. Further, it would not appear that responsible entities
would use the Gallet equations as the basis for the development of the vegetation management program.
Additionally, whereas the multiple clearance zones provide an indicator of proactive vegetation management, the
current proposal does not provide an equivalent demonstration of proactive performance. This approach appears
inconsistent with Order 693 and the presentation of NERC standards to provide a defense in depth strategy, which is
a fundamental outcome of the results-based standards process. Order 693 states in P24 that the “reliability mandate
of Section 215 of the Federal Power Act....contemplates the prevention of incidents, acts, and events that would
interfere with the reliable operation of the Bulk Power System.” The SDT should consider adding more clarification to
the draft standard and white paper describing the building blocks for determining how much vegetation management
(trimming) needs to be performed based upon growth rate of vegetation and the time between trimmings to reflect a
proactive approach.The SDT should consider the impact of moving the reporting requirement in the existing standard
to the compliance section of the new standard. The team should consider the reporting of this activity on an exception
basis within a pre-defined timeframe following the event. This approach would provide more timely awareness to the
Regional Entity and NERC of an event than the quarterly reporting expectation, and provide opportunities for
identification and implementation of mitigating strategies in a more timely manner. While this approach removes an
administrative type requirement from the standard that is believed to provide a deterrent to responsible entities, the
increased timeliness of reporting in an exception basis would provide greater benefit to the effort to maintain
reliability.Transmission Line is a defined term. The SDT should consider using this term in place of “transmission
line.”The report identified in the administrative section of draft 3 of FAC-003 is really a “Periodic Data Submittal” used
to assess compliance and does not belong in an administrative section of the standard - it belongs in the compliance
section of the standard. “Periodic Data Submittals” is one of eight different compliance monitoring and enforcement
processes that may be used to monitor and assess compliance. The eight processes are identified in the Uniform
Compliance Monitoring and Enforcement Program of the North American Electric Reliability Corporation and should
not be mixed in with other processes or procedures. Each standard must list the appropriate processes in the
compliance section of the standard so that there is a clear understanding of the purpose of the data submittal.As
drafted, FAC-003-2 applies only to Transmission Owners. It also should apply to Generator Owners. The SDT should
explain whether the issues brought forward in the GO/TO Report been considered and are addressed as part of this
revision.Please update the mapping document so that it compares the last version of the approved standard to the
latest proposed version of the standard so that it is easy to compare the proposed standard to the standard that is in
force now.
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Yes
Suggested Improvements to M1. and M2.The purpose of Requirements R1 and R2 is to require the prevention of
vegetation encroachments within the MVCD. As made clear in the background and remaining FAC 003-2
requirements, the overarching intent of FAC 003-2 is to prevent sustained outages caused by vegetation that could
lead to cascading. However, both M1 and M2 include real-time observations of encroachment into the MVCD as an
automatic violation of R1 or R2, respectively (even though the violations may not result in penalty or fine). This is
inconsistent with the “defense in depth” goal sought by the committee, as a real time observation using new
technologies may in fact demonstrate that the Transmission Owner is in fact aggressively managing vegetation to
meet the MVDC requirements and is discovering new encroachments and remediating them quickly and effectively
and thereby is not in violation of the standard.Similar to imminent threats, remediation procedures should be permitted
for encroachments as well and serve to make clear the observation is not automatically a violation. Classifying a realtime observation of an encroachment automatically as a violation of R1 or R2 penalizes a Transmission Owner for
identifying vegetation threats, which are less severe than imminent threats. Under Requirement R4, the transmission
owner is permitted to take appropriate actions to alleviate an imminent threat through short term corrective actions
upon observation of any vegetation that is near to or is encroaching into the MVCD. (See FAC-003-2 Guideline and
Technical Basis, Requirement R4). Considering the allowance for remedial action under Requirement R4 when facing
a condition that is “likely to cause a Sustained Outage at any moment,” it seems excessive to qualify a real-time
observation of an encroachment as a violation of R1 or R2. We suggest a better approach is to modify M1 and M2 to
allow for remedial action. Or, in the alternative, the standard should clarify that observations of encroachments using
software-enabled technology, such as LIDAR coupled with work order management systems, do not constitute a “real
time observation of an encroachment.” First, by modifying M1 and M2 to allow for remedial action as suggested below
will deal with the concern we raise:M1. Evidence of violation of Requirement R1 is limited to: o Real-time observation
of encroachment into the MVCD which is not mediated in accordance with R4. o ... M2. Evidence of violation of
Requirement R1 is limited to: o Real-time observation of encroachment into the MVCD which is not mediated in
accordance with R4. o ... In the Alternative, “Real-Time Observation” Should be Clarified. As noted above, a realtime observation of an encroachment is evidence of a violation of Requirements R1 and R2. Observations in real time
mean “an actual field observation or measurement of the conductor-to-vegetation distance and not a calculated
determination of relevant positions.” (See FAC-003-2 Guidelines and Technical Basis, Requirements R1 and R2)
Given the current definition, it is not clear observations using software-enabled LiDAR would trigger violations and
thereby would discourage the Standard’s emphasis on preventing sustained outages or Cascading due to grow-ins.
This may result in penalties for registered entities that are engaged in good faith activities to prevent sustained
outages. The meaning of “real-time observation” should be clarified as to remove any adverse incentives for
vegetation inspection and management. To implement this suggestion as an alternative to allowing remediation to
prevent an observation from being an automatic violation, the definition could be reworded to state:”Real-time
observation” means an actual field observation or measurement of the conductor-to-vegetation distance which is not
performed under the regular Vegetation Inspection of Requirement R6 or annual vegetation work plans in accordance
Response:
Utility Risk Management
Corporation
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with Requirement R7. Such observations do not include calculated determinations of relative vegetation positions.
Conclusion:Adopting one or both of these proposed changes would help R1 and R2 measures more fully meet the
goal of preventing overgrown vegetation and systemic failures triggered by flash over, as stated in the background
section on page 6 of FAC-003-2. The current M1 and M2 use of real-time observations conflicts with the expectation
that utilities engage in “defense in depth” measures. As the guidelines conclude regarding Requirements R1 and R2,
the Transmission Owner is expected to have a cohesive vegetation management program for managing vegetation in
such a manner as to maintain separation between conductors and vegetation. This is to function in conjunction with
the imminent threat procedure to facilitate interim corrective action. “However, brief encroachments by falling
vegetation are not considered to be a violation.” Making the changes suggested above - coupled with the existing
requirement that the utility mitigate an observation in accordance with the utility TVMP through a response schedule thereby advance the goals of the standard and take away an impediment to aggressive defense in depth.
Response:
SERC OC Standards
Review Group
Yes
The requirements (R6 and R7) for inspections and the performance of work plans are part of a defense-in-depth
approach and as such the TO is not depending on singular requirements to prevent sustained outages, therefore, the
VRF for R6 and R7 should remain medium not high. We applaud the attempt to improve the readability and ultimate
comprehension of reliability standards by changing to this new template. We have included some comments also
made by the SERC Vegetation Management Subcommittee (VMS).”The comments expressed herein represent a
consensus of the views of the above named members of the SERC OC Standards Review group only and should not
be construed as the position of SERC Reliability Corporation, its board or its officers.”
Yes
The requirements (R6 and R7) for inspections and the performance of work plans are part of a defense-in-depth
approach and as such the TO is not depending on singular requirements to prevent sustained outages, therefore, the
VRF for R6 and R7 should remain medium not high.
Yes
The standard should include only R1, R2 and the Clearance Table. Everything else should be in guidelines as to how
you might comply with the standard. If R3 thru R7 remain in the standard then it is virtually the same as it exists today,
just put in a different order.
Response:
SERC Vegetation
Management Subcommittee
Response:
GCPD
Response:
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CenterPoint Energy
Yes or No
Question 13 Comment
Yes
The term "Active Transmission Line Right-of-way" (ATLROW) is not defined in sufficient detail in the Definition of
Terms Used in the Standard section to know how to apply it to the Requirements and Measures. The Technical
Reference merely depicts the relative position of energized conductors, but it does not show a graphical determination
of the limits of the ATLROW. The ATLROW is missing a definable and determinable width in its current definition
within the Standard which makes it an arbitrary term and does not allow for a clear and measurable expected outcome
of each requirement. In several sections, the Standard relies on the specific determination of the physical width of the
ATLROW to determine applicability of the requirements. The Vegetation Inspection definition refers to “on” an
ATLROW. The Background section refers to “outside” the ATLROW. Table 1 refers to “within” and “on” the
ATLROW. M1 and M2 refer to “inside” the ATLROW. R3 and M3 refer to “on” the ATLROW. The Administrative
Procedure refers to “inside and/or outside” and “within” the ATLROW. The Guideline and Technical Basis section
refers to “on or near” the ATLROW and the “limited” ATLROW “width”. It also says that, “The Transmission Owner
should, therefore, endeavor to maintain its ATLROW to the full extent of its legal rights at all times in all cases.” Since
the Standard does not currently define how a Transmission Owner is to determine the specific boundaries of the
ATLROW, it would appear that the Transmission Owner is to make that determination on a case by case basis at its
discretion. Should that not be the intent, we recommend the definition for the ATLROW to be, “A strip or corridor of
land or aerial space that is occupied by energized transmission conductors with its operational clearance limits defined
by the Transmission Owner’s specific legal rights but in no case less confining than the MVCD applied to the
movement of the conductors within their Rating and Rated Electrical Operating Conditions.” This definition contains
sufficient detail to determine the physical limits of the ATLROW, and it allows for vegetation management to apply
within the full extent of the legal rights of the Transmission Owner while requiring a minimum area for vegetation
management in undefined ROW’s to ensure Sustained Outages are minimized.M1 contains a reference to “real-time
observation of encroachment into the MVCD” but does not explain who is to make the observation and where it is to
be documented. If this is to be done by the Transmission Owner, then perhaps it should be a Measurement under R6
and recorded under M6.The language in R6 refers to inspecting “transmission lines” and Table 1 for R6 refers to
inspecting “ROW”. Both areas should use consistent terminology.M1 and M2 have the potential for double jeopardy
when a Sustained Outage occurs because the Violation Severity Level has an entry for an MVCD encroachment
(which causes the outage) and another sister entry for the type of Sustained Outage. Some additional clarity in the
application of M1 and M2 is necessary.R5 should include the exception stated in the Rationale text box to add clarity
to the Requirement. R5 should read, “Each Transmission Owner shall take interim corrective action when it is
temporarily constrained from performing planned vegetation work, where a transmission line is put at potential risk due
to a constraint, except where the risk is avoided by implementing an alternate work methodology.” In the Guideline
and Technical Basis section for R1 and R2 (page 15), there is a reference to records of “planned inspections” and
“evidence” for no encroachment into the MVCD. This reference should be moved to R6 where the inspections are
required. If R6 is intended to provide evidence for M1, then that should be stated in R6.In the Guideline and Technical
Basis section for R6, the reference to the VSL calculation units and the example units should be consistent-the
example should use “line miles”, not just “miles”.Table 2 contains several “*” in the voltage column that are not
defined.In the Technical Reference on page 21, the following sentence should be deleted, “If constraints cannot be
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overcome and if design clearances are sufficient, an exception to the Transmission Owner’s 10-foot guideline might
be made.” The Technical Reference should not provide examples of granting exceptions as they may be
misinterpreted as an endorsement by NERC to increase the planting of trees near and under transmission lines
without taking into account several other factors such as ROW access, changing design conditions, future line
additions and rebuilds. The inclusion of modifications to the wire zone on page 24 regarding the wire-border zone
model should be re-examined to be sure they are specific to an environmental conservancy requirement while
allowing for construction and inspection access as needed.In the Technical Reference on page 22 under Planning and
Implementation, delete the sentence, “While designed primarily with transmission systems in mind, t is also applicable
to distribution projects.” The Standard should not imply its applicability to distribution systems since it is intended only
as a transmission standard.In the Technical Reference, the last sentence on page 26 starting with “Appropriate
actions...” should be moved to R5 where it applies. In general, the proposed FAC-003-2 has gone FAR beyond what
was contemplated by the Commission in FERC Order 693 and equates to a total re-writing of the Standard for no
apparent reason. The Commission's determination dealt with the following areas: (1) applicability; (2) inspection
cycles; and (3) minimum clearances on National Forest Service lands. For instance in Paragraph 729, the
Commission states, “As proposed in the NOPR, the Commission approves Reliability Standard FAC-003-1 with no
proposed modification on the issue of clearances. The Commission reaffirms its interpretation that FAC-003-1 requires
sufficient clearances to prevent outages due to vegetation management practices under all applicable conditions....”
Rewriting the minimum clearances introduced a new set of confusing definitions, and further burdens the
Transmission Owners with new documentation requirements with little if any benefit when compared to the Clearance
2 concept in the existing Standard.A preferred approach would have been to incorporate the following few items into
the existing Standard: (1) the RC versus the RRO; (2) the designation of a specific inspection frequency; (3) the Gallet
equation; and (4) the applicability to National Forest Service lands.
Response:
Ad Hoc Group subteam
formed to review draft
standard
Yes
The wording in R7 is troublesome. We believe that the process for developing the annual work plan is imbedded in
R3. As discussed in question 2, demonstrating capability to actually perform those actions necessary to ensure no
vegetation encroachments occur within the MVCD is the primary concern. Deferring such work into the next calendar
year appears contrary to this concern and neutralizes the defense-in-depth concept by diminishing the imminent threat
requirement of R4 to a primary means of defense. While we don’t want to incent vague annual work-plans, we also
don’t want to remove the imperative that the work must be done.
Yes
Under section 4.3.1 add in ice storms as one of the force majeure events. This type of event may impact many TOs
and should be included.
Response:
Nebraska Public Power
District
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Response:
Oncor Electric Delivery
Yes
Use of the Gallet equation to determine the minimum gap between vegetation and conductor to prevent sparkover
seems to be appropriate. No utility should be managing to this distance but developing a distance beyond this would
be arbitrary. This is a reliability standard not a worker safety or vegetation management practices standard. As
Federal agencies and other entities are interpreting the Standard to limit normal vegetation management efforts, the
FERC should develop and adopt an overarching memo allowing utilities to maintain vegetation under any agency
jurisdiction as a utility manages vegetation along the entire right-of-way corridor.
Yes
WAPA - UGPR would like to see "ice storms" specifically mentioned in Section 4.3.1. Having additional clarification as
to what is considered a "major storm" would also be helpful.
Yes
We believe the minimum vegetation distances are very granular and nearly un-measurable in real life. When a person
considers the table to be a list of minimums it seems that the regulated entities, or land owners would want the
distances to be as close to the wire as possible. We would not want a non-technical manager to believe that any small
distance outside of the noted distances is ok.
Yes
We have concern over establishing proof an outage is exempt due to fresh gale. A fresh gale, or even a localized
thunderstorm, can easily produce wind gusts that exceed the lines rated capacity for blow out. If an outage occurs
under these conditions, the standard provides an exemption under Section 4.3.1, but there is often no way to
empirically prove conditions exceeded the lines normal operating conditions. How should a utility handle these
situations?
Yes
We have concern over establishing proof an outage is exempt due to fresh gale. A fresh gale, or even a localized
thunderstorm, can easily produce wind gusts that exceed the lines rated capacity for blow out. If an outage occurs
under these conditions, the standard provides an exemption under Section 4.3.1, but there is often no way to
empirically prove conditions exceeded the lines normal operating conditions. How should a utility handle these
Response:
Western Area Power
Administration - Upper
Great Plains Region
Response:
Bonneville Power
Administration
Response:
Omaha Public Power
District
Response:
Southen Company
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situations? Please note there is a typographical error in the third paragraph on page 15, “...encroachment violation is
not be a violation...”We would like to thank the Standard Drafting Team for their hard work. The time and effort they
have put into developing this standard is obvious.
Response:
Dominion
Yes
While not related solely to this standard, we suggest that no future standard be effective until approval has been
granted by the applicable regulatory authority. Having an effective date that differs from the mandatory date is causing
confusion/chaos on the part of the applicable registered entity(ies). With the current process, it is possible to have a
standard that is mandatory conflict with a superseding newer version (or a new standard that contains requirements
meant to supersede those in the mandatory standard). Applicable entity(ies) may not be able to comply with both
when this is true, and may not be able to take steps necessary to transition from mandatory requirement to
superseding requirement without becoming non-compliant.
Response:
Westchester County
Board of Legislators
1.
Bulk Electricity System NOPR – FERC recently issued a notice of proposed rulemaking to revise the definition of
“bulk electric system” (BES) to include all transmission facilities with a rating of 100 kV or above. 130 FERC ¶ 61,204
(Mar. 18, 2010). If approved, such revision might significantly increase the amount of transmission facilities subject to
standard FAC-003. In areas with dense residential and commercial development, this revision will exacerbate
existing conflicts between homeowners, municipalities, affected transmission owners (TOs), and regulating agencies.
As described in comments below, compliance with the existing or perceived requirements in FAC-003 has produced
numerous conflict in areas of dense development and narrow rights-of-way between homeowners, TOs, and
regulating agencies because of economic, environmental, and aesthetic impacts. If FERC adopts the proposed BES
definition, then the FAC-003 standard (current 001 and draft 002) should be extensively reviewed by the drafting
team to evaluate the amount of affected facilities and the need for standard revision to avoid as far as possible further
conflicts.
2.
“Background” Section 5 – The draft adds a new section titled “Background” (Section 5). The existing standard FAC003-1 does not include a similar section. This narrative section appears to provide interpretation on the rationale for
a vegetation management reliability standard and to clarify the standard applicability. This discussion may be more
appropriate in the accompanying technical reference, which describes and clarifies standard FAC-003. While
identifying overgrown vegetation as cause of major outages and operational problems, this section fails to state that
many other causes can lead to Cascading events. Indeed, of the many NERC reliability standards, only one, FAC003, concerns vegetation management. While the August 2003 blackout was initiated by a tree contact, there were
numerous other factors that caused this power outage to spread to over a dozen states. Section 5 should therefore
be revised to clarify that FAC-003 is only one of many factors that can lead to a large-scale grid failure.
125
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
3.
Standard Applicability Across Land Uses – Standard FAC-003-1 and the proposed draft do not vary in applicability,
even though the types of land uses within and adjacent to transmission facilities vary widely. Among certain land
uses, such as dense residential development, this can lead to substantial conflict between the TO and adjacent
landowners, especially concerning environmental, aesthetic, and economic impacts. The Westchester County Board
of Legislators identified such problems in its recent resolution, available at
http://meetings.westchesterlegislators.com/Citizens/FileOpen.aspx?Type=4&ID=2828&AgencyName=WestchesterCo
unty .
Notwithstanding the reliability imperative expressed by Congress in enacting Section 1211 of the 2005 Energy Policy
Act, the implementation of reliability standard FAC-003 has produced significant challenges for all parties in suburban
areas. In particular, surburban area homeowners, often on small parcels, that abut or are near to transmission rightsof-way have experienced dramatic impacts upon their properties and property values when TOs exercise their “full
extent of legal rights at all times and in all cases”, as stated on page 18 of the draft. Therefore, the development of
standard FAC-003 must consider this backdrop and select requirements and accompanying text that provide some
balancing of electric reliabilty with environmental and economic impacts. As presently written, the draft does not
acknowledge such balance.
4.
Varying Conditions – Requirement R1.2.1 of Standard FAC-003-1 identifies numerous local conditions that should be
considered in determining appropriate clearance distances. This balanced evaluation of factors should be retained in
FAC-003-2.
5.
Full Legal Rights – The draft encourages TOs to exercise full legal rights at all times and in all cases. This language
is not included in present standard FAC-003-1. As noted above, electric reliabilty and TO compliance with FAC-003
must not preclude other important societal factors. The language encouraging full exercise of legal rights should be
removed from the draft.
Response:
KCPL
Yes
Requirement 4:
Recommend the SDT consider modifying R4 to make it clear the requirement applies to that which is within the Right
Of Way (ROW) for the transmission facility. Obviously, the Transmission Owner has no authority or control beyond
the ROW. This is also an audit concern regarding “triggering” this requirement on a subjective evaluation of
“imminent threat”. How does a Registered Entity, Regional Entity or Auditor determine what constitutes an “imminent
threat”? This will be a matter of opinion and makes this a difficult requirement regarding compliance when a
difference of opinion arises.
In addition, as proposed, this requirement does not address the need to take immediate corrective actions to mitigate
an imminent threat. The previous FAC-003 Standard included taking action to remove the “imminent threat” which is
not included in this proposed version 2. What was the intention of the SDT in this regard? Recommend the SDT
126
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
consider language to include taking action to remove the imminent threat.
In the “Guideline and Technical Basis” section:
1. Under R6: believe the word “per” is missing in the first sentence of the third paragraph between “once (per) line”.
2. Under R7: concerned regarding the use of words such as “never”, “at all times”, and “in all cases” in the bulleted
items with paragraph 6 in this section as a guiding document. This is the kind of material that is creeping into
compliance audits and recommend softening this language.
Violation Severity Levels
1. Do not agree with the zero tolerance for encroachments that do not result in a service interruption for R1 and R2.
2. Not notifying the Control Center should be a HIGH and not removing the imminent threat should be a SEVERE.
Response:
127
Consideration of Comments on 3rd Draft of FAC-003-2 Transmission
Vegetation Management — Part of Project 2007-07 Vegetation
Management
The Vegetation Management Standard Drafting Team and the Standards Committee’s Process
rd
Subcommittee thank all those who submitted comments on the 3 Draft of FAC-003-2 Transmission
Vegetation Management. The standard was posted for a 30-day public comment period from March 1,
2010 through March 31, 2010. Stakeholders were asked to provide feedback on the standard and its
proposed format through a special Electronic Comment Form. There were 13 questions posed, and most
of the questions were developed to collect stakeholder feedback on the proposed “results-based format”
for the standard. There were 55 sets of comments, including comments from more than 100 different
people from over 60 companies representing 8 of the 10 Industry Segments as shown in the table on the
following pages.
On January 14, 2010, the NERC Standards Committee endorsed the use of Project 2007-07 Vegetation
Management as the prototype for the proof-of-concept for using the results-based criteria for developing a
reliability standard. The results-based initiative is intended to focus the collective effort of NERC and
industry participants on improving the clarity and quality of NERC reliability standards by developing
performance, risk and competency-based requirements that accomplish a reliability objective through a
defense-in-depth strategy, while eliminating documentation-driven requirements that do not have an
impact on bulk power system reliability.
This report provides a copy of each of the questions that was posted for stakeholder comment with the
third draft of FAC-003-2, a summary indicating how the drafting team or the Process Subcommittee used
stakeholder comments submitted in response to that question, and the comments received. The
comments may be viewed in their original format at the following site:
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission, you
can contact the Vice President and Director of Standards, Gerry Adamski, at 609-452-8060 or at
1
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Index to Questions, Comments, and Responses
1.
In response to comments received regarding potential for “double jeopardy” and to provide
differentiation between transmission lines designated as having IROLs and Major WECC transfer
paths from those that are not, the SDT consolidated requirements R4 though R8 found in the August
2009 draft of FAC-003-2 into two requirements in the latest draft of FAC-003-2 (new requirements
R1 and R2). Do you agree? Please explain. ...................................................................................... 10
2.
The results-based reliability standard criteria focus on striving to achieve a portfolio of performancebased, risk-based, and competency-based mandatory reliability requirements that provide an
effective defense-in-depth strategy for achieving an adequate level of reliability of the bulk power
system in lieu of prescriptive requirements. Consequently, the SDT revised R1 and its subparts
found in the August 2009 draft of FAC-003-2 in favor of the text in the latest draft of FAC-003-2 (new
requirement R3). Do you agree? Please explain. .............................................................................. 19
3.
Do you agree with the overall layout of the proposed template? If not, please suggest an alternative
layout. ................................................................................................................................................. 28
4.
Do you agree with grouping the standard development timeline (previously called roadmap) with the
revision history, and the effective date(s) and putting this administrative information up front before
the Introduction Section? Please explain. .......................................................................................... 36
5.
Do you agree with grouping the Requirements and Measures together, in one Section now called
Requirements and Measures? Please explain. .................................................................................. 41
6.
Do you agree with grouping VRFs, Time Horizons and VSLs together, and putting them in a table
separate from the Requirements and Measures Section? Please explain. ....................................... 46
7.
Do you agree with the insertion of text boxes, where necessary, to help readers better understand
the basis of the Definitions and Requirements? Please explain. ....................................................... 51
8.
Do you agree with the addition of a Guideline and Technical Basis Section to place technical
materials and other related information that assists entities in understanding how to comply with the
standard but does not contain mandatory actions/activities? Please explain. ................................... 58
9.
Do you prefer putting URL links to reference materials in the Guideline and Technical Basis Section,
or do you prefer putting the additional technical/information materials in appendices, where needed,
to supplement the Guideline and Technical Basis Sections? Please explain. ................................... 65
10.
Do you agree with the addition of the Background Section to allow provision of background
information, and to elaborate on the reliability-related drivers for the standard/change? Please
explain. ............................................................................................................................................... 71
11.
Do you agree with the addition of an Administrative Procedure Section to place
administrative/procedural requirements that are contained in the existing standards but which do not
meet the results-based or risk-based criteria? Please explain. ......................................................... 77
12.
Is there any other information that should be included in the standard document? If so, please
explain why you feel that this information should be included. .......................................................... 83
13.
Do you have any other comment regarding the draft FAC-003-2 Transmission Vegetation
Management standard that have not been addressed above? If yes, please provide a reference to
the section, requirement, or subrequirement that you believe should be changed, added or deleted
and the rationale for your proposal..................................................................................................... 89
2
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Commenter
1.
Group
Guy Zito
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
Northeast Power Coordinating Council
Additional Member
10
X
Additional Organization
Region
Segment Selection
1. Alan Adamson
New York State Reliability Council
NPCC
10
2. Gregory Campoli
New York Independent System Operator
NPCC
2
3. Roger Champagne
Hydro-Quebec TransEnergie
NPCC
2
4. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
5. Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
6. Ben Eng
New York Power Authority
NPCC
4
7. Brian Evans-Mongeon
Utility Services
NPCC
8
8. Mike Garton
Dominion Resources Services, Inc.
NPCC
5
9. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC
5
10. David Kiguel
Hydro One Networks Inc.
NPCC
1
11. Michael R. Lombardi
Northeast Utilities
NPCC
1
12. Randy MacDonald
New Brunswick System Operator
NPCC
2
13. Greg Mason
Dynegy Generation
NPCC
5
14. Bruce Metruck
New York Power Authority
NPCC
6
15. Michael Schiavone
National Grid
NPCC
1
16. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
10
3
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
17. Robert Pellegrini
2.
Group
Organization
The United Illuminating Company
Jim Case
SERC OC Standards Review Group
Additional Member
Industry Segment
1
2
3
4
5
6
NPCC
X
Additional Organization
7
Region
Segment Selection
SERC
1, 3
2. Alvis lanton
Southern Illinois Power Cooperative
SERC
1, 3, 5
3. Melinda Montgomery
Entergy
SERC
1, 3
4. Ken Parker
Entegra
SERC
5
5. Larry Rodriquez
Entegra
SERC
5
6. Gwen Frazier
Gulf Power
SERC
1, 3, 5
7. Stephen Mizelle
Southern
SERC
1, 3, 5
8. Brad Young
E.ON.US
SERC
1, 3, 5
9. John Troha
SERC
SERC
10
Louis Slade
Dominion
Additional Member
X
Additional Organization
X
Region
X
X
Segment Selection
1. Jalal Babik
Electric Market Policy
SERC
6, 5
2. Mike Garton
Electric Market Policy
MRO
6, 5
3. John Loftis
NERC compliance
SERC
1, 3
4. Angela Park
NERC compliance
SERC
1, 3
5. Aaron Jonas
Forestry
SERC
1
4.
Group
Carol Gerou
MRO's NERC Standards Review Subcommittee
Additional Member
10
X
Ameren
Group
9
1
1. Gerald Beckerle
3.
8
X
Additional Organization
Region
Segment Selection
1. Chuck Lawrence
American Transmission Company
MRO
1
2. Tom Webb
Wisconsin Public Service Company
MRO
3, 4, 5, 6
3. Terry Bilke
Midwest ISO Inc.
MRO
2
4. Jodi Jenson
Western Area Power Administration
MRO
1, 6
5. Ken Goldsmith
Alliant Energy
MRO
4
6. Dave Rudolph
Basin Electric Power Cooperative
MRO
1, 3, 5, 6
7. Eric Ruskamp
Lincoln Electric System
MRO
1, 3, 5, 6
8. Joseph Knight
Great River Energy
MRO
1, 3, 5, 6
4
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
9. Joe DePoorter
Madison Gas & Electric
MRO
3, 4, 5, 6
10. Scott Nickels
Rochester Public Utilties
MRO
4
11. Terry Harbour
MidAmerican Energy Company
MRO
1, 3, 5, 6
5.
Group
Denise Koehn
Bonneville Power Administration
Additional Member
X
X
Additional Organization
Region
X
WECC
1
2. Don Swanson
BPA Transmission Line Maintenance
WECC
1
Joe Spencer (SERC staff)
and Jack Gardner (VMS
chair)
X
SERC Vegetation Management Sub-committee
Additional Member
Additional Organization
Region
1. Randy Gann
Alabama Power Company
SERC
2. Gerald Beckerle
Ameren Services Company
SERC
3. Jeffrey Hackman
Ameren Services Company
SERC
4. John Neagle
Associated Electric Cooperative, Inc.
SERC
5. Billy George
Duke Energy Carolinas
SERC
6. Ron Adams
Duke Energy Carolinas
SERC
7. Robert Trimble
E.ON U.S. Services Inc. for LG&E & KU
SERC
8. Jim Case
Entergy
SERC
9. Ralph Hale
Entergy
SERC
10. Marc Tunstall
Fayetteville Public Works Commission
SERC
11. Reggie Wallace
Fayetteville Public Works Commission
SERC
12. Terry Wilson
PowerSouth Energy Cooperative
SERC
13. Jack Gardner
Progress Energy Carolinas
SERC
14. John Wolfmeyer
SERC Reliability Corporation
SERC
15. Jerry Lindler
South Carolina Electric & Gas Company
SERC
16. Richard Dearman
Tennessee Valley Authority
SERC
7.
Group
Ben Li
Additional Member
10
Segment Selection
BPA Transmission Field Services
Group
9
X
1. Chuck Sheppard
6.
8
IRC Standards Review Committee
Additional Organization
Segment Selection
X
Region
Segment Selection
5
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
1. Bill Phillips
MISO
MRO
2
2. James Castle
NYISO
NPCC
2
3. Charles Yeung
SPP
SPP
2
4. Matt Goldberg
ISO-NE
NPCC
2
5. Mark Thompson
AESO
WECC
2
6. Patrick Brown
PJM
RFC
2
7. Steve Myers
ERCOT
ERCOT
2
8.
Group
Richard Kafka
Pepco Holdings, Inc. - Affiliates
Additional Member
X
Additional Organization
X
X
Region
RFC
1
2. Dave Paduda
Potojmac Electric Power Company
RFC
1
3. Steve Benn
Delmarva Power & Light
RFC
1
4. Olivia Watts
Atlantic City Electric
RFC
1
5. Steve Genua
Pepco Holdings, Inc
RFC
1
Sam Ciccone
FirstEnergy
Additional Member
X
Additional Organization
X
X
X
X
Region
Segment Selection
1. Rebecca Spach
FE
RFC
1
2. Katrina Schnobrich
FE
RFC
1
3. Dave Folk
FE
RFC
1, 3, 4, 5, 6
4. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
10.
Group
Carter B. Edge
Ad Hoc Group subteam formed to review draft
standard
Additional Member
X
Additional Organization
Region
1. Peter Heidrich
FRCC
FRCC
2. Pat Huntley
SERC
SERC
3. Roman Carter
NERC
NA - Not Applicable
4. Steve Ruekert
WECC
WECC
5. Chris Hajovsky
RRI Energy
NA - Not Applicable
11.
Group
Frank Gaffney
Florida Municipal Power Agency (FMPA) and Some
10
Segment Selection
Pepco Holdings, Inc
Group
9
X
1. Pat Byrne
9.
8
X
X
X
Segment Selection
X
X
6
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
Members
Additional Member
Additional Organization
Region
Segment Selection
1. Tim Byerle
New Smyrna Beach
FRCC
1, 3, 4
2. Jim Howard
Lakeland Electric
FRCC
1, 3, 5
3. Greg Woessner
Kissimmee Utilities Authority
FRCC
1, 3, 5
4. Lynne Mila
Clewiston
FRCC
1, 3, 4
5. Joe Stonecipher
Beaches Energy Services
FRCC
1, 3, 4
6. Cairo Venegas
Fort Pierce Utilities Authority
FRCC
1, 3, 4, 5
12.
Individual
Thomas Glock
Arizona Public Service Company
13.
Individual
Chip Turner
Tampa Electric Company
X
14.
Individual
Stephen Mizelle
Southen Company
X
15.
Individual
Silvia Parada Mitchell
TO/TOP
X
16.
Individual
John Buckley
Omaha Public Power District
X
17.
Individual
Howard Gugel
NERC Staff (12 staff members)
18.
Individual
Gary Cox
Tucson Electric Power Co.
X
19.
Individual
Edward Bedder
Orange and Rockland Utilities, Inc.
X
20.
Individual
Greg Lange
GCPD
21.
Individual
Christopher M. Crane
Westchester County Board of Legislators
22.
Individual
Robert Beadle
North Carolina EMC
23.
Individual
Mary Hetz
Ameren
X
24.
Individual
James W. Smith
ITC Holding
X
25.
Individual
Alan Gale
City of Tallahassee (TAL)
26.
Individual
Virginia Cook
JEA
X
27.
Individual
Weston Davis
Central Maine Power, Iberdrola USA
X
28.
Individual
Eric Senkowicz
FRCC Manager of Operations
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
7
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
29.
Individual
Samuel Stonerock
Southern California Edison Company
X
X
X
X
30.
Individual
Jon Kapitz
Xcel Energy
X
X
X
X
31.
Individual
Chris Scanlon
Exelon
X
X
X
X
32.
Individual
Jody Nelson
Ga Transmission Corp
X
33.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
X
X
34.
Individual
Greg Rowland
Duke Energy
X
X
X
X
35.
Individual
Laura Zotter
ERCOT ISO
Individual
Gerald T. Paulson
Western Area Power Administration - Upper Great
Plains Region
X
37.
Individual
Louis C. Guidry
Cleco
X
X
X
38.
Individual
Tom Hayes
East Kentucky Power Cooperative, Inc.
X
X
X
39.
Individual
Jack Gardner
Progress Energy Carolinas
X
X
X
40.
Individual
Kevin Howard
Western Area Power Administrtaion
X
41.
Individual
James Sharpe
South Carolina Electric and Gas
X
42.
Individual
George Czerniewski
Consolidated Edison Company of New York, Inc.
X
43.
Individual
Michael Pakeltis
CenterPoint Energy
X
44.
Individual
Darryl Curtis
Oncor Electric Delivery
X
45.
Individual
Thad Ness
American Electric Power (AEP)
X
46.
Individual
Dan Rochester
Independent Electricity System Operator
47.
Individual
Richard Dearman
Tennessee Valley Authority
X
Individual
Jim Fulton
BGE (on behalf of parent/affiliate companies: CEG,
CPSG, CECG, CNE & CENG)
X
49.
Individual
Edward Davis
Entergy Services
X
50.
Individual
Jason Shaver
American Transmission Company
X
36.
48.
7
8
9
X
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
8
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Commenter
Organization
51.
Individual
David Rocchio
Utility Risk Management Corporation
52.
Individual
Earl Burnside
PPL Electric Utilities Corporation (NCR00884)
53.
Individual
Jianmei Chai
Consumers Energy
54.
Individual
John Humphrey
Nebraska Public Power District
55.
Individual
Christopher M. Crane
Westchester County Board of Legislators
56.
Individual
Mike Gammon
KCPL
Industry Segment
1
X
2
3
5
X
X
6
7
8
9
X
X
X
4
X
X
9
10
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
1. In response to comments received regarding potential for “double jeopardy” and to provide differentiation between transmission
lines designated as having IROLs and Major WECC transfer paths from those that are not, the SDT consolidated requirements R4
though R8 found in the August 2009 draft of FAC-003-2 into two requirements in the latest draft of FAC-003-2 (new requirements R1
and R2). Do you agree? Please explain.
Summary Consideration: There were 43 comment forms indicating agreement with the proposed Requirement R1 and R2 and 8 comment
forms indicating disagreement.
The major comment issues covered:
•
The differentiation of IROL/WECC Major Transfer Path and other lines subject to this standard is defensible in the context of VRF. While
vegetation outages to lines covered in R2 are preventable and as such violations, the practical impact to the BES is no different than an
outage caused by other factors
•
WECC Transfer Path criteria should not be included in a national standard.
The VMSDT considerations for the major comment issues are:
•
The new R1 and R2 requirements have eliminated the double jeopardy problem. NERC’s Standards don’t allow two VRF’s for the same
requirement so the SDT created two requirements with different VRF’s.
•
The VM SDT believes that WECC criteria for Major Transfer Paths is not applicable in other RE’s and assumed this to be common
knowledge.
Some minor comment issues are:
•
Encroachment of the MVCD should not be a violation. A sustained outage should be the grounds for a violation.
•
MVCD should be defined.
•
Lines which cannot impact the BES, regardless of voltage, should be exempted from the standard
The VM SDT considerations for the minor issues are:
•
The team has concluded encroachment into the MVCD or ‘spark-over’ distance is a clear indication of improper or negligent vegetation
management and further that such encroachment creates an imminent threat condition.
•
MVCD is defined in both the Requirement and the Rationale.
FERC has directed the ERO to develop a methodology or test to designate “operationally significant” facilities in the March 18, 2010 Order 733.
The test is intended for application in PRC-023-1; however it can be extended for FAC-003-2 use.
Organization
Westchester County Board of
Legislators
Yes or No
Question 1 Comment
Do not have enough knowledge on this to provide response.
10
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
Nebraska Public Power District
No
Although it does provide some flexibility to the TO, it will be difficult to determine an encroachment into the
MVCD. It would easier to implement if R1 and R2 were only applicable when there was an outage on the
transmission system.
Dominion
No
Dominion does not agree with the inclusion of facilities that WECC designates as ‘major transfer paths’ in a
continent-wide standard. We suggest that, if the SDT wishes to include such reference and these facilities are
meant to be treated or synonymous with either IROL or SOL, that the SDT add a proposal to adopt and define
a suitable term for inclusion into the Glossary of Terms
Cleco
No
Encroachment into the MCVD should require the owner to take immediate corrective action to mitigate the
threat. Such an encroachment should not be reportable as a violation. Owners may be hesitant to
communicate possible vegetation threat conditions to the TOP or proper authority if they believe it will be
reported as a violation. We recommend the SDT consider modifying the measure for R1 and R2 to be
applicable only in the interruption of the transmission facility.
NERC Staff (12 staff members)
No
NERC Staff does not see a need to have two requirements (R1 and R2) which differentiation between
transmission lines designated as having IROLs and Major WECC transfer paths from those that are not with
two different Violation Risk Factors. The standard as drafted applies to all 200kv and above lines. The
Violation Risk Factor for all 200 kV and above lines should be “High”. R2 should be deleted and R1 should be
rewritten to be:R1. The Transmission Owner shall prevent vegetation from encroaching within the Minimum
Vegetation Clearance Distance (MVCD) of applicable Transmission line conductors to avoid a Sustained
Outage.
Xcel Energy
No
Requirements 1 & 2 are identical except for their applicability (R1 for IROL elements and elements in the
WECC Transfer Paths; R2 for all other lines =>200 KV). It is not readily apparent as to why there is a need to
distinguish between the two. Referencing the Table 2 "VRF" and "VSL" matrix indicates that R1 has a "High"
VRF and R2 has a "Medium" VRF. If this is the only reason, then consider adding, at a minimum, a
"Rationale" box explaining that reasoning.Also, the definition of MVCD needs to be a defined term or included
in R 1 & 2, e.g., “Minimum Vegetation Clearance Distance is the calculated minimum distanced stated in feet
(meters) to prevent spark-over between conductors and vegetation for various altitudes and operating
voltages as set forth in Table 2.” See comments to # 7 and # 13.
Arizona Public Service Company
No
This is a reliability standard for 230 kV and above and those lower voltages designated by the RRO. An
outage is an outage and the utility should be held accountable no matter if they are or are not designated.
SERC OC Standards Review
No
While we agree with the development of a second requirement to provide for the distinction between line
segments that are critical for reliability, in R1, a regional distinction should not be embedded in a national
11
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Group
Question 1 Comment
standard. We also strongly disagree that perfect compliance with R2, as stated, would improve reliability. If a
line is operated to avoid projected post contingent overloads, then the tripping thereof due to any cause has
no effect on BES reliability. A more prudent approach for the lines covered by R2 could be the requirement to
achieve 3 sigma or 4 sigma performance over a year’s time. Requirement 2, as stated, is not cost effective,
and may produce an unjust and unreasonable outcome to rate payers.While this draft clarifies (from version
FAC-003-1) that sustained outages are compliance violations and eliminates the “double jeopardy” which was
errantly introduced in the last draft of FAC-003-2 (when sustained outages were clearly defined as
compliance violations), we suggest that the team adjust R2 as previously mentioned. This draft provides a
mechanism to address the difference in outages that have impact to grid reliability from those that have an
impact only to local lines and associated customer reliability. The use of observed MVCD as a violation and in
the violation severity level matrix: o drives the right behaviors for improving reliability (by proactively
identifying and removing vegetation before it can become an imminent threat or cause an outage) o
eliminates the need to perform detail engineering/surveying/theoretical calculations before cutting vegetation,
o formalizes the informal interpretations that have resulted from FAC-003-1 enforcement and o allows the
vegetation field operations to focus on facts and remain practical rather than theoretical.
KCPL
No
American Transmission
Company
Yes
Bonneville Power Administration
Yes
Central Maine Power, Iberdrola
USA
Yes
City of Tallahassee (TAL)
Yes
Consumers Energy
Yes
The measures for R1 and R2 are zero tolerance for encroachments into the MVCD that did not result in a
“contact” with the transmission facility. Considering the substantial number of miles of transmission involved,
the complexities in anticipation of vegetation growth with numerous growth variables, vegetation management
limitations imposed by other regulations or requirements, and unexpected transmission events that require
substantial efforts regarding physical restoration, it is not reasonable or practical for the measures here to
include encroachments that do not result in an interruption of transmission service. Recommend the SDT
consider modifying the measures for R1 and R2 to be applicable only in the interruption of a transmission
facility.
12
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Duke Energy
Yes
Florida Municipal Power Agency
(FMPA) and Some Members
Yes
FRCC Manager of Operations
Yes
Ga Transmission Corp
Yes
GCPD
Yes
ITC Holding
Yes
Manitoba Hydro
Yes
Omaha Public Power District
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southen Company
Yes
TO/TOP
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Question 1 Comment
1. NSRS agrees with the revisions that the drafting team has made and agrees with the combining of four
requirements into two. NSRS prefers the MVCD methodology to the minimum clearance distance
13
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
methodology due to the fact that there is only one measurement to contend with versus two.2. If a company
has a line with a standing IROL could they be found in violation of both the requirements R1 and R2? If so,
the NSRS recommends combining R1 and R2.3. Please clarify the need for R1 and R2. Why were lines with
IROL separated out from lines without IROLs?
American Electric Power (AEP)
Yes
American Electric Power agrees with this change.
IRC Standards Review
Committee
Yes
Because real-time observation in Measurement 1 would require an actual measurement for comparison to
Table 2 to be defendable as a violation, the SRC suggests replacing observation with measurement.
The
SRC would suggest deleting the phrase "to avoid a sustained outage" as that phrase does not add any clarity
to either of the two requirements.
There do not seem to be any encroachments that the SDT will allow. If
there are encroachments that are considered allowable, who is responsible for making that consideration?
And what would be considered a "sustained" outage?Minimum Vegetation Clearance Distance (MVCD) is a
capitalized term used in Requirements 1, 2 and 7 but is not defined in the NERC Glossary of Terms Used in
Reliability Standards nor is a definition proposed in this standards action. Either a definition should be
proposed or the capitalization should be removed.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE agrees with the consolidation of R4 through R8 into two requirements in the FAC-003-2 draft.
Ameren
Yes
Creating two specific requirements removes the potential for double jeopardy.
Southern California Edison
Company
Yes
SCE agrees that the consolidation of Requirements R4-R* resolves the "double jeopardy" issue.
Tampa Electric Company
Yes
The change in the draft serves to consolidate, clarify and remove the “double jeopardy” as stated above. This
is an improvement in the standard.
CenterPoint Energy
Yes
The differentiation in the Violation Risk Factor for R1 versus R2 seems appropriate.
Consolidated Edison Company of
New York, Inc.
Yes
The elements that comprise IROLs must be clearly communicated to each Transmission Owner and must be
consistent across North America.
Orange and Rockland Utilities,
Inc.
Yes
The elements that comprise IROLs must be clearly communicated to each Transmission Owner and must be
consistent across North America.
14
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
Northeast Power Coordinating
Council
Yes
The most recent draft of the standard consolidated R4-R8 results in clearer requirements that meet the results
based criteria and addresses the “double jeopardy” issue. However, there is concern with the differentiation
of lines designated as having IROLs and Major WECC transfer paths from those that are not, as is proposed
in the Applicability section 4.2 and subsequently in requirements R1 and R2. As stated in the background
section: “This Standard focuses on transmission lines to prevent those vegetation related outages that could
lead to Cascading. It is not intended to prevent customer outages due to tree contact with lower voltage
distribution system lines. For example, localized customer service might be disrupted if vegetation were to
make contact with a 69kV transmission line supplying power to a 12kV distribution station. However, this
Standard is not written to address such isolated situations which have little impact on the overall Bulk Electric
System.” It must be recognized that in some systems, outages on lines operated at voltages greater than 69
kV, 200 kV for example, have localized impact only and do not lead to Cascading. Concurring with the
background, a line should be subject to this standard only if a vegetation related outage “could lead to
Cascading”, or could have a “significant impact” on the system. It does not depend on whether it is an IROL
line or not.A performance based methodology is used in NPCC to determine if an outage on a line can cause
a “significant impact” on the system. The lines identified by this methodology are not identified according to
their voltages, but rather by their impact on the system, regardless of the voltage.The introduction of “two”
subcategories of BES - an IROL and a non-IROL - appears to just differentiate between high VRF and
medium VRF. Furthermore, in the Applicability section, the IROL “variable” is mentioned only for lines
operated below 200 kV. What about lines operated at or above 200 kV lines? Why not have a single
Application item stating: overhead transmission lines operated at any voltage whose outages have a
significant impact on the system? A Table could define what is considered “significant”.There are standards
for vegetation management on the distribution system, and there are standards for higher voltage systems.
This standard should focus on lines with high impact on the system when a vegetation outage occurs.Utilities
will not let the vegetation encroach on other lines, but an importance will be given to vegetation management
on “critical” lines for the reliability of the whole system. On other lines, if an outage occurs, it will have
localized impact.A “Results-Based Reliability Standard” should first focus on the “critical” lines.If it is the intent
of NERC or the industry to ensure that a vegetation outage causes no more than a fixed level of load loss, it
should say so in a requirement.If the IROL “variable” is retained, identification of the transmission elements
that comprise IROLs must be officially communicated to the Transmission Owners. This must be done either
through a requirement in this, or another standard.
Progress Energy Carolinas
Yes
The previous version (FAC-003-1) was not developed with individual outages listed as a requirement or a
violation. The previous drafts of version 2 (FAC-003-2) have improved on FAC-003-1 by defining sustained
outages from within the Right-of-Way as violations. However, the recent drafts of FAC-003-2 also introduced
a potential for ‘double jeopardy’ when clarifying that sustained outages and MVCD encroachments were
(‘binary’) requirements/violations. This latest draft clarifies the expected performance into two concise
requirements that provide for differentiation in severity levels and risk factors, eliminating the unintended
15
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
‘double jeopardy’. The inclusion of the use of observed MVCD as a violation of R1/R2 and in the violation
severity level matrix drives the right behaviors for improving reliability (by proactively identifying and removing
vegetation before it can become an imminent threat or cause an outage) , eliminates the need to perform
detail engineering/surveying/theoretical calculations before cutting vegetation, formalizes the informal
interpretations that have resulted from FAC-003-1 and allows the vegetation field operations to focus on facts
(and remain practical rather than theoretical). Progress Energy believes that the R1 and R2 changes to this
draft are a significant improvement over FAC-003-1. This version draft: clarifies real-time MVCD and
sustained outages as a requirement; provides for differentiation between grid impacting outage events and
outage events to lines primarily associated with customer reliability; introduces a performance barrier/defense
that is fact based - eliminating the need to determine compliance through theoretical calculations that rely on
design assumptions (e.g., mechanical behavior of aged conductor), prior design criteria/code versions (i.e.,
code clearances in effect at time of design) and detail site measurements (e.g., “survey” quality
measurements and local environmental conditions at time of measurement/event).
JEA
Yes
The simplification and clarification improves the ability of Registered Entities to comply thereby enhancing
reliability.
Independent Electricity System
Operator
Yes
This change addresses the perceived “double jeopardy” risk.
Oncor Electric Delivery
Yes
This does not reduce the Standards effectiveness on the cascading issue or discount any outage on
applicable lines subject to this Standard in the electric Transmission system.
East Kentucky Power
Cooperative, Inc.
Yes
This draft adequately addresses the "double jepoardy" issue. The use of the Minimum Vegetation Clearance
Distances simplifies recommended maintenance process for field personnel and eliminates the need to
perform costly and time consuming engineering studies prior to trimming or removing vegetation.
SERC Vegetation Management
Sub-committee
Yes
This draft clarifies (from version FAC-003-1) that sustained outages are compliance violations and eliminates
the “double jeopardy” which was errantly introduced in the last draft of FAC-003-2 (when sustained outages
were clearly defined as compliance violations). This draft provides a mechanism to address the difference in
outages that have impact to grid reliability from those that have an impact only to local lines and associated
customer reliability. The use of observed MVCD as a violation and in the violation severity level matrix: o
drives the right behaviors for improving reliability (by proactively identifying and removing vegetation before it
can become an imminent threat or cause an outage) o eliminates the need to perform detail
engineering/surveying/theoretical calculations before cutting vegetation, o formalizes the informal
interpretations that have resulted from FAC-003-1 enforcement and o allows the vegetation field operations
to focus on facts and remain practical rather than theoretical.
16
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
Western Area Power
Administrtaion
Yes
This is a very efficient and logical consolidation of requirements.
Western Area Power
Administration - Upper Great
Plains Region
Yes
This is not a critical issue for the WAPA - UGPR.
Tennessee Valley Authority
Yes
This method effectively recognizes the difference in reliabilty risks among various lines based on their value to
the transmission grid.
Entergy Services
Yes
We agree that R1 and R2 are beneficial, but believe that they should be explained in greater detail for much
greater clarity to reflect their intent. Our understanding is that R1 applies to ALL IROL's and ALL Major
WECC Transfer Path lines, regardless of voltage, and R2 is centered around ALL lines operated at voltages
200 kV and above but are not classified as IROL/WECC lines. Our understanding of the term "applicable line
conductor" in R2 refers back to the facilities defined in Facilities - Section 4.2 and as modified by the phrase in
R2: "which are not elements of an IROL and are not a Major WECC transfer path, (operating within Rating
and Rated Electrical Operating Conditions)". However the appropriateness of our assumed reference back to
Section 4.2 and the modification contained in R2 is not clear. It also is not clear that the term "applicable line
conductor" in R2 is the same as "applicable line conductor" in R6. We suggest the term "applicable line
conductor" be specifically defined as that term is intended to be applied in R2, and the term "applicable line
conductor" be defined as that term is intended to be applied in R6.
FirstEnergy
Yes
We agree that the new R1 and R2 alleviate the potential double jeopardy issue as well as differentiate the
high and medium risk factor transmission lines. However, we offer the following comments and suggestions
for improvement:It is not clear how the Transmission Owner (TO) will determine which lines are associated
with IROLs. Upon reviewing standard FAC-014 Req. R5, which requires the communication of SOLs and
IROLs, the required communication of IROLs to the TO is not specified. There needs to be a tie between this
standard and the FAC-014 standard, which will require a revision to FAC-014. Unfortunately, this issue will
create a gap if FAC-014 is not revised and submitted to FERC in parallel with the submittal of FAC-003-2 to
FERC. This may require immediate action such as an urgent action SAR or other appropriate actions.If our
suggestion to revise FAC-014 is not possible at the present time, then we suggest an alternative course of
action to include language in R1 of FAC-003 to aid the TO in obtaining the information regarding lines
associated with IROLs. We propose adding the following sentence to R1: "The Transmission Owner can
request information regarding transmission lines associated with an IROL from its Planning Coordinator."
Ad Hoc Group subteam formed to
Yes
We understand the differentiation to be around the intent that those transmission lines designated as having
IROLs and Major WECC transfer paths pose a more significant threat to the reliability of the BES and that
17
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
review draft standard
Yes or No
Question 1 Comment
encroachment of the MVCD in these cases are relatively more significant. We suggest that this be clarified in
the rationale.
18
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
2. The results-based reliability standard criteria focus on striving to achieve a portfolio of performance-based, risk-based, and
competency-based mandatory reliability requirements that provide an effective defense-in-depth strategy for achieving an adequate
level of reliability of the bulk power system in lieu of prescriptive requirements. Consequently, the SDT revised R1 and its subparts
found in the August 2009 draft of FAC-003-2 in favor of the text in the latest draft of FAC-003-2 (new requirement R3). Do you agree?
Please explain.
Summary Consideration: There were 41 comment forms that indicated agreement with revising Requirement R1 found in the August 2009 draft
of FAC-003-2 in favor of the text in the latest draft (new requirement R3) and 12 forms indicating disagreement.
The major comment issues covered:
•
Several respondents felt R3 lacked clarity and needed more definition. However there were a large number of commenters who
specifically pointed out an appreciation for the requirement being less prescriptive and allowing the Transmission Owner flexibility in
developing its program.
•
Several respondents felt encroachment of the MVCD should not be a violation.
•
There were several concerns raised with citing the Rating and Rated Conditions to describe the conditions the Transmission Owner
should use to develop its clearances and avoid encroaching into the MVCD.
•
The term “Bulk Power System” should not be used in this Requirement.
The VM SDT considerations for the major comment issues are:
•
Due to the large number of respondents who expressed a positive opinion of eliminating prescriptive items in R3 using the Results-based
approach the SDT felt R3 is appropriate as written.
•
The team has concluded encroachment into the MVCD or ‘spark-over’ distance is a clear indication of improper or negligent vegetation
management and further that such encroachment creates an imminent threat condition.
•
The team has further described Rating and Rated Conditions in the Guideline and Technical Basis Section under Requirement R3.
•
This term “Bulk Power System” has been removed from every instance in the Standard.
Some minor comment issues are:
•
Make Standard dependant on R1 and R2 only. Remove all other requirements.
•
Add NESC clearance requirements to R3.
The VMS SDT considerations for the minor comment issues are:
•
One of the tenets of the Results-based framework is a set of building blocks which support each other. While R1 and R2 are the ultimate
test of reliability they are an insufficient number of building blocks for an Results-based Standard.
•
While adding NESC clearance requirements to R3 may clarify what is needed to develop the document, the SDT felt that Rating and
Rated Conditions adequately cover this.
19
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
Tampa Electric Company
No
A more in-depth technical review of this requirement is required. Our response is predicated upon the
following quote from the draft standard; “...considering all possible locations the conductor may occupy
assuming operation within Rating and Rated Electrical Operating Conditions.”
NERC Staff (12 staff members)
No
As written, R3 does not provide enough clarity as to what should be included in a documented transmission
vegetation management program. R3 should be expanded to include what should be included in the
transmission plan. Such as:R3. Each Transmission Owner shall have a documented transmission vegetation
management program that describes how it conducts work on its Active Transmission Line Rights of Way to
avoid Sustained Outages due to vegetation, considering all possible locations the conductor may occupy
assuming operation within Rating and Rated Electrical Operating Conditions. The transmission vegetation
management program shall:3.1 Specify the methodologies that the Transmission Owner uses to control
vegetation.[1] 3.2 Specify a Vegetation Inspection frequency of at least once per calendar year that takes
into account local[2] and environmental factors. 3.3 Require an annual work plan that identifies the
applicable lines to be maintained and associated work to be performed during the year. It shall be flexible to
adjust to changing conditions and to findings from Vegetation Inspections. Adjustments to the plan within the
year are permissible. The plan shall take into consideration permitting and scheduling requirements from
landowners or regulatory authorities. It shall support the objectives of the transmission vegetation
management program and utilize the methodologies outlined in the transmission vegetation management
program. 3.4 Require a process or procedure for response to imminent threats[3] of a vegetation-related
Sustained Outage. The process or procedure shall specify actions which shall include immediate
communication of the threat to the Transmission Operator or proper operating authority. The process or
procedure shall specify what conditions warrant a response.3.5 Specify an interim corrective action process
for use when the Transmission Owner is constrained from performing vegetation maintenance as planned.
3.6 Specify the maintenance approach used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that Table 1 clearances in Attachment 1 are never violated. The
maintenance approach shall consider the sag and sway of the conductor throughout its operating range under
rated conditions.[1] ANSI A300, Tree Care Operations - Tree, Shrub, and Other Woody Plant Maintenance Standard Practices, while not a requirement of this standard, is considered to be an industry best practice.[2]
Local factors include treatment cycle, extent and type of treatment, and their relationship to the normal growth
rate.[3] The term “imminent threat” refers to a vegetation condition which is placing the transmission line at a
significant risk of a Sustained Outage. Refer to Technical Reference for examples of imminent threat
procedures and conditions for implementation.
Consumers Energy
No
Consumers Energy strongly disagrees with the MVCD as presented in this version of the standard. These
distances do not provide an adequate safeguard to prevent outages since the conductor position relative to
the vegetation is sensitive to electric load and wind at any particular moment while vegetation height is not.
Measurements M1 and M2 require real-time observation of a violation of MVCD to be reportable. As
20
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
presented, vegetation growing beneath the conductor with a clearance of MVCD + 1 foot is not reportable.
However, this same conductor may sag due to load increase or move due to wind displacement within hours
of the real-time observation. If great enough, the sag or displacement may move the conductor in contact
with the vegetation resulting in an outage just hours after being deemed compliant.At a minimum the MVCD
should be designed to provide the Gallet clearance distance at maximum sag or wind displacement
(whichever is greater) at all times. No matter when the line is cleared of vegetation or inspected for
vegetative conditions, if the enhanced MVCD is being met an outage cannot occur until further vegetative
growth occurs. Furthermore, for line clearing operations, tree crews do not and cannot determine in the field
the maximum potential sag or wind displacement to know how much vegetation to clear. They require much
clearer instructions with a set amount of clearing distance to obtain at the time of work. This distance must
account for maximum sag, wind displacement and the Gallet distance at a minimum.
Cleco
No
Encroachment into the MCVD should require the owner to take immediate corrective action to mitigate the
threat. Such an encroachment should not be reportable as a violation. Owners may be hesitant to
communicate possible vegetation threat conditions to the TOP or proper authority if they believe it will be
reported as a violation. We recommend the SDT consider modifying the measure for R1 and R2 to be
applicable only in the interruption of the transmission facility.
GCPD
No
Grant believes that R1 and R2 should be the entire standard and the rest of the requirements should be in
guidelines and supplementary materials to assist in meeting the two results based requirements. We
understand that some risk-based and competency based requirements are necessary for some standards.
Not this one. No grow-in caused outages is the objective. Requiring a specific plan does not show
competency, it just shows you have a plan. Feels very much like the existing standards. "Show us your
Documentation".
Northeast Power Coordinating
Council
No
R3 specifies “...considering all possible locations the conductor may occupy assuming operation within Rating
and Rated Electrical Operating Conditions.” Although both “Rating” and “Rated Electrical Operating
Conditions” appear in the NERC Glossary, inspection of these definitions shows that they are very vague, and
“Rated Electrical Operating Conditions” uses the word “reasonably”, a term FERC has previously indicated as
being unacceptable. From a practical standpoint this seems to allow too much latitude to an entity to do the
least amount of trimming and not consider the extra sag and swing caused by some of the more extreme
operating conditions that “may” occur, such as loading to an STE or DAL limit during a higher velocity wind
than normal, coupled with a higher ambient temperature. An entity could potentially claim that vegetation was
trimmed to normal load levels, normal facility loading sag, and minimum velocity wind speed swings, and be
within the tolerance of the standard as we interpret it. The Drafting Team should clarify what the expectation
is with regard to line loading, sag, and swing due to wind speed and the types of operating conditions it
deems to be justified to create a more exact requirement.
21
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
Nebraska Public Power District
No
same concern as item 1.
Central Maine Power, Iberdrola
USA
No
The TVMP must include clearances bewteen trees and conductors at time of vegetation management
work.Suggest that the TVMP require the use of qualified personnel to manage this program.
Arizona Public Service Company
No
This standard lacks accountability and transparency. This is a reliability standard and the industry is to
prevent outages within the active ROW. It doesn’t matter if the vegetation grows-in, blows-in or falls into the
conductor these are all outages. One is no less of an outage than the other one. They should be treated
equally and the utility should be held accountable for lack of maintaining the transmission system.
FirstEnergy
No
We agree that the previous R1 was too prescriptive and are in favor of the new Requirement R3. However,
we do not agree with all the wording of R3 as well as the Rationale box for R3. 1. Requirement R3 - The
phrase "considering all possible locations the conductor may occupy assuming operation within Rating and
Rated Electrical Operating Conditions" is confusing. We like the wording from the previous (Draft 2) of FAC003-2 and suggest the following rewording of this phrase: "considering all possible locations the conductor
may occupy throughout its operating range under all rated conditions."2. Rationale box for Req. R3 - We
suggest removing the first sentence in the Rationale box for R3. The need to provide a basis on the intent and
competency of the TO in maintaining vegetation is not explicitly stated in the requirement. Also, we are not
sure what is meant by "competency". If it is referring to minimum required competencies for personnel
performing vegetation management, that is outside the scope of this standard.
Ameren
Yes
Bonneville Power Administration
Yes
City of Tallahassee (TAL)
Yes
Consolidated Edison Company of
New York, Inc.
Yes
Duke Energy
Yes
Entergy Services
Yes
Exelon
Yes
22
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
FRCC Manager of Operations
Yes
Ga Transmission Corp
Yes
Manitoba Hydro
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
Orange and Rockland Utilities,
Inc.
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Tennessee Valley Authority
Yes
TO/TOP
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Xcel Energy
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Question 2 Comment
1. NSRS agrees with the revisions to R3. With regard to operations within Ratings and Rated Conditions, are
operations after a contingency considered to be within Ratings and Rated Conditions?2. Could wording be
added to R3 to specify rated conditions include National Electric Safety Code conditions or assumptions?
23
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
Florida Municipal Power Agency
(FMPA) and Some Members
Yes
Although FMPA agrees with the intent of the Measures, FMPA is concerned that the measures M1 and M2
may not meet the purpose of the measures as stated in the latest draft version of the Standard Processes
Manual, which states that that a Measure “(p)rovides identification of the evidence or types of evidence
needed to demonstrate compliance with the associated requirement.” Instead, M1 and M2 provide examples
of evidence that would be used to determine non-compliance, not used to determine compliance.
American Electric Power (AEP)
Yes
American Electric Power agrees with this change.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE agrees with the R3 text in the latest draft of FAC-003-2.
Dominion
Yes
Dominion agrees and finds this approach superior to existing which sometimes appears to be more
administratively focused.
JEA
Yes
Given the basic performance required in R1 and R2 of this version, I agree that specifics about what is
included in the plan are not needed. Each entity should be encouraged to write their plan so that the
occasional human errors and failures that are inevitable still lead to compliance with the performance aspects
of this standard. The team should be sure that the measures do not require unfailing perfect execution of this
procedure so that entities are encouraged to minimize this document.
ITC Holding
Yes
ITC feels that this draft is an improvement by clarifying the action expected by this requirement (“competencybased” program specific methodology documentation) and separating other implementing (“risk based”)
actions from FAC-003-1 as new requirements within this draft version. ITC also agrees with results-based
reliability, a standard principle that is driven by relevant reliability requirements and measureable results
rather than prescriptive requirements driven by documentation.The term “bulk power system” should not be
used in the comment form or any other documentation associated with FAC-003-2.
Independent Electricity System
Operator
Yes
Old Requirement R1 has been distilled down to its essential elements with the removal of the detailed subrequirements that were previously included. This places the onus of developing an effective transmission
vegetation management program (TVMP) on the asset owners where it ought to be, since they have the
requisite expertise. Guidance is however provided in the Technical Reference document to assist
Transmission Owners in developing a TVMP that in their view works for them, and achieves the overall
objective of preventing those vegetation related outages that could lead to Cascading. By specifying the
“what” appropriately and leaving the “how” to the entity, the entity is now in the best position to determine the
most effective deployment of its resources for meeting the goals of the standard.
24
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
CenterPoint Energy
Yes
R3 focuses on its intended impact on Sustained Outages without being overly prescriptive.
Southern California Edison
Company
Yes
SCE prefers the results-based approach to crafting reliability standards because it provides utilities with the
necessary flexibility to develop internal criteria based on widely accepted best practices and industry
innovations.
Western Area Power
Administrtaion
Yes
The old Draft 2 version of R1 was developed to give the regulatory entities substantial and tangible
information from which to judge the adequacy of a TO's overall approach to program management. The old
Draft 2 version of R1 was purposely crafted in this detailed manner as an alternative to attempting to manage
the problematic CCZ concepts contained in Draft 1. Industry strongly rejected the CCZ management
concepts contained in Draft 1 in the first comment period. It appears that the current Draft 3 version of R3
has lost some of the content needed to fully substitute for the management of Draft 1 CCZ concepts. The
addition of an implementation requirement intended to measure the full execution and success of the overall
management approach identified by a TO in response to the new R3 may help to address this shortcoming.
As currently worded, the requirement to simply execute a flexible annual work under the new R7 in Draft 3
does appear extensive enough to fulfill this need.
Oncor Electric Delivery
Yes
The RBS defense-in-depth strategy for this Standard does provide an adequate level of reliability. The
Standards purpose statement refers to the electric Transmission system and corresponding applicable lines
not the BPS or BES as currently defined in the NERC glossary or being proposed (NOPR) RM09-18-000.
Removing prescriptive requirements allows utilities flexibility to document their program and perform their
vegetation management to achieve the goal of no outages that lead to cascading.
IRC Standards Review
Committee
Yes
The SRC agrees with the intent of R3, but questions the need for inspection postponements to be limited to
natural "disasters". A well-planned inspection may be delayed by a common lighting storm. While there is a
need to conduct the inspections and those inspections could be done anytime within the TO's own plans - the
SDT may want to modify the exception to be natural disasters or other conditions that are reported within 5
business days and agreed to as an excused condition by the Regional Reliability Organization.
Southen Company
Yes
The term “bulk power system” should not be used in the comment form or any other documentation
associated with FAC-003-2.
Progress Energy Carolinas
Yes
This separates implementing actions such as inspections, annual plans and imminent threat procedures from
TVMP methodology (which proves competency of the program).This draft is an improvement by clarifying the
action expected by this requirement (“competency-based” program specific methodology documentation) and
separating other implementing (“risk based”) actions from FAC-003-1 as new requirements within this draft
25
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
version.
SERC OC Standards Review
Group
Yes
This separates implementing actions such as vegetation inspections, performing annual work plans and
responding to imminent threats from the required documentation of the TVMP methodology (which proves
competency of the program).This draft is an improvement by clarifying the action expected by this
requirement (program specific methodology documentation requirement) and separating other implementing
actions from FAC-003-1 as new requirements in this draft version.
SERC Vegetation Management
Sub-committee
Yes
This separates implementing actions such as vegetation inspections, performing annual work plans and
responding to imminent threats from the required documentation of the TVMP methodology (which proves
competency of the program).This draft is an improvement by clarifying the action expected by this
requirement (program specific methodology documentation requirement) and separating other implementing
actions from FAC-003-1 as new requirements in this draft version.
Western Area Power
Administration - Upper Great
Plains Region
Yes
WAPA - UGPR agrees with a reliability based standard. In the plains states, we have fewer trees than many
utilities, so having prescriptive requirements that assume we have lines running through forested areas
seems to mandate an excessive amount of detail. We prefer to keep our program very simple -- perform
periodic inspections to identify vegetation problems and then direct applicable resources in to take care of the
problem. Our hope is that a results-based reliability standard will provide some flexibility for those utilities with
smaller scale vegetation encroachments.
Ad Hoc Group subteam formed to
review draft standard
Yes
While the new R3 is less prescriptive than the old R1, it appears to stray from criteria #4 for developing
results-based standards, as described in this comment form. It appears to require only the development of a
document. We understand that in some cases this cannot be avoided. We believe that this is one of those
cases where the reliability objective of building competency in considering all possible locations the conductor
may occupy and assuming operation within Rating and Rated Electrical Operating Conditions over-rides our
reluctance in requiring a registered entity to produce a document rather than a result. We suggest that in a
future revision to standard that this can be combined with R7 to create a comprehensive requirement that the
entity have a vegetation management program that demonstrates it is able to perform those actions
necessary to keep vegetation out of the MVCD.
KCPL
No
The measures for R1 and R2 are zero tolerance for encroachments into the MVCD that did not result in a
“contact” with the transmission facility. Considering the substantial number of miles of transmission involved,
the complexities in anticipation of vegetation growth with numerous growth variables, vegetation management
limitations imposed by other regulations or requirements, and unexpected transmission events that require
substantial efforts regarding physical restoration, it is not reasonable or practical for the measures here to
include encroachments that do not result in an interruption of transmission service. Recommend the SDT
26
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
consider modifying the measures for R1 and R2 to be applicable only in the interruption of a transmission
facility.
27
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
3. Do you agree with the overall layout of the proposed template? If not, please suggest an alternative layout.
Summary Consideration: Most comment forms (43 out of 53) indicated agreement with the overall layout of the proposed template. However,
some expressed concerns over individual parts of the template. The Vegetation Management SDT and the Standards Committee Process
Subcommittee (SCPS) appreciate the commenters’ comments and suggestions.
Some commenters do not agree with grouping Measures and Requirements together on the basis that Measures are compliance related elements
and hence should be grouped with the compliance elements. This suggestion was not adopted. The SCPS asked a specific question about
putting the requirements and measures together, and 50 of the 52 comment forms indicated support for this change.
Some commenters proposed that the Text Boxes are not needed if standards are written clearly; others expressed a concern that the material in
the text boxes may be taken as mandatory, or used by the auditors as guidelines for assessing compliance. Some suggested that it is necessary
to have a clear declaration on which parts/elements in the standards are mandatory. While the rationale for a requirement may be clear to most
people who are familiar with the topic addressed by the standard, as the industry grows and people unfamiliar with the industry try to understand
each requirement, documenting the rationale for each requirement is expected to be useful. The Text Boxes that provide the “rationale” for each
requirement and other explanatory information will remain in the body of the standard until it is balloted, but will be removed from the approved
version of the standard. Their content will be moved to the Guideline and Technical Basis Section.
The subcommittee will ask that NERC’s legal department to write a statement for addition to each standard to clarify which parts/elements of the
standard are mandatory and enforceable and which are provided only as information.
Some commenters raised a concern over the administrative elements. Some are unsure whether or not these elements are mandatory and asked
if they are mandatory, then why they are not included in the Requirement Section. These commenters suggested that if the administrative
reporting is not mandatory, does it belong in the standard, or should the Rules of Procedure Section 1600 be used to collect the data or document.
Some suggested that the Guideline and Technical Basis Section does not belong to a standard; others suggested that the material in the
Guideline and Technical Basis Section be moved to appendices. Some suggested that the materials in the text boxes can also be regarded as
providing the ‘technical basis’ and as such, can also be moved to appendices. Some commenters suggested moving the Guideline and Technical
Basis Section to immediately after the Requirements and Measures section for ease of reference and this suggestion was not adopted. The
compliance elements of the standard include evidence retention as well as other information that is mandatory, and the SCPS believes this should
appear before the elements of the standard that aren’t mandatory.
Some commenters do not support moving VRFs and Time Horizons away from the Requirements to be grouped together with the VSLs. They
expressed a desire to be able to see the VRF associated with each Requirement to know the violation impact. The SCPS will modify the format to
put the information in both places – adjacent to the requirement and in a separate table.
Some commenters expressed a concern with putting the Development Plan, Definitions, Effective Dates and Revision History at the front end
since the readers must screen through 4-5 pages before getting to the standard itself. Some commenters suggested that these housekeeping
items be moved to the end, other commenters suggested putting the Background Section before the Applicability Section in the Introduction. The
28
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
table with effective dates was removed as this will be challenging to keep up to date, however the other sections of the standard will remain where
proposed with the exception that the Definitions Section will be moved ahead of the Background Section.
Some commenters indicated that there appears to be some redundant verbiage in the Background Section and the Guideline and Technical Basis
Section. The SCPS will bring this to the attention of the VM SDT. These two sections were intended to have two distinctly different purposes – the
Background Section identifies “why” the standard exists, and the Guideline and Technical Basis Section provides information that may be useful to
entities in applying the standard.
Some commenters suggested using color code to differentiate between the information that is meant to be temporary and the information that is
expected to stay with the standards. This suggestion was not adopted.
Organization
Yes or No
Question 3 Comment
American Transmission
Company
No
a.) ATC believes that the “Guideline and Technical Basis” section does not belong within the NERC Standard.
ATC feels there are parts of this section that appear to obligate the TO with additional mandatory
requirements. (please refer to additional details in Question #8 below) b.) ATC believes the “Measures”
section immediately following the Requirement is helpful and placement is appropriate, however, the
introductory statement in R1 and R2 is poorly worded. For example, M1 currently states: “ Evidence of
violation of Requirement R1 is limited to:” ATC feels this is a negative approach and recommends that it be
stated in a positive manner such as”” Evidence of compliance to R1 would be to: o Not have any vegetationrelated Sustained Outages due to a grow-in.” c.) ATC would like to clarify whether the “Rational” boxes
remain within the final standard. It seems appropriate to have this information but that it would be better to
have this information appear in the “Guideline and Technical Basis” section.
GCPD
No
Don't need all the extra requirements beyond R2.
Florida Municipal Power Agency
(FMPA) and Some Members
No
FMPA appreciates the improvements and has additional suggestions. Please see responses to the remainder
of the questions, and below, for suggestions:The evidence retention should be grouped with the Measures for
ease of creating a records retention schedule for the standards and requirements.Do we really need a
“Compliance Monitoring and Enforcement Processes” section of the standards? Are there any standards that
don’t have all of these activities?
City of Tallahassee (TAL)
No
I would delete the Rationale in favor of keeping the Guideline and Technical Basis. The Guideline appears to
be more in-depth than the Rationale. This makes the Rationale unnecessary.
Northeast Power Coordinating
Council
No
NPCC participating members want to thank the drafting team for the hard work devoted to developing this
standard, and recognize the difficult issues of producing the first “results based” proof of concept standard
and offer the following, not as criticism, but as helpful suggestions for their consideration based on a cross
section of stakeholder reactions to the draft. 1) Measures are compliance related elements and should not
29
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
appear immediately after the requirements. The older template had the compliance elements grouped
together in a separate section, and we suggest this continues. In the past there have been instances of
RSAW (Reliability Standards Audit Worksheets) not clearly matching the standard’s requirements or
measures. We suggest that this initiative with a results based requirement consistently involve the
development of the associated RSAWs to ensure coordination, and also that the requirement results in a
performance based, competency, or risk based reliability criterion. 2) Effective dates have become a
complex issue. We suggest that rather than having an effective date table in the standard, this type of
information be restricted to the implementation plan and ultimately reside in a NERC relational database
which is currently under discussion/development. NPCC participating members suggest that the “Effective
Dates” section be replaced with “NERC BOT Adopted Date”. Due to their complexities, FERC and Provincial
approvals are something best left to implementation plans and databases. 3) “Rationale” boxes appearing in
the Requirements section are problematic. If a “Rationale” box is required to explain part of the requirement
then the requirement needs to be revised. For example, in R7 the requirement states that a TO shall execute
a flexible annual vegetation management plan. Flexible in this context could have many different
interpretations, yet in the “Rationale” box the use of the word flexible is clearly delineated to mean work may
be deferred if not an imminent threat. In general we believe these boxes add little value, and if the
requirement can’t be understood without the “Rationale” then the requirement needs to be worded
appropriately. Suggest these types of explanatory statements go into guidance documents, or supporting
technical documents, and do not appear in the “Requirements” sections. 4) Also, there seems to be some
confusion regarding the Administrative Procedure section. There seems to be requirements embedded within
it, e.g. “The Transmission Owner will submit a quarterly report to its Regional Entity, or the Regional Entity’s
designee, identifying all Sustained Outages of transmission lines determined by the Transmission Owner....”
Is this an enforceable aspect of the standard? If so, are there any other documents such as the NERC Rules
of Procedure “ROP” or compliance related documents such as the CMEP that have to be changed? NPCC
participating members recognize that this is a results based standard. Administrative requirements should be
removed from the standards, and dealt with elsewhere (such as the ROP). 5) The Guideline and Technical
Basis section contains valuable information, but this adds to the volume of the document. The Drafting Team
should consider moving this to a separate document. In viewing the standards as a whole, the FAC-003
standard is relatively straightforward when compared to the developing of other standards such as the TPL
standard. A similar approach, if applied to the TPL would result in a standard with potentially hundreds of
pages. If the type of work appearing in this section is envisioned for other more complex standards such as
TPL, the DT should consider separating out this section as a single supporting document. 6) Do FERC and
the Provincial governmental authorities approve just the requirements in the Standard, or the whole package?
FRCC Manager of Operations
No
See responses to #8, 10, 11 and 13.
IRC Standards Review
No
The proposal to move the time horizon and the VRF to a separate independent section is not useful. Take
for example R1 and R2 of the proposed standard. A careful read of the two requirements and measurements
30
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Committee
Question 3 Comment
would indicate that there is no difference between them and that it would be better to have one requirement
for all conductors. It is not until the reader gets to the compliance section does the VRF difference show up.
There is no savings to removing the previous format's parenthetical inclusion of time horizon and VRF at the
end of the requirement. The Independent Section can contain all of the proposed information but don't remove
it from the requirement. The format of the standard would not be an issue if NERC would develop a
standards database. Then, the database could be queried in any format the user desires.
ERCOT ISO
No
The Standard itself is several pages into the document. The VRFs/VSLs should be in the
Requirements/Measures Section. The Background, Rationale, Administrative Procedures are additional
information and should be located in an Appendix so it doesn’t clutter the Standard.
CenterPoint Energy
No
We suggest combining and moving the Rationale, Background, Guideline and Technical Basis, and Technical
Reference to a consolidated appendix because there is much duplication in the wording within each of these
sections, and independently they may be misinterpreted as being an integral part of the Requirements and
Measurements which they are not. The Requirements and Measurements should stand clearly on their own.
The appendix should contain examples of how to meet the requirements under various circumstances. The
appendix should be supplementary and optional to the Standard.It is also not clear if the Administrative
Procedure is a mandatory activity. It would be helpful if the intent of this section was stated within the
Standard.
NERC Staff (12 staff members)
No
We suggest using two colors for explanatory information - yellow for information that is temporary - such as
the information explaining the difference between the approved and proposed definitions of “Vegetation
Inspection” - and using blue for all boxes that are intended to remain in the approved standard.We feel that
the Standards Committee Process Subcommittee should pursue adding a statement from NERC’s legal
department indicating which parts of the standard are enforceable. In the meantime, we suggest using the
standard template in order to clearly define the enforceable parts of the standard. The section identified as
“Guideline and Technical Basis” is not really a guideline (typically a proposed process for completing work)
and is not really a “technical basis” (typically a summary of research or engineering judgment, etc. used to
explain the reasoning for something). The information in this section is explaining how the drafting team
expects compliance with the requirements to be measured. We suggest revising the heading to “Application
Guidelines.” This is the term that was originally proposed by the Results-based team and is the heading
identified in the proposed Standard Processes Manual.
Ad Hoc Group subteam formed to
review draft standard
Yes
Arizona Public Service Company
Yes
31
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Bonneville Power Administration
Yes
Central Maine Power, Iberdrola
USA
Yes
Cleco
Yes
Consumers Energy
Yes
Duke Energy
Yes
Entergy Services
Yes
Exelon
Yes
Independent Electricity System
Operator
Yes
Manitoba Hydro
Yes
Nebraska Public Power District
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Orange and Rockland Utilities,
Inc.
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Question 3 Comment
32
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
Southen Company
Yes
Southern California Edison
Company
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Xcel Energy
Yes
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE is supportive of the proposed template.
JEA
Yes
Coupling the measures and rationale with each requirement make the standard easier to follow and to
implement.
Dominion
Yes
Dominion agrees, but suggests that reference(s) to figure(s) and table(s) contain links that can take reader to
that section of the document. This is superior to having to scroll through document. If the reference(s) is
external to this standard document, links may be harder to manage but should at least reference a common
webpage(s) used by NERC for the posting of such documents.
ITC Holding
Yes
ITC feels that the overall layout of the standard (a) improves readability, (b) clarifies expectations, (c) reduces
confusion associated with referencing between pages, and (4) allows for background information and the SDT
rationale to accompany the standards but we would suggest locating Guideline and Technical Basis after
Requirements and Measures for better reference accessibility.
MRO's NERC Standards Review
Subcommittee
Yes
N/A
Tampa Electric Company
Yes
None
Western Area Power
Administration - Upper Great
Yes
None
33
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
FirstEnergy
Yes
Overall, we like the layout of the standard, especially the Effective Date table in the front of the standard, the
combination of Requirements and Measures, and the grouping of the VRF, Time Horizons, and VSL into one
table. However, we would like to see a clearer delineation between the mandatory requirements and the
guidance and rationale information. The standard should explicitly be clear as to what is mandatory and what
is not, which may even require moving the "Rationale" text boxes out of the Requirements and Measures
section. FE believes the information presented in the Rationale text boxes can be effectively covered in the
"Guidelines and Technical Basis".
Western Area Power
Administrtaion
Yes
The format could be enhanced by moving the Guidelines and Technical Basis section forward to be included
with the corresponding Requirement, Measure, and Rationale. This would be helpful because it is awkward
flipping back and forth between these two sections when trying to fully understand a requirement.
Pepco Holdings, Inc. - Affiliates
Yes
The general layout is quite effective. Still, it would be good to keep the VRFs and time horizons within the text
of the requirement.
Ga Transmission Corp
Yes
The layout is adequate but many things are needing further explanation such as the MVCD.
Progress Energy Carolinas
Yes
The overall layout improves readability, clarifies expectations, reduces confusion associated with referencing
between pages, and allows for background information and SDT rationale to accompany the standards
(reducing the need for interpretation).
SERC OC Standards Review
Group
Yes
The overall layout improves readability, clarifies expectations, reduces confusing references between pages,
and allows for background and rationale to accompany standards.
SERC Vegetation Management
Sub-committee
Yes
The overall layout improves readability, clarifies expectations, reduces confusing references between pages,
and allows for background and rationale to accompany standards.
East Kentucky Power
Cooperative, Inc.
Yes
The overall layout is greatly improved. This draft is easier to read and understand and clarifies the expected
actions required in the standard.
American Electric Power (AEP)
Yes
The overall template layout is acceptable
Tennessee Valley Authority
Yes
This aids the understanding of the standard.
Plains Region
34
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
Ameren
Yes
This draft is much more user friendly and easier to follow; appreciate the follow up information.
Consolidated Edison Company of
New York, Inc.
Yes
We do believe the overall layout is effective but the SDT should consider putting the Background Section
before the Applicability Section in the Introduction and also try to reduce any redundant verbiage in the
Background Section and the Guideline and Technical Basis Section. A twenty-one page Standard is too
lengthy and the supporting Technical Reference document properly addresses many of the issues mentioned
in the Guideline and Technical Basis Section.
KCPL
Yes
35
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
4. Do you agree with grouping the standard development timeline (previously called roadmap) with the revision history, and the
effective date(s) and putting this administrative information up front before the Introduction Section? Please explain.
Summary Consideration: A vast majority of the comment forms (48 out of 52 who responded to this question) indicated support for grouping the
Development Timeline, Revisions History and Effective Dates and putting them up front before the introduction Section.
Some commenters suggested moving this group of information to the end, other commenters suggested that the Definition Section be taken out of
the group and placed just before Introduction. The SCPS does not think that moving the grouped information to the end will result in much
improved readability. Readers can get to the beginning of a standard as quickly by scrolling or flipping through the pages.
The SCPS agrees with moving the Definition Section to just before the Introduction Section since Definitions are part of the balloted materials and
the team adopted this suggestion. Note that after the standard is balloted, the definitions, if approved, are moved out of the standard and into the
Glossary of Terms Used in Reliability Standards.
Some commenters suggested adding a table of contents. The SCPS will consider this in the next posting.
Organization
Yes or No
Question 4 Comment
IRC Standards Review
Committee
No
For this standard one must read through 7 pages before getting to the reason for the posting. The
administrative information should be relegated to the end of the posting not the beginning.Under exceptions in
the Effective Dates section of the standard, IROLs are referenced as only being created by the Planning
Coordinator. Because Reliability Coordinators must also establish IROLs per FAC-011 and FAC-014, we
suggest that reference to the Planning Coordinator should be redacted and IROLs should be discussed
regardless of whether the Planning Coordinator or Reliability Coordinator creates them.
Consolidated Edison Company of
New York, Inc.
No
The only issue we have with the administrative information being before the Introduction Section is with the
Definition of Terms Used in the Standard Section. We feel this should be part of the Introduction and not a
stand alone section.
Orange and Rockland Utilities,
Inc.
No
The only issue we have with the administrative information being before the Introduction Section is with the
Definition of Terms Used in the Standard Section. We feel this should be part of the Introduction and not a
stand alone section.
ERCOT ISO
No
This information should be located at the end so that it doesn’t distract from the main purpose of the
Standard. It is cumbersome to read through several pages before getting to the actual language of the
Standard.
Ad Hoc Group subteam formed to
Yes
36
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
review draft standard
American Transmission
Company
Yes
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
Central Maine Power, Iberdrola
USA
Yes
City of Tallahassee (TAL)
Yes
Cleco
Yes
Consumers Energy
Yes
Duke Energy
Yes
Exelon
Yes
GCPD
Yes
JEA
Yes
Manitoba Hydro
Yes
Nebraska Public Power District
Yes
NERC Staff (12 staff members)
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
37
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
Oncor Electric Delivery
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southen Company
Yes
Tennessee Valley Authority
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Western Area Power
Administrtaion
Yes
Ameren
Yes
Appreciate the ability to reference up front.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE agrees with the proposed grouping and placement of these items.
Dominion
Yes
Dominion agrees that the new format is superior to the old. However, we suggest a table of contents be
added to include at a minimum, sections for (1) Definitions of Terms Used in Standard (2) Effective dates, (3)
Introduction, (4) requirements and measures (5) Compliance (6) Time Horizons, VRF and VSLs (7)
Administrative (8+) guidelines, technical basis, tables or figures referenced in standard.
Entergy Services
Yes
Easy to follow.
Ga Transmission Corp
Yes
I do not see a problem with this change.
38
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
Xcel Energy
Yes
It is acceptable to do so, however it is not clear as to how the effective date portion will be incorporated in a
final version of the standard. Will there be some kind of cover page to at least indicate the standard or will it
just be a small title bar at the top? (i.e. - what does page 1 of the standard look like?)
ITC Holding
Yes
ITC agrees with locating the revision history and administrative information before the introduction. This
alignment improves clarity and readability by providing a single location for this information.
Florida Municipal Power Agency
(FMPA) and Some Members
Yes
Just a question, when the standard becomes effective, how will it be posted? FMPA assumes that this section
will move to the end of the standard instead of the front when approved.
CenterPoint Energy
Yes
No preference.
Tampa Electric Company
Yes
None
Northeast Power Coordinating
Council
Yes
NPCC participating members believe this is acceptable. However our previous response to question 3 above
still applies regarding the Effective Date section. It should be removed from the standard, and either appear
in an implementation plan, or more effectively in a NERC relational database.
Independent Electricity System
Operator
Yes
Since in this case the effective dates of all requirements are all the same, we believe the effective dates table
could be significantly condensed.
East Kentucky Power
Cooperative, Inc.
Yes
The format provides for better clarification and is easier to read and comprehend.
MRO's NERC Standards Review
Subcommittee
Yes
The NSRS likes the way the standards is now formatted and finds it more user friendly.
American Electric Power (AEP)
Yes
These changes make sense to American Electric Power.
SERC OC Standards Review
Group
Yes
This format adds clarity and improves readability.
SERC Vegetation Management
Sub-committee
Yes
This format adds clarity and improves readability.
39
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
Progress Energy Carolinas
Yes
This grouping improves clarity and readability by providing a single location for this information.
Western Area Power
Administration - Upper Great
Plains Region
Yes
WAPA - UGPR is neutral on location of these items.
Southern California Edison
Company
Yes
We agree that grouping the administrative information up front is logical and makes for a cleaner
presentation.
FirstEnergy
Yes
We agree with having a detailed table showing the effective dates of each requirement. However, we would
like to see NERC go back into the table and specify the dates of NERC and FERC effective dates once they
are known. Having the statement "1st day of the 1st quarter one year after applicable regulatory approval" in
the standard does not help the user of the standard when they are working towards compliance, and requires
them to go elsewhere to find when the approvals took place. All this information should be in the standard
when available and NERC staff should be afforded the latitude to do so even without needing to use its Errata
process. Placing the dates directly within the standard is more convenient for the end user.
KCPL
Yes
40
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
5. Do you agree with grouping the Requirements and Measures together, in one Section now called Requirements and Measures?
Please explain.
Summary Consideration: A vast majority of the comment forms (50 out of 52) indicated support for grouping the Requirements and Measures in
one Section.
Some commenters suggested moving the Measures back to the Compliance Section and adding a reference to each Measure stating which
Requirement it refers to. The SCPS does not think that moving the Measures back to the Compliance Section will result in any improvement in
readability. Keeping the Measures together with the Requirements provides readers with a clear and easy view of what evidence needs to be
provided to demonstrate compliance with the Requirements.
Organization
Yes or No
Xcel Energy
Question 5 Comment
We are indifferent as to the placement of the Measures, however it does appear to create awkward shaped
paragraphs when Requirements and Measures are place around Rationale boxes.
Northeast Power Coordinating
Council
No
Bonneville Power Administration
Yes
Cleco
Yes
Duke Energy
Yes
IRC Standards Review
Committee
Yes
Manitoba Hydro
Yes
Nebraska Public Power District
Yes
NERC Staff (12 staff members)
Yes
As commented earlier in question 3, this is a compliance related issue and should be in the Compliance
section. NPCC participating members believe clear concise requirements should be the focus, and inserting
measures immediately after the requirements adds little value. In addition, RE compliance staffs who use the
metrics find no value to moving it as well. This format would ease working with the document as a working
draft, but should not be in an adopted document. Consider moving Measures back to the compliance section,
and add a reference to a Measure’s wording stating which requirement the measure refers to. Only adding a
statement when the Requirement and Measure numbering don’t line up could be considered.
41
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
North Carolina EMC
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southen Company
Yes
Southern California Edison
Company
Yes
TO/TOP
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Western Area Power
Administrtaion
Yes
Central Maine Power, Iberdrola
USA
Yes
Adds clarity between requirements and measures .
Arizona Public Service Company
Yes
APS doesn’t agree with all of the requirements.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
Yes
BGE agrees it makes sense to group these two sections together.
42
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
CNE & CENG)
JEA
Yes
Coupling the measures and rationale with each requirement make the standard easier to follow and to
implement.
Dominion
Yes
Dominion finds this format improved over the existing as reader can more easily correlate the requirement
(process/procedures) to the measure (evidence).
Exelon
Yes
Exelon agrees this is a good practice that will help ensure Requirements and Measures are aligned
Florida Municipal Power Agency
(FMPA) and Some Members
Yes
FMPA agrees that grouping the Requirements and Measures together in one section is a great idea; however,
to realize even more benefit, we now have the opportunity to eliminate redundant wording, e.g., M3 can be
shortened to: “A documented transmission vegetation management program” and eliminate the rest of the
words that are redundant with R3.
Entergy Services
Yes
Great addition and improvement!! Much clearer and easier to follow.
City of Tallahassee (TAL)
Yes
However, if you keep the Rationale text boxes, keep the Measures in the same column as the requirement.
This will result in a more consistent “look and feel” to all the requirements (M3 for R3 is the example).
FRCC Manager of Operations
Yes
In addition the DT could also eliminate redundant wording in the standard requirement, e.g., M3 can be
shortened to: “A documented transmission vegetation management program” and eliminate the rest of the
words that are redundant with R3 or use words in the measure that refer back "to the requirement above".
ERCOT ISO
Yes
Including a specific measure with each requirement adds clarity; however, it isn’t clear whether each measure
is exclusive to the requirement that it follows. Is it possible that some requirements will have multiple
measures that are not listed immediately following the requirement?
ITC Holding
Yes
ITC agrees with Requirements and Measures grouped together
GCPD
Yes
Makes the standard template much easier to read and use.
Consumers Energy
Yes
Much easier to follow in this format.
Ameren
Yes
Much more user friendly to be able to see the requirement and the measurement together for clarification.
43
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
CenterPoint Energy
Yes
No preference.
MRO's NERC Standards Review
Subcommittee
Yes
NSRS prefers to have the requirements, measures, VRFs, VSLs and Time Horizons together instead of
referencing to another page or part of the standard.
American Transmission
Company
Yes
See ATC’s comment on “Measures” in Question #3 above.
Tennessee Valley Authority
Yes
This aides in understanding of the standard. Grouping the VSL and VRF for each requirement along with the
measurement could be beneficial too.
Ga Transmission Corp
Yes
This also is OK no problem with the layout.
Progress Energy Carolinas
Yes
This change also improves readability and improves understanding of the requirement.
SERC OC Standards Review
Group
Yes
This format adds clarity and improves readability.
SERC Vegetation Management
Sub-committee
Yes
This format adds clarity and improves readability.
East Kentucky Power
Cooperative, Inc.
Yes
This format provides for better readability and clarification.
Tampa Electric Company
Yes
This improves the clarity and understanding to the requirements.
Independent Electricity System
Operator
Yes
This is useful to avoid having to move back and forth between separate sections to find out what is needed to
show that a requirement is met. We do not have a strong preference for this re-grouping however.
Western Area Power
Administration - Upper Great
Plains Region
Yes
WAPA - UGPR believes this makes it easier to identify the requirement and what we need to provide to
demonstrate with are in compliance with the requirement.
FirstEnergy
Yes
We agree that grouping the Requirements and Measures together is convenient when utilizing the document
for compliance.
44
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
Consolidated Edison Company of
New York, Inc.
Yes
We agree with grouping the Requirements and Measures together since it does add another level of clarifying
description for our field forces who are ensuring compliance during vegetation management activities. The
Measures for R1 and R2 describe evidence of violation while the Measures for the remaining Requirements
R3 - R7 describe evidence of compliance. All Measures should be written consistently as either evidence of
compliance or evidence of violation.
Orange and Rockland Utilities,
Inc.
Yes
We agree with grouping the Requirements and Measures together since it does add another level of clarifying
description for our field forces who are ensuring compliance during vegetation management activities. The
Measures for R1 and R2 describe evidence of violation while the Measures for the remaining Requirements
R3 - R7 describe evidence of compliance. All Measures should be written consistently as either evidence of
compliance or evidence of violation.
Ad Hoc Group subteam formed to
review draft standard
Yes
We agree with the understanding that the specific requirements of the standard are the enforceable elements
of the standard. The rationale and measures add clarity to support a results-based requirement.
American Electric Power (AEP)
Yes
Yes, this is a more readable format.
KCPL
Yes
45
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
6. Do you agree with grouping VRFs, Time Horizons and VSLs together, and putting them in a table separate from the Requirements
and Measures Section? Please explain.
Summary Consideration: A vast majority of the comment forms (47 out of 54) indicated support with grouping VRFs, Time Horizons and VSLs
together.
Some commenters suggested moving the VERs and Time Horizon back to the Requirements.
Some commenters agree with grouping VRFs, VSLs and Time Horizons together, but expressed a desire to also see the VRFs and Time Horizons
in the Requirements as well. The SCPS adopted this suggestion in the next posting.
Some commenters suggested listing the applicable table rows with each requirement to consolidate all pertinent information with the requirement.
The SPCS believes that this will convolute the Requirements and Measures Section with little added value.
Some suggested adding the penalty matrix to facilitate discussions with property owners/agencies resisting maintenance activates. The SCPS
does not believe the penalty matrix is a standard element or technical reference material. This suggestion was not adopted.
Some commenters indicated that although a non-binding poll is taken of the VRFs and VSLs, it appears that the Time Horizons are part of the
standard that is still subject to stakeholder ballot. Commenters suggested that the SDT should explain how this will be made clear to balloters and
asked if there is an intent to modify the standards process to remove the time horizons from the portions of the standard that are subject to ballot.
In response to the above suggestions, the SCPS will retain the grouping as proposed, but will also put Time Horizons and VRFs adjacent to their
associated Requirements.
Organization
Yes or No
Question 6 Comment
Pepco Holdings, Inc. - Affiliates
No
Agree that the grouping of the subject material is appropriate, but it is not necessary to also remove the
VRFs and time horizons from the requirement.
JEA
No
I would prefer to have the VRF’s and time horizons together with the requirements and measures section. The
VSL’s separate is appropriate as that is not information needed while complying, but only after a failure.
Manitoba Hydro
No
If the VRF’s Time Horizons and VSLs were listed in with each requirement and measure section, it would
eliminate the need for cross referencing 2 sources of information.
Oncor Electric Delivery
No
It would be nice to see the associated VRF’s and Time Horizon with the requirements. No text, but
referenced.
ERCOT ISO
No
The associated VRFs/Time Horizons/VSLs should be identified alongside each Requirement so that all
relevant criteria for a given Requirement are organized together.
46
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
IRC Standards Review
Committee
No
While we agree that the grouping of the subject material is appropriate, it is not necessary to also remove the
VRFs and time horizons from the requirement.
Duke Energy
No
While we like grouping VRFs, Time Horizons and VSLs together in a table, we would also like to see each
VRF and Time Horizon listed with its requirement. It’s a small amount of information that we think adds value
in both places.
Ad Hoc Group subteam formed to
review draft standard
Yes
Ameren
Yes
American Transmission
Company
Yes
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
Central Maine Power, Iberdrola
USA
Yes
Cleco
Yes
Consolidated Edison Company of
New York, Inc.
Yes
Consumers Energy
Yes
Dominion
Yes
East Kentucky Power
Cooperative, Inc.
Yes
Exelon
Yes
47
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
FRCC Manager of Operations
Yes
Independent Electricity System
Operator
Yes
Nebraska Public Power District
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
Orange and Rockland Utilities,
Inc.
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southern California Edison
Company
Yes
TO/TOP
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Western Area Power
Administrtaion
Yes
Xcel Energy
Yes
MRO's NERC Standards Review
Yes
Question 6 Comment
Again it is good to have this information together in place of referencing some other page or part of the
48
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Subcommittee
Question 6 Comment
Standard.
Tennessee Valley Authority
Yes
Also please consider parsing out a copy of each VSL/VRF with in each individual requiremnt and measure
part of the standard as mentioned in question 5 above.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE supports grouping VRFs and VSLs together in a separate table.
Southen Company
Yes
Consider putting the appropriate line from the table with each requirement in the body of the standard in
addition to the table format. This does make the standard longer and does introduce some redundancy, but it
would make each requirement easier to read and interpret on a “standalone” basis.
City of Tallahassee (TAL)
Yes
I believe this makes it easier to follow the Requirements.
ITC Holding
Yes
ITC Agree's
Florida Municipal Power Agency
(FMPA) and Some Members
Yes
Much easier to find and understand
CenterPoint Energy
Yes
No preference.
Entergy Services
Yes
This grouping helps to clarify the manner in which the violations will be ranked.
Progress Energy Carolinas
Yes
This grouping improves the template used by previous versions by providing a single view of the impact and
risk that has been associated with each requirement. Progress Energy believes that this change would also
be improved if the applicable VRF/VSL/Time Horizon table rows were also listed with each requirement
(consolidating pertinent info with the requirement). Another improvement would be including the penalty
matrix (or including a URL link) to facilitate Transmission Owner discussions with property owners and other
governmental agencies.
SERC OC Standards Review
Group
Yes
This improves the template used by previous versions by providing a single view of the impact consideration
of each requirement. An improvement would be also listing the applicable table rows with each requirement
which consolidates all pertinent info with the requirement. Also, adding the penalty matrix would facilitate
discussions with property owners/agencies resisting maintenance activates.
49
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
SERC Vegetation Management
Sub-committee
Yes
This improves the template used by previous versions by providing a single view of the impact consideration
of each requirement. An improvement would be also listing the applicable table rows with each requirement
which consolidates all pertinent info with the requirement. Also, adding the penalty matrix would facilitate
discussions with property owners/agencies resisting maintenance activates.
GCPD
Yes
This is audit stuff that does need to stay together.
Northeast Power Coordinating
Council
Yes
This is consistent with FERC’s determination that these are compliance elements and not part of the standard
requirements. It will also assist with compliance determinations.
Western Area Power
Administration - Upper Great
Plains Region
Yes
WAPA - UGPR is neutral on location of these items.
FirstEnergy
Yes
We agree with grouping these items together. It may also be beneficial to include links directly in the table to
explanations of VRFs, Time Horizons, and VSLs so that someone unfamiliar with, for instance, what a "LongTerm Planning" horizon means, they could look it up.
NERC Staff (12 staff members)
Yes
We agree with the idea behind the grouping. However, according to the Reliability Standard Development
Procedure - Version 7, although a non-binding poll is taken of the VRFs and VSLs, it appears that the Time
Horizons are part of the standard that is still subject to stakeholder ballot. The SDT should explain how this
will be made clear to balloters. Is there intent to modify the standards process to remove the time horizons
from the portions of the standard that are subject to ballot? This issue needs to be addressed by the
Standards Committee Process Subcommittee.
Tampa Electric Company
Yes
With all of the VRFs, Time Horizons and VSLs grouped together it facilitates the overall understanding of
these factors as they relate to the standard.
Ga Transmission Corp
Yes
Yes this was a good change.
American Electric Power (AEP)
Yes
Yes; this format is more user-friendly.
KCPL
Yes
50
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
7. Do you agree with the insertion of text boxes, where necessary, to help readers better understand the basis of the Definitions and
Requirements? Please explain.
Summary Consideration: The majority of comment forms (43 out of 54) agree with the insertion of text boxes.
Some commenters disagree with the insertion as the material in the text boxes will be subject to FERC’s review and approval.
Other commenters raised a concern that the materials may become pseudo requirements; others are concerned that the material in the text boxes
is also mandatory, or may be used by auditors as guidelines to assess compliance.
Some believed that text boxes are not necessary given there is a Guideline and Technical Basis Section. Some suggested removing the text
boxes and moving the material to the Guideline and Technical Basis Section.
Some commenters indicated that some text boxes can be temporary (for example, those associated with a definition). More clarity is needed to
distinguish this type of text box in the drafting stage, with the expectation that they will be removed after a standard is approved and the definition
becomes effective (and removed from the standard).
The SCPS appreciates these comments and the commenters’ concerns. The SCPS agreed to post the text boxes with the working document but
move the text boxes into the Guideline and Technical Basis Section to support the standard until it is balloted, but will be removed from the
approved version of the standard before it is submitted for adoption and filing with regulatory and governmental authorities. Their content will be
moved to the Guideline and Technical Basis Section. The material in the Guideline and Technical Basis Section is intended to provide guidance
but is not intended to expand on any of the requirements and is not intended to include any mandatory performance. A legal statement will be
added to the standard to make this clear.
Organization
Yes or No
Question 7 Comment
Exelon
No
Additional clarifications should be included in appendices or reference documents. Including them with the
requirements and measures will cause confusion concerning what the compliance obligation is. This will
introduce uncertainty to the compliance monitoring process.
American Transmission
Company
No
Although the test boxes provide some addition help, ATC believes that these text boxes should appear in the
Guideline and Technical Basis section and that whole section should appear in a companion document to the
standard but not be included as part of the standard. Also, see ATC’s comment on Rational in Question #3
above.ATC believes that guidance information should not be reviewed and approved by FERC and the
inclusion of such information within the standard opens this language up to FERC’s oversight and approval.
Northeast Power Coordinating
Council
No
As stated in question 3 above, NPCC participating members believe crisp, clear results based requirements
require no further explanation. Requirements must be written so they are clearly understood. Text boxes
clutter up the standard. Questions could arise if these add “pseudo” requirements to the standards, and there
is any inconsistency in what is stated about requirements. NPCC strongly suggests their removal in favor of
51
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
clear, measurable, and high quality results based requirements.
City of Tallahassee (TAL)
No
I would delete the Rationale in favor of keeping the Guideline and Technical Basis. The Guideline appears to
be more in-depth than the Rationale. This makes the Rationale redundant and unnecessary.
CenterPoint Energy
No
It is not clear how the information in the text boxes will be used to determine compliance with the
Requirements and Measures. It appears that in the Definition of Terms Used in Standard section that the text
boxes add to the definitions or are footnotes to historical information. The Definitions should stand on their
own and be robust enough to ensure they are helpful in determining compliance with the Requirements and
Measures. In the Requirements and Measures section, the text boxes appear to contain partial information
from the Guideline and Technical Basis, and Technical Reference. In all cases the information is not helpful
and provides incomplete information. The text boxes should be deleted and pertinent information to
compliance should be incorporated into the Definitions, Requirements, and Measures. Any explanatory text
or examples should be moved to an appendix as supplementary and optional to the Standard.
ERCOT ISO
No
It is not clear whether the information in the text boxes is “For Information Only.” While the additional
information may be helpful, it appears to add sub-requirements within the Standard. This information could
be included under a “Rationale” section in an Appendix. However, if the information clouds the purpose of the
Requirements or dictates how to comply, then it should be eliminated completely.
Consumers Energy
No
Not necessary given the “Guidelines and Technical Basis”.
Nebraska Public Power District
No
Text boxes and other supporting information are a benefit to the reader as a clarification guide, but should be
placed in something other than the Standard.
IRC Standards Review
Committee
No
The concept of text boxes needs further discussion. The idea of using text boxes for clarity and explanation is
valuable, but is the material in the text box mandatory? If it includes mandatory material than it is not a good
idea - all mandatory requirements must be in the requirement. If the text boxes are retained to explain how a
phrase is being used (e.g. to make clear what compound actions apply to what compound time frames), then
yes, this approach can be invaluable.
Cleco
No
The inclusion of the text implies additional requirements. Keep quidance to a separate paper.
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
52
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Consolidated Edison Company of
New York, Inc.
Yes
Duke Energy
Yes
FRCC Manager of Operations
Yes
Manitoba Hydro
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Orange and Rockland Utilities,
Inc.
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
Southen Company
Yes
Tennessee Valley Authority
Yes
TO/TOP
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Question 7 Comment
1. We agree. The rationale boxes will cut down on interpretations. 2. Are the rationale boxes part of the
approved standards for which registered entities will be audited. Are the rationale boxes federal law?3. Under
R3, a reference to the National Electric Safety Code in the rationale box would be helpful. (The goal is to
53
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
verify that utilities will not be held in violation of this standard when operating beyond the NESC conditions.)
North Carolina EMC
Yes
Additional background in the test boxes is very helpful.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE agrees this would help clarify the basis of the Definitions & Requirements.
Dominion
Yes
Dominion agrees, but suggests that reference to figure(s) and table(s) contain links that can take reader to
that section of the document. This is superior to having to scroll through document. If the reference(s) is
external to this standard document, links may be harder to manage but should at least reference a common
webpage(s) used by NERC for the posting of such documents.
Xcel Energy
Yes
However, the boxes should be adding clarity, not "defining' terms or stipulating further requirements/criteria
that must be met. See MVCD in R1 & R2 and the incorporated Table 2, and comments to #1 & #13 in this
form. The standard should be able to convey the requirements without the text boxes or, if the text boxes are
used, the purpose and legal import of such boxes should be clarified. Further, it should be clarififed that for
text boxes that provide examples (e.g., the boxes on page 2 in the definitions section), such boxes should
clearly state that the examples are in no way limitations.
Ga Transmission Corp
Yes
I do like the text boxes.
ITC Holding
Yes
ITC agrees, but would like to suggest that the text boxes include additional pertinent information from the
Technical Reference that would be helpful as reliability talking points to the public. Example: (R3): The
following is a sample description of one combination of strategies which may be utilized by a Transmission
Owner. A Transmission Owner’s basic maintenance approach could be to remove all incompatible vegetation
from the right of way if it has the right to do so and has no constraints
Ameren
Yes
It's helpful to understand the SDT's logic for requirements, clarification is always appreciated.
GCPD
Yes
May help in cutting down the volume of SAR interpretation requests.
Central Maine Power, Iberdrola
USA
Yes
R3 - this may be a good place to describe clearances at time of vegetation management work
Florida Municipal Power Agency
Yes
The clarification is important and will reduce the number of requests for interpretation if interpretation is
already provided to some extent. Just a caution about how the text boxes will be used in the audit process,
54
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
(FMPA) and Some Members
Question 7 Comment
clarification concerning their use during compliance monitoring would be great.
NERC Staff (12 staff members)
Yes
The explanatory information posted with the proposed definitions, like the definitions, is only relevant to this
standard, and some of the information is only relevant to the point where the definition becomes enforceable.
What is the expectation for what will happen to this information in the future? We suggest that the text boxes
associated with requirements include a reference to that requirement. (Change “Rationale” to “Rationale for
R1”)
Western Area Power
Administrtaion
Yes
The format could be enhanced by moving the "Guidelines and Technical Basis" section forward to be included
with the corresponding Requirement, Measure, and Rationale. Perhaps the "Guidelines and Technical Basis"
could also be combined with the corresponding "Rationale" text box. This would be helpful because it is
awkward flipping back and forth between these two sections when trying to fully understand a requirement.
SERC OC Standards Review
Group
Yes
This format adds clarity and improves readability.
SERC Vegetation Management
Sub-committee
Yes
This format adds clarity and improves readability.
East Kentucky Power
Cooperative, Inc.
Yes
This format is simpler, easier to read, understand and implement.
Progress Energy Carolinas
Yes
This format provides clarity and improves readability. Progress Energy believes that having SDT basis
information for a requirement in the standard will reduce the need for interpretation and improve the
interpretation process for a requirement, if necessary.
Tampa Electric Company
Yes
This improves the clarity and understanding to the requirements.
American Electric Power (AEP)
Yes
This is a good change.
JEA
Yes
This is extremely helpful in understanding the intent of the requirement
Western Area Power
Administration - Upper Great
Plains Region
Yes
WAPA - UGPR believes that the expanations within the text boxes provided additional useful information.
55
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
Entergy Services
Yes
We agree that text boxes being used for additional clarity is a benefit if used in a correct and clear manner. It
needs to be specifically stated in the document that the text boxes are to be used for reference only, entities
will not be required to specifically follow the language in the Rationale box, and that each utility should specify
their own process for addressing each Requirement. For example....the Rationale box for R4 states that
"Verified knowledge includes observations by journeyman lineman, utility arborist, or other qualified
personnel.......". Our process will specify exactly who that qualified personnel is (Transmission Specialist or
another qualified Entergy Employee in the Transmission Vegetation Group, for example). We will specify this
in our internal processes.
FirstEnergy
Yes
We agree that text boxes can be useful for requirements and definitions. However, the SDT may want to
consider eliminating the text boxes since this information is already provided in the Guidance and Technical
Basis section. Also, we have the following additional comments:General:1. With respect for the rationale text
boxes for definitions, it is not clear if these boxes will be retained once the definitions are moved out of the
standard and added to the NERC Glossary.2. The rationale text boxes can be beneficial for the
requirements, but some of the text boxes in this current draft of FAC-003-2 seem to include prescriptiveness
that is not found in the requirement. An example is in the text box for Req. R4, which implies timeliness of
notification of an imminent threat with the use of the word "rapid". In the case of R4, the requirement should
state that notification be carried out immediately (see our suggested rewording of R4 in Question 13). 3.
Although these text boxes are not enforceable for compliance, we are not convinced that an auditor will view
this as simply guidance.Specific:1. Definition for Active Transmission Line ROW - Example 3 of Inactive
ROW - Consider removing this example; situations where vegetation is left unmanaged on portions of the
ROW where double-circuit structures exist with only one circuit strung with conductors poses an unnecessary
increased risk for vegetation related outages. 2. Rationale box for Req. R3 - See our comments in Question
23. Rationale box for Req. R4 should be revised to state: "To ensure rapid notification of the responsible
control center when an occurrence of an imminent threat condition is verified. Evidence of verified knowledge
includes observations by journeyperson, lineperson, utility arborist, or other qualified personnel, or a report
verified by these personnel. This notification allows the responsible control center to take the appropriate
action until the threat is relieved. Appropriate actions may include a temporary reduction in the line loading or
switching the line out of service."4. Rationale box for Req. R5 - (1) The last statement of this box seems
incomplete. It should be revised to state: "This requirement is not intended to address situations where the
transmission line is not at immediate risk and the work event can be rescheduled or re-planned using an
alternate work methodology."; and (2) We suggest revising the first statement to "Legal actions filed by
property owners, easement restrictions and other events...."
Southern California Edison
Company
Yes
We agree that the insertion of text boxes aids readers in understanding the basis for the Definitions and
Requirements.
56
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
Independent Electricity System
Operator
Yes
We agree that the side-bars give useful contextual information that is not part of standard. This is good and
avoids the reader’s attention being completely redirected to a reference document when seeking clarification
of the intent of a requirement. We believe however that these text boxes should be used sparingly and the
content should also be brief to minimize possible distractions to the reader.It should also be made clear in the
standard that these text boxes are not intended to impose additional requirements and in the event of any
perceived conflict, the text of the requirement will take precedence.
South Carolina Electric and Gas
Yes
We agree, however we would like clarification on whether entities can be held accountable for rationale
portions of the standard as they are for interpretations that are added to a standard.
Ad Hoc Group subteam formed to
review draft standard
Yes
We understand this question to refer to the “rationale” text boxes in this standard. Additional information such
as this is useful to the entity in explaining and clarifying the understanding of the drafting team in articulating
the requirement and thus supports a fuller understanding of the entity in achieving compliance with the
requirement.
KCPL
No
I like information that helps to “guide” and “provide guidance”, however, we already having trouble with
information from FAQ’s, White Papers, and other guiding documents creeping into the requirements by
auditing teams. The inclusion of “guiding information” in the text of the Standard itself may promote adding to
requirements. Although helpful, I recommend removing this text from within the body of the Standard.
57
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
8. Do you agree with the addition of a Guideline and Technical Basis Section to place technical materials and other related information that
assists entities in understanding how to comply with the standard but does not contain mandatory actions/activities? Please explain.
Summary Consideration: Most of the comment forms (38 out of 54) indicated agreement with the addition of the Guideline and Technical Basis
Section.
Some commenters expressed a concern over how the materials contained in this Section may be used in compliance monitoring and
enforcement.
Some commenters suggested that it should be expressly stated that this section is for information purposes only and is not part of the Standard
Requirements. They further suggested compiling all of the “Information Only” materials into an Appendix as a preferred alternative. Others
suggested that guideline materials be moved into a separate document.
Some commenters suggested that while this Section contains useful materials, NERC should consider developing a separate set of Guideline
documents to afford the industry a knowledge base that is not directly sanctionable for non-compliance.
Some commenters expressed a concern that being located within the standard, the Guideline Section will imply additional requirements for
mandatory compliance, or get used by auditors as compliance issues.
The SCPS assesses that the industry likes the idea of having technical guidelines for standards. Guideline materials, whether they are put in a
separate document or included in a standard, can be used by anyone to assess compliance with standards. Putting them outside of the standard
does not eliminate this possibility.
The material in the Guideline and Technical Basis Section is intended to provide guidance but is not intended to expand on any of the
requirements and is not intended to include any mandatory performance. A legal statement will be added to the standard to make this clear. The
SCPS believes that as long as it is made clear that only the requirements and provision of evidence are mandatory, any supporting materials can
be provided in a standard to aid readers better understand the standard without binding them to complying with the supporting materials. The
intent of the description of the elements of a standard in the proposed Standard Processes Manual is to make it clear that there is a distinction
between the enforceable sections of the standard and the compliance and supporting information sections of the standard.
Organization
Florida Municipal Power Agency
(FMPA) and Some Members
Yes or No
Question 8 Comment
No
Although FMPA agrees that a Guideline and Technical Basis document is important, FMPA has concerns
about how this section might be used in compliance monitoring and enforcement. For instance, R4 has a time
requirement somewhat embedded in the Guideline and Technical Basis that is not in the requirement in the
standard: “The imminent threat process should be implemented in terms of minutes or hours as opposed to a
longer time frame for interim corrective action plans”. How many minutes or hours? This adds ambiguity to the
standard. If a time limit is desired, it should be in the requirement. There are other examples of items that
could be interpreted as requirements in the Guidelines. It should be made clear what the purpose of the
Guidelines is in compliance monitoring and enforcement. FMPA suggests publishing two documents in the
same fashion that the Functional Model has two documents, one for the standards (e.g., the requirements),
and another for technical guidance to the standards (e.g., the Guideline and Technical Basis section) to
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
parallel the structure of the Functional Model and Functional Model Technical Document, which will help
make the distinction between CMEP and guidance more distinct.
American Transmission
Company
No
ATC disagrees with the above statement that it only assists in understanding how to comply. ATC believes
that parts of this section are written so they could be interpreted to contain mandatory actions/ activities. To
demonstrate, see example on pg.15, R4, 2nd paragraph states...Two key elements of an acceptable
imminent threat procedure are outlined below:..........) It should not be more than a preferred method for
implementation or supporting how the TO can meet the standard. NERC needs to clarify how this section
was intended to be used. (This as written could become part of a Compliance Audit process)Also, refer to
ATC’s comment on this section in Question #3 above.
Bonneville Power Administration
No
Consider referencing ANSI A300 part 7 as best management practices for R3. It is currently referenced in the
White Paper, and would lend more credibility to the standard if it was inserted in the text box for R3.
ERCOT ISO
No
For the same reasons stated in the comments to Question 7, it should be expressly stated that this section is
for information purposes only and is not part of the Standard Requirements. Compiling all of the “Information
Only” materials into an Appendix would be the preferred method of organization.
Northeast Power Coordinating
Council
No
NPCC participating members do not believe that publishing more information as part of the standard is
appropriate. For the same reasons as stated in the preceding response related to “Text Boxes” in question 7,
any inconsistency may result in a conflict with a requirement. The information in the Guideline and Technical
Basis section is valuable, however, and should be available to the industry in the form of guidelines. NPCC
participating members suggest that NERC assemble a comprehensive set of “Guideline” documents into one
bookmarked pdf publication to be updated as standards change. This will afford the industry a knowledge
base that is not directly sanctionable for non-compliance, but a set of industry best practices, background,
and reference for the standards development activities. Also, concern exists that FERC and Provincial
governmental authorities will have jurisdiction over “Guidelines”, and when the standard is approved it will
become a mandatory “rule”.
Nebraska Public Power District
No
Same as item 7.
CenterPoint Energy
No
See answer to Q3.
GCPD
No
Should be separate documents. If located with the standard it will get used by the auditors as compliance
issues. NO matter how much text you provide to the contrary it will become part of the standard over time.
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
Consolidated Edison Company of
New York, Inc.
No
Since the SDT has developed a complete Technical Reference Document for this Standard, there seems to
be redundancy with the Guideline and Technical Basis Section. This Standard has become too lengthy with
all of the additional details and information that has been added. We prefer to have a shorter Standard and a
more detailed stand alone supporting reference document.
Orange and Rockland Utilities,
Inc.
No
Since the SDT has developed a complete Technical Reference Document for this Standard, there seems to
be redundancy with the Guideline and Technical Basis Section. This Standard has become too lengthy with
all of the additional details and information that has been added. We prefer to have a shorter Standard and a
more detailed stand alone supporting reference document.
Cleco
No
The inclusion of the text implies additional requirements. Keep quidance to a separate paper.
IRC Standards Review
Committee
No
This change also requires some additional explanation. What level of importance will be given to such
materials? If an SDT inserted a Best Practices document, does that allow auditors to refer to that document
for purposes of holding an entity non-compliant?
Are these materials there to help entities who do not
know how to comply? If these materials are self-help guides, then it would be better to include them as URL
references that are stored in the NERC library. That way there can be not confusion about whether the
material is there as a self-help guide, or as a reference for auditors.
FRCC Manager of Operations
No
We agree that this is valuable information and important to convey with the standard. This should be a
separate companion document balloted, approved and posted with the standard but not be a part of the
standard.
TO/TOP
No
We agree that this is valuable information and important to convey with the standard. This should be a
separate companion document balloted, approved and posted with the standard but not as part of the
standard.
SERC OC Standards Review
Group
No
We recommend that the text “grid reliability” be substituted for “Bulk Electric System” on page 6 of the
draft.The inclusion of non-mandatory guidelines in a standard that will ultimately be approved by FERC gives
undue credence to “guidelines” that will lead undoubtedly to mis-application by future compliance auditors.
We suggest separation of this information from the mandatory reliability standard that will be filed at FERC. It
could be held in a repository on the NERC website.
Arizona Public Service Company
Yes
Central Maine Power, Iberdrola
Yes
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
USA
Consumers Energy
Yes
Duke Energy
Yes
Exelon
Yes
Manitoba Hydro
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Tennessee Valley Authority
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Tampa Electric Company
Yes
Aids in improved understanding of FAC-003-2.
FirstEnergy
Yes
Although we agree that guidelines are good to have and agree that having them in the body of the standards
is convenient, we question how this section will be viewed from a compliance standpoint. We understand this
section is not intended to be mandatory, but does that mean that regulatory authorities will only approve the
other sections of the standard and not this section? Also, it should be clear and explicitly stated in the lead-in
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
to this section that this is guidance which is not mandatory and enforceable. Additionally, terms such as
"shall", "should", and "require" should not be used in the guidance section because the information presented
in this section could be construed as mandatory by an auditor. An example of this is in the guidance
information for Requirement R7 which states "Documentation is required when the annual work plan is
adjusted...". This mandatory-type language should not be included in the Guidelines section.
MRO's NERC Standards Review
Subcommittee
Yes
Another good addition to the standard and will help clarify parts of the standard without referring to another
document or set of guidelines.
Southern California Edison
Company
Yes
Assuming that the "Guideline and Technical Basis Section" will be retained and revised in future revisions to
the standard, such information should prove very useful.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE agrees with the addition of a Guidance & Technical Basis section.
JEA
Yes
Having the information in the same document makes the information more accessible to the entity attempting
to comply with the standard.
Ga Transmission Corp
Yes
I do however believe that each utility should have the flexibility to manage there program the way they feel is
the most effective method. I do not want the technical basis section to limit options. Should this be in a white
paper format?
East Kentucky Power
Cooperative, Inc.
Yes
I have no preference one way or the other on this issue.
ITC Holding
Yes
ITC agrees with Guidelines and Technical Basis section, but recommend including useful Technical
Reference actions and activities that would support defense-in-depth strategy. We also feel that to avoid any
confusion with the applicability section and interpretations in the future, any references to the Bulk Electric
System in the standard sections and guidance/technical reference document should be reviewed and
changed.
Entergy Services
Yes
Language should be added to the Guideline and Technical Basis Section to clarify or re-state that this section
is for assisting entities in understanding how to comply with the standard but does not contain mandatory
actions/activities, and a statement that entities are not required to use the information in the Guideline and
Technical Basis Section.
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
Western Area Power
Administrtaion
Yes
The format could be enhanced by moving the "Guidelines and Technical Basis" section forward to be included
with the corresponding Requirement, Measure, and Rationale. Perhaps the "Guidelines and Technical Basis"
could also be combined with the corresponding "Rationale" text box. This would be helpful because it is
awkward flipping back and forth between these two sections when trying to fully understand a requirement.
NERC Staff (12 staff members)
Yes
There is no language in the body of the standard to clarify that the information in the Guideline and Technical
Basis Section of the standard is not subject to enforcement. We suggest revising the heading to “Application
Guidelines.” This is the term that was originally proposed by the Results-based team and is the heading
identified in the proposed Standard Processes Manual.
SERC Vegetation Management
Sub-committee
Yes
This format adds clarity and improves readability.
Xcel Energy
Yes
This is all good information to add a depth of understanding for the user. It's not clear as to how modifications
to the Guideline and Technical Basis would come about - it is the same as the standards revision process?
Does this section replace the white paper? Will it actually be deemed to be part of the Standard? We are
curious as to the legal weight if this is not part of the Standard and believe that key provisions are in this
section. It seems it should be part of the Standard.
Ameren
Yes
This is helpful information to have that does not clutter up the requirements and measurements. Under R6,
the third paragraph, there is a typo: ..."230kv transmission lines at least once 'line' during the calendar year".
City of Tallahassee (TAL)
Yes
This is very useful information and will minimize misinterpretations by the entities and the compliance teams.
Progress Energy Carolinas
Yes
This new section provides additional information and SDT rationale that is critical to understanding how to
comply with the requirements in the standard and will also provide SDT intent/basis for the interpretation
process when necessary. Progress Energy believes that any references to the Bulk Electric System in the
standard sections and guidance/technical reference document should be reviewed and changed (e.g. “grid
reliability”) to avoid confusion with the applicability section in this draft and avoid the potential for applicability
interpretations once this version is adopted.
Independent Electricity System
Operator
Yes
This section should be placed in an appendix preceded by a statement that clearly states the purpose of the
Section and indicates that the Guideline and Technical Basis Section does not in any way add to the
requirements of the standard. Also, this section appears to be a summary of the Technical Reference
Document but we could find no reference to the Technical Reference within the standard. This reference
should be cited for the benefit of anyone seeking further detail.
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
Western Area Power
Administration - Upper Great
Plains Region
Yes
WAPA - UGPR agrees with the concept of placing the background technical information in a separate section.
We were a bit concerned with the Guideline for R7 because it seems to mandate many more items than were
called for in the actual requirement in the body of the standard. Our belief is that the Guideline section should
not infer or list any more requirements than the actual requirement dictates.
Ad Hoc Group subteam formed to
review draft standard
Yes
We agree with the additional material as an aide to entities to further understand the basis for the
requirements. In this spirit the information should support compliant behavior and thus the reliability
objectives of the standard.
Dominion
Yes
While we agree that these can be useful, we are concerned about the ‘last minute’ change (March 24th) to the
technical reference document being used by those reviewing the materials for this project.
Southen Company
Yes
Would it be better to have an official white paper associated with the standard rather than having this
information in the standard? A white paper can be changed without seeking industry comments and approval
from NERC, while information in the standard must go through the entire approval process. As it is
structured now, information-only updates to the Technical Basis Section would require the entire standards
approval process to be completed.
American Electric Power (AEP)
Yes
Yes, although American Electric Power does question whether auditors will be able to avoid reading and
applying such text.
KCPL
No
I like information that helps to “guide” and “provide guidance”, however, we already having trouble with
information from FAQ’s, White Papers, and other guiding documents creeping into the requirements by
auditing teams. The inclusion of “guiding information” in the text of the Standard itself may promote adding to
requirements. Although helpful, I recommend removing this text from within the body of the Standard.
64
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
9. Do you prefer putting URL links to reference materials in the Guideline and Technical Basis Section, or do you prefer putting the
additional technical/information materials in appendices, where needed, to supplement the Guideline and Technical Basis Sections?
Please explain.
Summary Consideration: Out of the 52 comment forms received, 28 forms indicated a preference for use of URLs, 22 indicated a preference for
appendices and 5 indicated no preference. These results indicate that either approach would be acceptable. The SCPS agreed to put the
information in an appendix rather than in a URL because it is difficult to maintain the accuracy of URLs over time, and because keeping the
information in the body of the standard is less work for end users as all information would be in one place.
Organization
Yes or No
Question 9 Comment
MRO's NERC Standards
Review Subcommittee
If there is background information contained in a URL link pertaining to a particular Requirement, that
link should be with the Requirement that it pertains to.
Ad Hoc Group subteam
formed to review draft
standard
Judicious and correct use of citations should allow the proper documentation of references without the
hazard of expired URLs or expansion from using appendices.
Tennessee Valley Authority
No preference, either way will work.
Consumers Energy
Prefer appendices
Exelon
Prefer appendices
PPL Electric Utilities
Corporation (NCR00884)
Prefer appendices
South Carolina Electric and
Gas
Prefer appendices
TO/TOP
Prefer appendices
Tucson Electric Power Co.
Prefer appendices
Western Area Power
Administrtaion
Prefer appendices
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 9 Comment
Xcel Energy
Prefer appendices
GCPD
Prefer appendices
Actually we prefer that they are separate from the standard entirely. See question 8.
Cleco
Prefer appendices
An appendix ensures the information is available and original at the time the document it supports was
prepared.
ERCOT ISO
Prefer appendices
An Appendix would probably be easier to use, but either type of reference would suffice. Regardless of
which is used, it should include a footnote that the information is “For Information Purposes Only” and
are not a part of the Standard’s Requirements. If the information causes confusion, then it should be
eliminated completely. Also, what types of materials are contemplated to be “reference materials”?
Oncor Electric Delivery
Prefer appendices
Appendices would memorialize documents vs URL links to reference materials that may change over
time. This Standard was crafted from “todays” point of view and background information. Reference
material might change and the URL would point to material not validating the current form, logic, and
background of the Standard.
Entergy Services
Prefer appendices
Appendices, or reference to a single site for all referenced material, would be the most helpful from the
standpoint of keeping the information together and more readily available.
BGE (on behalf of
parent/affiliate companies:
CEG, CPSG, CECG, CNE &
CENG)
Prefer appendices
BGE prefers that such materials be included in the appendices.
NERC Staff (12 staff
members)
Prefer appendices
It is not clear what part of the standard is being balloted and what part is not. In addition, it is not clear
what process will be used to modify the guideline/technical basis section of the standard. This needs to
be determined before this standard can be balloted.
FRCC Manager of Operations
Prefer appendices
Links can get broken - official records (ie. standards) need to stand alone.
City of Tallahassee (TAL)
Prefer appendices
The fewer places I have to navigate to the better I like it. I find too many “broken” URLs. This will also
make it easier when I download a “complete set” of standards from the NERC website.
Dominion
Prefer appendices
Unless a ‘failsafe’ process is developed to insure URL links are keep up-to-date, preference is to locate
all referenced materials within the standard (same URL). However, there are a number of ways that
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 9 Comment
URL linkage could be done. One would be to locate all Guideline and Technical Basis documents on a
webpage dedicated to such documents. This would allow URL linkage at a higher level than if there is
URL linkage for each Guideline or Technical Basis document. This is probably the easiest to maintain.
Another would be to link each Guideline or Technical Basis document referenced in a standard to the
same URL as that standard. Maintaining URL linkage is probably medium. Yet another is to have the
URL link to a webpage created specifically for that Guideline or Technical Basis document. This is likely
to be the hardest (require most effort) to maintain.
CenterPoint Energy
Prefer appendices
URL links tend to change over time due to administrative requirements. Moving them to the appendix
will avoid revisions to the Standard. See also answer to Q3 regarding the Guideline and Technical
Basis Section.
Florida Municipal Power
Agency (FMPA) and Some
Members
Prefer appendices
URLs can break
Nebraska Public Power District
Prefer appendices
URLs change periodically.
North Carolina EMC
Prefer appendices
Will need to put something in place to make sure that the links get properly updated if they change.
Ameren
Prefer the inclusion
of URL links
Arizona Public Service
Company
Prefer the inclusion
of URL links
Bonneville Power
Administration
Prefer the inclusion
of URL links
Consolidated Edison Company
of New York, Inc.
Prefer the inclusion
of URL links
Duke Energy
Prefer the inclusion
of URL links
Ga Transmission Corp
Prefer the inclusion
67
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 9 Comment
of URL links
IRC Standards Review
Committee
Prefer the inclusion
of URL links
Manitoba Hydro
Prefer the inclusion
of URL links
Omaha Public Power District
Prefer the inclusion
of URL links
Pepco Holdings, Inc. Affiliates
Prefer the inclusion
of URL links
Southern California Edison
Company
Prefer the inclusion
of URL links
Utility Risk Management
Corporation
Prefer the inclusion
of URL links
Progress Energy Carolinas
Prefer the inclusion
of URL links
Additional reference documents provide additional information that may be needed to understand how
to comply and the basis of requirements, but they should not be included as appendices. The use
appendices could result in a SDT process/effort for minor revisions to the reference document.
American Transmission
Company
Prefer the inclusion
of URL links
Also see ATC’s comment on “Guideline and Technical Basis Section” in Question #3 above.
Independent Electricity System
Operator
Prefer the inclusion
of URL links
In general the additional reference materials may make the document extremely voluminous so we
prefer URL links.
Northeast Power Coordinating
Council
Prefer the inclusion
of URL links
Links are preferable to alleviate the concerns expressed in question 8 above, especially with respect to
FERC approval.
JEA
Prefer the inclusion
of URL links
No strong preference.
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 9 Comment
Tampa Electric Company
Prefer the inclusion
of URL links
None
Western Area Power
Administration - Upper Great
Plains Region
Prefer the inclusion
of URL links
None
Orange and Rockland Utilities,
Inc.
Prefer the inclusion
of URL links
Prefer the inclusion of URL links
East Kentucky Power
Cooperative, Inc.
Prefer the inclusion
of URL links
Provides for clarity and readability.
Southen Company
Prefer the inclusion
of URL links
See answer to number 8.
American Electric Power
(AEP)
Prefer the inclusion
of URL links
The use of URL links is probably most appropriate for an increasingly web-based reference repository.
SERC OC Standards Review
Group
Prefer the inclusion
of URL links
This format adds clarity and improves readability.
SERC Vegetation
Management Sub-committee
Prefer the inclusion
of URL links
This format adds clarity and improves readability.
ITC Holding
Prefer the inclusion
of URL links
URL links provide immediate access, are less cumbersome, and usually provide additional research
material when accessed.
FirstEnergy
Prefer the inclusion
of URL links
We prefer URL links. Although, we are not clear what this question is asking regarding "additional
technical/information materials". Is the team referring to "supplemental" reference documents such as
the technical reference white paper that was recently posted for stakeholder review on March 24,
2010? If so, we agree that supplemental reference material be included through URL links, perhaps at
the end of the "Guidelines and Technical Basis" section of the standard.
KCPL
Prefer appendices
Although a good idea generally, too many times URL links change name or something else that makes
the imbedded link unusable or takes you to the wrong place. Having an appendix ensures the
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 9 Comment
information is available and original at the time the document it supports was prepared.
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
10. Do you agree with the addition of the Background Section to allow provision of background information, and to elaborate on the
reliability-related drivers for the standard/change? Please explain.
Summary Consideration: Most of the comment forms (42 out of 54) indicate agreement with the addition of the Background Section.
Some commenters expressed similar concerns as those for Text Boxes and the Guideline and Technical Basis Section that the information should
not be subject to FERC’s review and approval, and that the Background may contain Requirement material that is enforceable. Other commenters
suggested that this Section is not needed given the addition of the Guideline and Technical Basis Section.
The SCPS believes that the Background Section serves a different purpose than the Guideline and Technical Basis Section. The Background
Section provides the background that led to the development of the standard, tying it to the reliability drivers and principles. In essence, the
Background Section gives readers the reasons for and the events that led to the development of the standard. The Guideline and Technical Basis
Section serves a very different purpose as it provides readers with the technical background, general guidelines, and general practices or
technical merits that the responsible entities could take or consider to help them meet the reliability requirements. The Guideline and Technical
Basis Section can also be used to provide some examples to illustrate the coverage or intent of the requirements.
On this basis, the SCPS believes it is in the interest of the majority of commenters to keep the Background Section. The SCPS will communicate
to the standard drafting team that the Background Section must not contain requirement material, and should not include any technical information
that should be provided in the Guideline and Technical Basis Section. The Background Section will remain at the front of the standard. As noted
in response to other questions, a legal statement will be added to clarify which sections of the standard are mandatory and enforceable.
Organization
Yes or No
Question 10 Comment
ERCOT ISO
No
Again, it is preferable to include this type of information in an Appendix as long as it is made clear that this is
additional information and is not a part of the Standard’s Requirements. However, if there is a chance that
the additional information included in the Appendix is going to cloud the Requirements spelled out in the
Standard, then our preference is to eliminate the additional information completely.
SERC OC Standards Review
Group
No
Inclusion of a background section in a document that will be approved wholly by FERC give undue credence
and weight to statements which may be included that are not necessarily factual 100% of the time. For
example, the first sentence of the last paragraph of the background section reads as follows: “Since
vegetation growth is constant and always present, unmanaged vegetation poses an increased outage risk,
especially when numerous transmission lines are operating at or near their Rating.” Obviously, woody stems
do not grow during the dormant season, yet the background asserts that it does. There are other areas in this
sentence that are not completely factual and should not be in a reliability standard. We recommend that the
text “grid reliability” be substituted for “Bulk Electric System” on page 6 of the draft.
Consumers Energy
No
Not necessary.
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
Northeast Power Coordinating
Council
No
NPCC participating members believe this is more informational and appropriate on the individual standard’s
NERC Website “Under Development” page, in an announcement, cover letter, or to be distributed with the
standard drafts.
Nebraska Public Power District
No
Same as item 7.
CenterPoint Energy
No
See answer to Q3.
Florida Municipal Power Agency
(FMPA) and Some Members
No
The background belongs in the Guidelines and not as part of the standard.
FRCC Manager of Operations
No
The background section should be re-named "Technical Basis". Trim content and leave only the first and last
paragraphs. In addition, all 5 paragraphs of the section as written should be moved to the front of the
Guidelines and Technical Basis document as a "Background" section of that separate document. NERC
should limit its use of "background" information within the reliability standard itself.
TO/TOP
No
The background section should be re-named "Technical Basis". Trim content and leave only the first and last
paragraphs. In addition, all 5 paragraphs of the section as written should be moved to the front of the
Guidelines and Technical Basis document as a "Background" section. NERC should limit its use of
"background" information in reliability standards.
Cleco
No
The inclusion of the text implies additional requirements. Keep quidance to a separate paper.
Exelon
No
This information should be in appendices or reference documents available on the NERC standards site.
Ameren
Yes
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
Central Maine Power, Iberdrola
USA
Yes
City of Tallahassee (TAL)
Yes
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Duke Energy
Yes
East Kentucky Power
Cooperative, Inc.
Yes
Ga Transmission Corp
Yes
JEA
Yes
Manitoba Hydro
Yes
MRO's NERC Standards Review
Subcommittee
Yes
North Carolina EMC
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southen Company
Yes
Tennessee Valley Authority
Yes
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Question 10 Comment
73
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
Western Area Power
Administrtaion
Yes
SERC Vegetation Management
Sub-committee
Yes
Allows for a more informed interpretation of the standard.
American Electric Power (AEP)
Yes
American Electric Power agrees with this change.
American Transmission
Company
Yes
ATC agrees that the Background Section is helpful; however, NERC should define its purpose and goal.
What is currently written is more than necessary to be included in this standard.
Dominion
Yes
Dominion agrees but suggests it be moved towards end (suggest between Administrative and
Guideline/Technical basis sections).
Ad Hoc Group subteam formed to
review draft standard
Yes
Great help in showing intent and reliability goal of the standard.
Southern California Edison
Company
Yes
Including a background section should prove useful for future editions. However, at some point such
information could be made accessible through URL links.
ITC Holding
Yes
ITC agrees with the addition of Background Section
GCPD
Yes
May help in iterpretations and in explaining to stakeholders in our organizations.
Tampa Electric Company
Yes
None
Western Area Power
Administration - Upper Great
Plains Region
Yes
None
Progress Energy Carolinas
Yes
Progress Energy agrees and believes that the background section will allow relevant background information
that provided direction/guidance for the SDT to be readily available after the standard revision is adopted.
Entergy Services
Yes
The Background Section is helpful, but the last sentence states....."Thus, this Standard's emphasis is on
vegetation grow-ins.". This statement seems to conflict with the outage Category 2 "Fall In" classification,
74
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
even though it is a fall in from within the ROW.
Xcel Energy
Yes
The Background section should be moved to the back, in front of the Guideline and Technical Basis.
IRC Standards Review
Committee
Yes
This background is important for insertion at the beginning of a SAR. But for a standard-posting, it is
suggested that this section is redundant and better inserted after the requirement and measures with the
other Administrative materials.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
This makes sense to BGE.
NERC Staff (12 staff members)
Yes
This provides a context for the requirements and is very beneficial in understanding the intent of the standard.
Independent Electricity System
Operator
Yes
This section expands on the purpose statement and will promote a uniform understanding of the fundamental
drivers for the standard and its requirements, as well as its philosophy and scope.
Consolidated Edison Company of
New York, Inc.
Yes
We agree but believe the Background Section should be situated before the Applicability Section in the
revised Standard and redundant verbiage should be removed.
Orange and Rockland Utilities,
Inc.
Yes
We agree but believe the Background Section should be situated before the Applicability Section in the
revised Standard and redundant verbiage should be removed.
FirstEnergy
Yes
We agree that a Background section is beneficial. However, we believe it may be more appropriate to move
this information to the Guidelines section as a lead-in. Also, we suggest a rewording of the first sentence of
the first paragraph on Pg. 2 which states: "Major outages and operational problems have resulted from
interference between overgrown vegetation and transmission lines located on many types of lands and
ownership situations". We agree that vegetation can contribute to outages, but it cannot be the sole cause of
major outages. Major outages can be prevented if other measures required by other NERC standards are
implemented when vegetation causes a line or other equipment to malfunction. We suggest a rewording of
this statement as follows: "Interference between vegetation and transmission lines located on many types of
land have contributed to significant outages and operational challenges."
KCPL
No
I like information that helps to “guide” and “provide guidance”, however, we already having trouble with
information from FAQ’s, White Papers, and other guiding documents creeping into the requirements by
auditing teams. The inclusion of “guiding information” in the text of the Standard itself may promote adding to
75
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 10 Comment
requirements. Although helpful, I recommend removing this text from within the body of the Standard.
76
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
11. Do you agree with the addition of an Administrative Procedure Section to place administrative/procedural requirements that are
contained in the existing standards but which do not meet the results-based or risk-based criteria? Please explain.
Summary Consideration: Most comment forms (36 out of 52) indicated agreement with this addition.
Some commenters questioned whether or not these Administrative Procedures are mandatory and if so, why they are not placed in the
Requirements and Measures Section or at least renamed “Administrative Requirements”. They asked, if the administrative requirements are
mandatory, are they subject to compliance audit and if so, would a monetary penalty be applied?
Some suggested that if the administrative procedures are not mandatory requirements, they should not be included in standards and proposed the
alternative approach of collecting data/reports through the Rules or Procedure Section 1600.
The intent of creating the Administrative Procedure Section is to separate the procedural and administrative requirements from the results-based
reliability requirements since not performing the former tasks does not adversely affect BES control or performance or expose the BES to reliability
risks. The SCPS will provide further clarity to the intent of this Section, and consider the use of Rules of Procedure Section 1600 for data/report
collection as an alternative.
Organization
Yes or No
Question 11 Comment
Consumers Energy
No
Nebraska Public Power District
No
Administrative requirements should not be included in the Standard, they may be construed unintentionally as
a requirement.
GCPD
No
Anything not directly associated with the compliance requirements or for help with interpretations should not
be in the standard.
Northeast Power Coordinating
Council
No
As stated earlier, NPCC participating members don’t understand if this section holds sanctionable
requirements, and if so under what authority. Administrative items are best left to the ROP or Compliance
documents. A results based standard’s primary focus should be on the requirements, and the goal or
reliability objective. Taking administrative requirements out of the formal requirements section, adding them
to another section, and still deeming them to be requirements is of no value to reducing the administrative
burden on the industry. This makes the implementation of the standard more burdensome due to the fact that
these additional “requirements” now reside in different places in the standard document. NPCC participating
members suggest if these are truly valid requirements they need to be together with the other requirements.
If they do not meet the results based criteria, and were included in this “Administrative Procedure” section
strictly because of that, then they need to reside in another document. Their continued appearance in the
document dilutes the integrity of the results based standard initiative.
77
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 11 Comment
Exelon
No
Exelon is concerned this will raise questions concerning what criterion separates an administrative
requirement from a results or risk based requirement. How are administrative requirements to be treated in
the CMEP?
CenterPoint Energy
No
It is not clear if the Administrative Procedure is a mandatory activity. It would be helpful if the intent of this
section was stated within the Standard.Also, this section in not parallel with the Rating and Rated Electrical
Operating Conditions exception contained in R1 and R2. We recommend the following parallel wording for
the first paragraph of this section:”The Transmission Owner will submit a quarterly report to its Regional
Entity, or the Regional Entity’s designee, identifying certain Sustained Outages of the categories defined
below, while operating within the Rating and Rated Electrical Operating Conditions, determined by the
Transmission Owner to have been caused by vegetation that includes, as a minimum, the following:”Also, the
categories listed in this section do not have parallel language to M1 and M2. We recommend that this section
should adopt the wording in M1 and M2 for the Sustained Outages to be reported. Currently, Category 2 and
Category 4 do not distinguish between an IROL and Major WECC Transfer Path. This may become a
tracking problem since they have different Violation Risk Factors. If this is not important, then Category 1A
and 1B can be combined.
Consolidated Edison Company of
New York, Inc.
No
It is somewhat confusing to have sanctionable requirements located in other sections of the Standard outside
of 'Requirements and Measures.' The section title 'Administrative Procedure' is somewhat misleading; if it was
renamed 'Administrative Requirements' we feel it would be clearer to the industry.
Orange and Rockland Utilities,
Inc.
No
It is somewhat confusing to have sanctionable requirements located in other sections of the Standard outside
of 'Requirements and Measures.' The section title 'Administrative Procedure' is somewhat misleading; if it was
renamed 'Administrative Requirements' we feel it would be clearer to the industry.
SERC OC Standards Review
Group
No
Reporting Outages is not a part of Vegetation Mgmt. Therefore, this reporting belongs in an Administrative
Section or possibly via a NERC 1600 request. In no circumstance should it be a Requirement of the standard.
In the last paragraph this section appears to place a requirement on a regional reliability entity: “The Regional
Entity will report the outage information provided by Transmission Owners, as per the above, quarterly to
NERC, as well as any actions taken by the Regional Entity as a result of any of the reported Sustained
Outages.” Was this really intended? What if the RE fails to make a report?
IRC Standards Review
Committee
No
Some additional explanation is needed.
If the requirement is to do inspections, and compliance is
measured on that basis only then the Administrative Section is OK.
If the entity is mandated to also meet
the actions specified in the Administrative Section, then the change is not acceptable. This standard's
example administrative section is introducing new requirements into the standard, and those requirements
should be in the standard. In short, if there is a reliability requirement than that is what should be mandated.
78
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 11 Comment
The idea of mandating administrative items that are often designed to make auditing (not operations or
planning) simpler should not be mandated.
FRCC Manager of Operations
No
The "Administrative" section needs to be streamlined - remove the first 2 paragraphs - quarterly reporting is
no longer required and would be an administratively redundant process to the self-reporting of outages.
Leave the outage categories to support consistent self-reports. Delete last paragraph - reporting by the
Regional Entities to NERC is a delegated function that should be governed by the delegation agreements,
rules of procedure or other internal ERO process, not within a reliability standard since REs and the EROs are
not users, operators, etc of the BPS.
TO/TOP
No
The "Administrative" section needs to be streamlined - remove the first 2 paragraphs - quarterly reporting is
no longer required and would be an administratively redundant process to the self-reporting of outages.
Leave the outage categories to support consistent self-reports. Delete last paragraph - reporting by the
Regional Entities to NERC is a delegated function that should be governed by the delgation agreements,
rules of procedure or other internal ERO process, not a reliability standard.
Ad Hoc Group subteam formed to
review draft standard
No
The administrative procedure section is appropriate under results-based requirements. However, we believe
that reporting requirements established under other methods, such as the CMEP, may be confused by
including it. It is unclear how non-conformance with administrative procedures would be handled. Perhaps
administrative procedures would be better handled under ROP Section 1600 data requests or other Rules.
Cleco
No
The inclusion of the text implies additional requirements. Keep quidance to a separate paper.
Florida Municipal Power Agency
(FMPA) and Some Members
No
The reporting requirements really boil down to a self-reporting or self-certification process since the only items
to report would be violations to the standard. If such quarterly reporting is desired, it is really a selfcertification process and should be governed by that process and not through a separate Administrative
Procedure.FMPA recommends deleting the last paragraph - reporting by the Regional Entities to NERC is a
delegated function that should be governed by the delegation agreements, rules of procedure or other internal
ERO process, not within a reliability standard since REs and the EROs are not users, operators, etc of the
BPS, and are not designated in the Applicability section.
Ameren
Yes
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Central Maine Power, Iberdrola
USA
Yes
City of Tallahassee (TAL)
Yes
Dominion
Yes
Entergy Services
Yes
Ga Transmission Corp
Yes
Manitoba Hydro
Yes
MRO's NERC Standards Review
Subcommittee
Yes
NERC Staff (12 staff members)
Yes
Omaha Public Power District
Yes
Oncor Electric Delivery
Yes
Pepco Holdings, Inc. - Affiliates
Yes
PPL Electric Utilities Corporation
(NCR00884)
Yes
South Carolina Electric and Gas
Yes
Southen Company
Yes
Southern California Edison
Company
Yes
Tennessee Valley Authority
Yes
Question 11 Comment
80
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 11 Comment
Tucson Electric Power Co.
Yes
Utility Risk Management
Corporation
Yes
Xcel Energy
Yes
Are we to understand that the requirements listed in the Administrative section are not sanctionable from a
NERC compliance perspective?
American Transmission
Company
Yes
ATC feels this adds good will on the part of the entity to submit necessary reports, however, ATC requests
clarification whether this section is subject to NERC violations. (Currently not listed in Table 1 Time Horizons,
VRFs and VSLs)
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
Yes
BGE agrees with addition of an Administrative Procedure section.
Duke Energy
Yes
During the WEBINAR, a question was raised regarding how failure to meet an Administrative/Procedural
requirement would be addressed by the Regional Entity. Can the Standard Drafting Team prepare a response
to the question?
JEA
Yes
However, it needs to be made clear whether this is subject to audit, and whether failure to meet the
requirement is subject to the same or different enforcement procedures as the numbered requirements in the
standard.
East Kentucky Power
Cooperative, Inc.
Yes
I do not believe that reporting of outages is a part of development and implementation of a Vegetation
Management Plan. I fail to see how it brings value to the standard.
ITC Holding
Yes
ITC agrees that the “administrative role” such as outage reporting; shouldn’t be a reliability requirement and
are more appropriately defined as an administrative procedure. We would also like some clarification on
whether this section of the standard is subject to NERC violations. Currently it’s not listed in Table 1 Time
Horizons, VRFs and VSLs
Western Area Power
Administration - Upper Great
Plains Region
Yes
None
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 11 Comment
Tampa Electric Company
Yes
Not sure why separating 1.A & 1.B is preferred over 1,2,3,4?
Progress Energy Carolinas
Yes
Progress Energy agrees that “Administrative” functions such as outage reporting should not be listed as a
reliability requirement and are more appropriately defined as an administrative procedure. (Outage reporting
is an administrative function that does not directly improve reliability which should be the focus of reliability
standard requirements.)NERC has other formal information request procedures in place (such as a NERC
1600 request), if that becomes necessary to ensure outage reporting.
SERC Vegetation Management
Sub-committee
Yes
Reporting Outages is not a part of Vegetation Mgmt. Therefore, this reporting belongs in an Administrative
Section or possibly via a NERC 1600 request. In no circumstance should it be a Requirement of the standard.
Western Area Power
Administrtaion
Yes
The Administrative Procedure section could be moved forward following the Background section to better
introduce the general administrative overview for what would then become the following Requirements,
Measures, etc. These general administrative and procedural requirements are more easily overlooked when
they included at the back of the Standard.
American Electric Power (AEP)
Yes
This addition is acceptable
Independent Electricity System
Operator
Yes
This section imposes an additional reporting requirement but there is no associated VRF or VSL. Is this
intentional? How will failure to report on time be treated? This is unclear as is the significance of any such
Administrative “Requirements” within the standard, in general. Is the intention to establish separate
procedures to govern the administrative and reporting obligations of registered entities under the Rules of
Procedure?
FirstEnergy
Yes
We agree with the Administrative Procedure Section. Monetary fines should not be imposed for
noncompliance with administrative requirements.
KCPL
No
It is too easy to unintentionally infer or introduce something that is not intended to be a requirement, but gets
interpreted as a requirement in this section. Standards should be clear in what is a requirement and what is
helpful information. If these are requirements, then propose them as requirements. If not, then remove to
another guiding document.
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
12. Is there any other information that should be included in the standard document? If so, please explain why you feel that this
information should be included.
Summary Consideration: None of the commenters offered any suggestions for including additional information that has not already been
suggested in one or more of the comments provided in Questions 3 to 11.
Some commenters provided comments on the standard content itself.
Some commenters commented on the “Informal Comment” process. While this process may be useful in speeding up the process of developing
standards, it introduces a potential for a given Team to ignore valuable comments (either because the issue is unknown to them, or because the
proposal does not agree with the team’s ideas). They suggested that all comments (both formal and informal) be posted immediately for all to
review. The SCPS agrees with the suggestion however the software currently used to collect stakeholder feedback doesn’t format the data
collected in a manner that is easy to understand. NERC staff is exploring alternatives that would make it easier for stakeholders to view
comments as they are submitted. The informal commenting process is meant to collect industry views in the same manner as the formal
commenting process; it differs only in not requiring the SDTs to provide a response to each comment. Notwithstanding this provision, the SDT is
still obligated to post all comments and provide summary responses to the comments.
Organization
Yes or No
Ad Hoc Group subteam formed to
review draft standard
No
American Transmission
Company
No
Bonneville Power Administration
No
City of Tallahassee (TAL)
No
Cleco
No
Consolidated Edison Company of
New York, Inc.
No
Consumers Energy
No
Dominion
No
Question 12 Comment
83
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Duke Energy
No
East Kentucky Power
Cooperative, Inc.
No
Exelon
No
Florida Municipal Power Agency
(FMPA) and Some Members
No
Ga Transmission Corp
No
Independent Electricity System
Operator
No
ITC Holding
No
JEA
No
Manitoba Hydro
No
Nebraska Public Power District
No
NERC Staff (12 staff members)
No
Northeast Power Coordinating
Council
No
Oncor Electric Delivery
No
Orange and Rockland Utilities,
Inc.
No
Pepco Holdings, Inc. - Affiliates
No
Question 12 Comment
84
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 12 Comment
PPL Electric Utilities Corporation
(NCR00884)
No
South Carolina Electric and Gas
No
Southern California Edison
Company
No
Tennessee Valley Authority
No
Tucson Electric Power Co.
No
Utility Risk Management
Corporation
No
Western Area Power
Administrtaion
No
Tampa Electric Company
No
All areas have been addressed and clarified as needed.
BGE (on behalf of parent/affiliate
companies: CEG, CPSG, CECG,
CNE & CENG)
No
BGE feels no other information is necessary for inclusion.
American Electric Power (AEP)
No
None
Western Area Power
Administration - Upper Great
Plains Region
No
None
GCPD
No
Too much already.
Omaha Public Power District
Yes
SERC OC Standards Review
Yes
As suggested in comment six, an improvement would be also listing the applicable table rows with each
requirement which consolidates all pertinent info with the requirement. Also, adding the penalty matrix would
85
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Group
Question 12 Comment
facilitate discussions with property owners/agencies resisting maintenance activates. This standard indicates
a lack of recognition that vegetation outages are not necessarily reliability events. In the quest for improved
reliability, spending the money necessary to achieve perfect compliance with R2, as stated, either will
increase customer rates unnecessarily or cause the misallocation of maintenance funding away from
maintenance activities that have a substantially higher impact on reliability.
SERC Vegetation Management
Sub-committee
Yes
As suggested in comment six, an improvement would be also listing the applicable table rows with each
requirement which consolidates all pertinent info with the requirement. Also, adding the penalty matrix would
facilitate discussions with property owners/agencies resisting maintenance activates.
Arizona Public Service Company
Yes
Clearance 1 needs to be put back into this requirement as written. This is a vegetation management standard
and there needs to be clear direction on how the system is going to be maintain at the time of maintenance.
This ensures a clear direction to the utility the system has to be maintained. ANSI A-300 part 1 and 7 needs
to be a requirement within the standard. Following this consensus agreement within the Professional Utility
Vegetation Management sector outlines a process for providing a reliable transmission system. At a
minimum ANSI A-300 part 1 and 7 should be incorporated into the Guideline and Technical Basis Section as
a resource for compliance with this standard. Prudence would dictate that it be adopted into this draft as the
foundation of any transmission vegetation management program as it is the accepted standard for
professionals who are responsible for managing vegetation for electric utilities.Personnel qualifications need
to be included in the standard and should include minimum measures such that there is consistency across
the industry. This ensures that personnel are qualified and will have ongoing training and education in utility
vegetation management. For example: The person who manages the field operation should have at least 5
years experience in vegetation management be an International Society of Arboriculture Certified Arborist and
a Utility Specialist.
Ameren
Yes
In 4.3.1, suggest that "ice" be included in circumstances beyond the reasonable control of a TO in addition to
the other "acts of God".
Entergy Services
Yes
More clarifying language throughout the document would be helpful.
Progress Energy Carolinas
Yes
None, other than the comment about potential improvements in question #6.
IRC Standards Review
Committee
Yes
Regarding the new format, the idea of using “Informal Comment Periods” may be useful in speeding up the
process of developing standards, but it also introduces a potential for a given Team to ignore valuable
comments (either because the issue is unknown to them, or because the issue does not agree with their
ideas).
How will the Standards Committee or others ensure the quality of the process does not suffer in
this way? What type of review process is contemplated to detect such behavior?
Having the Formal
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 12 Comment
comments at the end of the process may prevent subject matter experts (SME) from seeing the comments
and perspectives of other SMEs. The SRC suggests that all comments (both formal and informal) be posted
immediately for all to review.
Xcel Energy
Yes
See comments to #1, #7 and #13 of this form
FirstEnergy
Yes
See our other comments.
Central Maine Power, Iberdrola
USA
Yes
Table 2 expand footnote - State that table 2 is intended as a buiding block to develop clearance at time of
vegetation management work. See TVMP for clearances.
CenterPoint Energy
Yes
The detailed rationale for the required one year inspection cycle in R6 should be included in the Technical
Reference. The explanation provided in the Rationale that it “seems to be reasonable” and in the Technical
Reference that it is “reasonable based on upon average growth rates across North America and common
utility practice” are unfounded and arbitrary without a specific reference to a North American study. The
Technical Reference should contain an example diagram of “the portion of the ROW where the corridor edge
zones are designated by regulatory bodies for vegetation to exist” taken from the examples in the Definition of
Terms Used in Standard section. It is unclear how this example should be interpreted for compliance should
a Sustained Outage occur from vegetation growing within this zone. It is common for regulatory bodies to
push utilities to plant trees or maintain trees within transmission rights of way to “hide the lines”, and it is
unclear if this example is attempting to encourage such practice by regulatory bodies at the sacrifice of
reliability.In general, the Technical Reference should contain more specific examples of violations of the
Requirements and highlight specific exceptions related to vegetation related outages.The background and
basis for adding the term “Active Transmission Line Right-of-Way” should be added to the Technical
Reference.The background and basis for 4.2.4 that excludes the Standard from applying to fenced
substations should be added to the Technical Reference.Just as the force majeure statement (4.3.1) was
moved to the Applicability section of the Standard, the exception for applicability beyond the Rating and Rated
Electrical Operating Conditions should be included in the Applicability section as well. Currently, it is only
included in R1 and R2. It should be made clear if the other Requirements and Measurements must consider
conditions beyond the Rating and Rated Electrical Operating Condition.Within the Requirements and
Measures section there should be subheadings for each type of Requirement, performance-based, risk
based, and competency-based. This classification is only indicated in the Technical Reference.
MRO's NERC Standards Review
Subcommittee
Yes
The NSRS believes a section for definitions and abbreviated terms such as, Active ROW, MVCD, and WECC
is needed. Also, See comment above in Question 9 on URL links.
Southen Company
Yes
We feel a definition of Category 3 outages (non reportable outages) should be included under the
87
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 12 Comment
administrative procedures. Although these outages are not reportable, this would provide a mechanism for
classifying these outages so the utility can maintain evidence of its investigation and the rationale for not
reporting them.
KCPL
No
88
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
13. Do you have any other comment regarding the draft FAC-003-2 Transmission Vegetation Management standard that have not been
addressed above? If yes, please provide a reference to the section, requirement, or subrequirement that you believe should be
changed, added or deleted and the rationale for your proposal.
Summary Consideration:
1. Reasonable control - Some commenters expressed that the phrase “reasonable control” is difficult to enforce, while others wanted it moved
to another section of the standard.
The term “reasonable control” is prevalent in many force majeure clauses. It intends to limit the extent of compliance responsibility to those
conditions that are within the sphere of the TO’s ability. The SDT have determined that eliminating the word “reasonable” would not detract
from the original intent and have made the change to the standard.
The SDT does not have a preference for the location of the force majeure language. This is within the scope of the Standards Committee
Process subcommittee to address.
2.
Differentiate between “human error” versus “human activity” – Some commenters requested further explanation of these terms.
The SDT intended for the term “human activity” to be used in the Background section of the standard and have removed “human error”. The
SDT intends the phrase human activity to describe those human actions that are outside the control of the Transmission Owner such as
logging, vehicle contact with tree, removal or digging of vegetation, horticultural or agricultural or arboricultural activity. The SDT proposes the
following new Force Majeure text:
“This Standard does not apply to any occurrence, non-occurrence, or other set of circumstances that are beyond the control of a Transmission
Owner subject to this reliability standard, including acts of God, flood, drought, earthquake, major storms, fire, hurricane, tornado, landslides,
ice storms, vehicle contact with tree, human activity involving, removal of vegetation, installation of vegetation or digging around vegetation,
animals severing trees, lightning, epidemic, strike, war, riot, civil disturbance, sabotage, vandalism, terrorism, wind shear, or fresh gales (or
higher) that restricts or prevents performance to comply with this reliability standard’s requirements. Nothing in this section should be
construed to limit the Transmission Owner’s right to exercise its full legal rights on the Active Transmission Line ROW.”
3. Competency-based requirement R3: Some commenters expressed that R3 is deficient in detail.
The SDT determined that the following parameters demonstrate competency:
•
•
•
•
•
•
•
Understands the dynamics of conductor movement over its operating range and design conditions, understands the interrelationship between growth rates and inspection frequency and choice growth control method. And successfully
implements the understanding as evidenced by lack of vegetation related outages.
Conducts inspections on a frequency that accounts for vegetation growth rates and local conditions.
Considers scheduling and permit lead times.
Designs work plans that levelizes work load.
Utilizes best industry practices such as ANSI A300.
Develops vegetation maintenance plans that account for vegetation growth rates and local conditions.
Incorporates a feedback mechanism in the program.
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
•
•
•
•
•
•
•
Balancing ROW management with cost and science.
Establishes wire security zones.
Documents non-compatible species.
Exercises full legal rights on the Active Transmission Line ROW to avoid outages.
Knows the condition of its ROW.
Gives clear direction to field personnel so that they know what to do to maintain the clearances.
Addresses an interim corrective action plan.
The SDT proposes the following modification to R3:
“R3. Each TO shall document the procedures, processes, or specifications it uses to prevent the encroachment of vegetation
into the MVCD. Such documentation will incorporate the dynamics of a transmission line conductor’s movement throughout its
Rating and Rated Electrical Operating Conditions and the inter-relationships between vegetation growth rates, vegetation
control methods, and inspection frequency, for the Transmission Owner’s applicable lines.”
4. Flexible annual work plan – Some commenter indicated that the word “flexible” in requirement R7 is difficult to enforce
without more detail.
The SDT modified the requirement as follows:
“R7. Each Transmission Owner shall complete an annual vegetation work plan to ensure no vegetation encroachments
occur within the MVCD. Modifications to the work plan in response to changing conditions or to findings from vegetation
inspections may be made provided they do not put the transmission system at risk.”
5. The SDT revised Section 4.2.2 – The SDT did not agree to the removal of the reference to FAC-014 and have re-inserted it.
“4.2.2. Overhead transmission lines operated below 200kV having been identified as an element of an Interconnection
Reliability Operating Limit (IROL) designated in compliance with NERC Standard FAC-014.”
6. Reporting – Some commenters recommend keeping the outage reporting language in the technical requirements section.
The Standards Committee Process Subcommittee is the appropriate body to address this issue.
7. Gallet distances – Some commenters asked how can reliability be equal or better when Gallet distances are less than IEEE
distances.
At the Gallet distance, the probability of Flashover is zero. The current in-force version of the FERC Transmission Vegetation
Management Program Standard (FAC-003-1) uses the minimum air insulation distance (MAID) without tools formula provided in IEEE Std.
516-2003 to compute the required minimum vegetation clearance distance between a transmission line conductor and vegetation. The
equations and methods provided in IEEE 516 were developed by an IEEE Task Force in 1968 from test data provided by thirteen
independent laboratories. The distances provided in IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap,
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
or in other words, dry laboratory conditions. Consequently, the validity of using these distances in an outside environment application has
been questioned.
The current in-force version of FAC-003-01 allowed the TO’s to use either Table 5 or Table 7 to establish the absolute lowest value for
these minimum clearance distances. Table 5 could be used if the TO knew the maximum transient over-voltage factor for its system.
Otherwise, Table 7 would have to be used. Table 7 represented minimum air insulation distances under the worst possible case transient
over-voltage factor. These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for
500 - 550 kV phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for
concern in this particular application of the distances.
The SDT sought out a different method of establishing these absolute minimum clearance distances that considers both the outside
weather environment and also the realistic maximum transient over-voltages factors for in service transmission lines.
In general, the worst case transient over-voltages occur on a transmission line when the line is open on one end and is opened on the
other and then inadvertently re-energized when trapped charge is present. The intent of FAC-003 is to keep a transmission line that is in
service from becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst
case scenarios mentioned above can be ignored.
For the purposes of FAC-003, the worst case transient over-voltage then becomes the maximum value that can occur with the line
energized. Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are
negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere along the
length of an in-service AC line is approximately 2.0 per unit. This value is a conservative estimate of the transient over-voltage that is
created at the point of application (e.g. a substation) by switching a capacitor bank without a pre-insertion device (e.g. closing resistors).
At voltage levels where capacitor banks are not very common (e.g. 362 kV), the maximum transient over-voltage of an “in-service” ac line
are created by fault initiation on adjacent ac lines and shunt reactor bank switching. These transient voltages are usually 1.5 per unit or
less.
Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order to
be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient overvoltage factor of 2.0 per unit for transmission lines operated at 242 kV and below is considered to be a realistic maximum in this
application. Likewise, for ac transmission lines operated at 362 kV and above a transient over-voltage factor of 1.4 per unit is considered
a realistic maximum.
The Gallet Equation is a proven method of computing the required strike distances for proper transmission line insulation coordination.
These equations were developed for both wet and dry applications and can be used with any value of transient over-voltage factor.
When one compares the Minimum Air Insulation Distances using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical
spark-over distances computed using the Gallet wet equations, for each of the nominal voltage classes using identical transient overvoltage factors it is clear that the Gallet equations yield a more conservative (larger) minimum distance value.
The following table is an example of this comparison:
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Comparison of spark-over distances computed using Gallet wet equations
vs.
IEEE 516-2003 MAID distances
using realistic transient over-voltage factors
( AC )
Nom System
Voltage (kV)
( AC )
Max System
Voltage (kV)
Transient
Over-voltage
Factor (T)
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
IEEE 516
MAID (ft)
@ Alt. 3000 feet
765
800
1.4
8.89
8.65
500
550
1.4
5.65
4.92
345
362
1.4
3.52
3.13
230
242
2.0
3.35
2.8
115
121
2.0
1.6
1.4
8. Definition of Active Transmission Line ROW – Some commenters indicated that the Active Transmission Line ROW
definition is unclear.
The SDT thoughtfully considered FERC staff’s concern regarding the Active Transmission Line Right-of-Way. However, in
light of the Commission direction in Order 693, in response to First Energy’s concern about unnecessary expense of
managing unused rights-of-way, to include such a provision, the SDT was left with only two practical choices, the current
proposed definition or a fill-in-the-blank site-specific TO-designated approach. Acknowledging the desire to eliminate fill-inthe-blank requirements, the SDT opted for the proposed definition. Therefore, the SDT respectfully suggests that no workable
change can be made to this definition and still implements Commission direction and thus has opted to retain the current draft
language.
9. R4: “Responsible control center” and “verified knowledge” – Some commenters remarked that there is no “Local Control
Center” entity in Functional Model and that could be an enforcement issue. Other commenters sought clarification for the
phrase “verified knowledge”.
The SDT clarified R4, M4 and Rationale text box:
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
“R4.
Each Transmission Owner shall notify the responsible control center without undue delay when qualified personnel
confirm the existence of a vegetation imminent threat. A vegetation imminent threat condition is one which is likely to cause a
Fault at any moment.”
“M4.
Each Transmission Owner that has experienced a confirmed vegetation imminent threat will have evidence that it
notified the responsible control center.”
“Rationale
To ensure rapid notification of the correct personnel when an occurrence of a critical situation is observed. Qualified personnel
may include line workers and utility arborists. The responsible control center is selected to ensure that the flow of operational
information, which includes broken cross-arms and tree issues, will continue to the Transmission Operator (or its delegate).”
10. R6 and R7 – Several commenters noted that R6 and R7 were assigned High VRFs although they previously were Medium.
SDT changed R6 and R7 from High to Medium. The justification is provided by NERC VRF Worksheet Tool and review of
NERC VRF Guideline. (See attached VRF_Tool_R6.pdf and VRF_Tool_R7.pdf documents for the VM SDT consensus
response utilizing the VRF Tool.)
11. Requirements R1 and R2 – some commenters stated:
i.
The MVCD requirements R1 and R2 need more detail to be enforceable and auditable. They do not see how FAC-003-2
addresses sag and sway with the elimination of Clearance 1.
ii.
Concern that the VRF for lines covered in R2 is a Medium.
Consideration:
i.
The SDT understands the commenter’s concern. The SDT worked on addressing the concern by drafting alternate
language to be responsive to issues of enforceability and auditability and offer the following as an alternative R1/R2
for industry comment:
“R1. Each Transmission Owner shall manage the floor of its Active Transmission Line ROW in accordance to one of
the following at all times:
A) A fixed maximum vegetation height of 15 feet from the ground at the mid-half of the span and 20 feet in the
outside quarters of the span, or,
B) A calculated maximum vegetation height that is the sum of the minimum conductor height at “max sag” plus
MVCD plus cycle growth, or,
C) A calculated minimum vegetation to conductor clearance that is the sum of “max sag” in the span plus MVCD
plus cycle growth, or,
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
D) A value determined by the Transmission Owner to provide a separation between the conductor and the
vegetation that is comparable to options A, B, or C.
E) Any alternative approach that ensures no encroachment occurs within MVCD, considering the sag and sway
of the conductor throughout its operating range under rated conditions.
F) A value to provide a separation between the conductor and the vegetation that is the sum of MVCD, and a
value that considers the sag and sway of the conductor throughout its operating range under rated conditions
plus 10 feet.”
NOTE: The SDT suggests similar language as found in the posted draft for measures M1/M2 may be appropriate
with this alternate R1/R2.
ii.
The SDT considered the comments that pertain to the assignment of a Medium VRF to R2 on the basis of IROL/Major
WECC Transfer Path designation. The SDT determined that the assignment of Medium is justified because the loss of
non-IROL or non-Major WECC Transfer Path lines pose a lower reliability risk than those lines that are elements of an
IROL or Major WECC Transfer Path.
Organization
Yes or No
American Electric Power
(AEP)
Question 13 Comment
American Electric Power suggests replacing the term "Minimum Vegetation Clearance Distance" with "Critical
Vegetation Clearance Distance." The use of "minimum" suggests that the minimum is acceptable. However, in
dealing with landowners or land managers, we may not be able to negotiate any more than the minimum. "Critical"
would help convey the sense that the distance borders on dangerous unacceptability.
Central Maine Power,
Iberdrola USA
No
Consumers Energy
No
East Kentucky Power
Cooperative, Inc.
No
IRC Standards Review
Committee
No
Manitoba Hydro
No
Pepco Holdings, Inc. -
No
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
Affiliates
PPL Electric Utilities
Corporation (NCR00884)
No
South Carolina Electric
and Gas
No
Southern California
Edison Company
No
Tennessee Valley
Authority
No
Tucson Electric Power
Co.
No
Tampa Electric Company
No
None
FRCC Manager of
Operations
Yes
- Applicability Section 4.3 - use the term "Exemptions" instead of "Other" as it is more descriptive.- As noted earlier Applicability Section 5 - use the term "Technical Basis" instead of "Background" and streamline by removing
paragraphs 2, 3 and 4.- R
American Transmission
Company
Yes
(a) R1 and R2 (pg.7) - What is meant by “to avoid a Sustained Outage”. Could be argued that a grow-in that does not
cause a Sustained Outage is acceptable. (Could this be a FERC issue?)(b) R5 (pg.9) - ATC believes the term
“temporarily” should be stricken from the requirement. This leaves too much to interpretation and does not add to the
requirement(c) R6 (pg.9) - The descriptive timeframe “at least once per calendar year” is used. What does this mean?
Every 365 days or a 12 month period within a calendar year? NERC needs to define this.(d) R4 (pg.15 in the
Guideline and Technical Basis) - The term “verified knowledge” is used which does not seem consistent with the
definition of “Verified Knowledge” in R4 Rationale on pg.8.(e) R4 (pg.16 in the Guideline and Technical Basis) - The
term “responsible control center” is used and further defined. ATC believes this is the Transmission Operator. This
should either be moved to the “Definitions of Terms” section or to R4 of the standard where the term is used.
Western Area Power
Administrtaion
Yes
1) It is suggested that the word "located" in the third bullet in Measure 1 and Measure 2 be replaced with the word
"originating". As worded, M1 or M2 could be interpreted to mean that vegetation originating outside of the right-of-way
which blows or sways into contact with conductors “located inside the ... right-of-way” would be evidence of a violation
of R1 or R2. Utilities generally are very limited in their ability to manage vegetative conditions outside of their right-of95
Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
ways.2) Please reference the comments under Question 2 above regarding the incompleteness of requirements R3
and R7 in fully replacing the CCZ management concepts utilized in the Draft 1 version of the proposed FAC-003-2.3)
The requirement R4 Guidelines and Technical Basis narrative is inconsistent with requirement R4. Specifically, in the
Guidelines and Technical Basis section the second paragraph’s introductory sentence identifies a requirement for an
imminent threat procedure, and the second bullet in this paragraph identifies a need to identify vegetation related
conditions that warrant a response. Neither of these items are a requirement of R4 as currently written. R4 only
speaks to the notification of the responsible control center when it has verified knowledge of a vegetation imminent
threat condition.4) The requirement R7 Guidelines and Technical Basis section is written with an inappropriate bias
towards very extensive or time based vegetation maintenance programs. Comments received from previous draft
standard reviews have revealed that there are many other effective program approaches being utilized by the industry.
It is suggested that this section be revised to broaden its scope to incorporate these other program approaches.
Ga Transmission Corp
Yes
1) I would like further examples of inactive portions of corridors. For example would a ten foot buffer strip that is in
addition to a normal width to stay off a property line but is included in an easement plat but not cleared be considered
inactive corridor or not? 2) The MVCD definition may not be realistic in its wording. Many utility companies may not be
able to maintain these clearances at “design of Transmission Facility”. This needs further definition maybe “NESC
moderate wind”. Many utilities in coastal areas will design lines for high sustained winds due to hurricanes these
clearances may not be possible to maintain under these conditions however the line may be designed to with stand
these winds.
FirstEnergy
Yes
1. Requirements R1 and R2 - We do not agree with the "zero tolerance" for real-time observation of encroachments
that do not cause an outage. When discovered, most Transmission Owners (TO) take immediate action to alleviate
encroachments and it is not appropriate to be fined for taking immediate action when no outage has occurred.
Therefore, a violation should only occur when the TO has not immediately alleviated the situation within 24 hours. We
suggest the following change to the first bullet in Measures M1 and M2: "Real-time observation of encroachment into
the MVCD that is not corrected within 24 hours."2. Measurement M1 and M2 - For additional clarity, we suggest
adding the following wording from Guideline and Technical Basis into M1 and M2 - "Brief encroachment by falling
vegetation are not considered a violation."3. Requirement R4 - Since the intent of this requirement is the immediate
notification of an imminent threat, we suggest adding the word "immediately" between "shall" and "notify".4.
Requirement R5 - We suggest removing the term "temporarily" in the requirement. Some constraints faced by
Transmission Owners are permanent and appropriate alternate action is permanently implemented. 5. Requirement
R7 - Although we agree that the TO should be allowed to adjust the plan, the use of the term "flexible" is subjective.
Additionally, the phrase "to ensure no vegetation encroachments occur within the MVCD" is redundant with the other
requirements of the standard. Therefore, we suggest revising the wording of Requirement R7 to the following: "Each
Transmission Owner shall implement an annual vegetation work plan. Adjustments to the work plan to defer work
beyond the calendar year are acceptable and shall be documented."6. Coordination between Project 2007-07 and
2010-07 - Since the TO-GO interface team has identified the need for Generator Owner (GO) applicability in the FAC003 standard, we believe that these two drafting teams should coordinate the addition of the GO into this Version 2 of
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
FAC-003. It would not seem sensible to revise Version 1 of FAC-003 to include the GO while Version 2 is developed
and approved without applicability to the GO.7. Compliance Section - Under "Additional Compliance Information", we
suggest removing the parenthetical phrase "See Administrative Procedure" and replace with "None". Since the
Administrative Procedure is not part of the requirements, it is not sanctionable and should not be included in the
Compliance Section.
MRO's NERC Standards
Review Subcommittee
Yes
1. Need definition for the phrase “Major WECC Transfer Paths”.2. In question 2 of the comment form, it refers to the
“bulk power system.” This standard does not cover the bulk power system, it covers lines above 200kV and certain
ones below 200kV.
BGE (on behalf of
parent/affiliate
companies: CEG, CPSG,
CECG, CNE & CENG)
Yes
4.2.4 States that the Standard is not applicable to “...to Facilities .... located inside the fenced area of a switchyard,
station or substation”. This implies that anything within the fenced area of a switchyard, substation or power plant does
not fall within the jurisdiction of FAC-003-2. Some fenced in areas could be very large and susceptible to vegetation
encroachments issues.4.3.1 Suggest including in the Force Majeure government a phrase referencing government
interference, such as “Federal, State or other regulatory interference, including legal or other legislative actions, that
prevents performance to comply with this reliability standard.”M1 & M2 bullet: “Real-time observation of encroachment
into the MVCD” implies that real-time observation of vegetation encroachment ensures reliable operation the Bulk
Electric System. The reliability standard objective states;”To improve the reliability of the electric Transmission system
by preventing those vegetation related outages that could lead to Cascading.”However, real time observation of
current operating conditions provides no assurance that vegetation will not lead to outages. BGE recommends
removing the language. If an inspector finds vegetation encroaching into the MVCD during a visual inspection he / she
should immediately initiate an Immediate Threat Notification. Therefore, this measure has no value.Disagree with R6.
- Inspection Frequency. Very prescriptive. Please consider allowing TO’s to select an annual frequency that best fits
their requirements, such as calendar year, every growing season, every non-growing season, etc. BGE currently
defines their inspection frequency as annually during the non-growing season, October 1 to May 1. BGE believes
inspecting during the dormant season is a best practice due to the ability of the inspector to identify vegetation
defects, especially off the ROW, which could be hidden during the growing season due to foliage, canopy cover, etc.
Also, if a utility elects to leverage an advance technology, such as LiDAR, it provides the most effective results when
LiDAR is utilize during the growing season, therefore allowing the results of the advance technology to enhance the
fall to spring inspection cycle. All of the above comments are submitted on behalf of:
- Baltimore Gas & Electric
Company - Constellation Energy Group, Inc. - Constellation Power Source Generation, Inc. - Constellation
Energy Commodities Group, Inc. - Constellation New Energy, Inc. - Constellation Energy Nuclear Group, Inc.
Arizona Public Service
Company
Yes
APS objects to number 3 Objectives statement. This is the only reliability standard that has at its Objective to prevent
vegetation related outages that could lead to cascading. This is a reliability standard and its objective needs to be:
“To improve the electric Transmission system by preventing vegetation related outages.” Requirement 6: To ensure
reliability the TO’s are responsible for doing an annual inspection. You either do it or don’t and if you don’t finish it
you should be held accountable. There shouldn’t be a lower VSL because you didn’t finish all of it. This is poor
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
planning on the utilities part.Requirement R7: When developing the annual work plan the Transmission Owner should
allow time for procedural requirements to obtain permits to work on federal, state, provincial, public, tribal lands. In
some cases the lead time for obtaining permits may necessitate preparing work plans more than a year prior to work
start dates. Transmission Owners may also need to consider those special landowner requirements as documented in
easement instruments. There needs to be parameters for the TO to show they allowed time for procedural
requirements. An example, some land agencies will give you permission to perform work in as little time as two weeks
and others can take two years. Even within the same land agency the timing of approvals is a moving target. APS
recommends the TO must show documentation it submitted their Vegetation Management Plan to the land agency at
least 120 days prior to the required start date. If the land agency doesn’t respond within this time frame and the utility
can not perform the work they shouldn’t be held responsible.
JEA
Yes
Generally, I believe this document is a huge improvement. The requirements are much clearer and easier to
implement than some versions from the past. I do not understand why R7 is still in this standard however. It appears
to be a requirement whose purpose is only to dictate HOW an entity must document its implementation of its
vegetation management program. Thus, I believe this requirement should be removed.
Consolidated Edison
Company of New York,
Inc.
Yes
In R5, the SDT should better define the phrase 'where a transmission line is put at potential risk due to the constraint.'
This is rather vague and could lead to inconsistent practices between utilities. Con Edison defines all undesirable
species on the full width of the ROW as 'potential risks to the transmission line' regardless of height or location at the
time of vegetation management. Interim corrective action should only be required when the potential risk is
approaching the imminent threat classification.
Orange and Rockland
Utilities, Inc.
Yes
In R5, the SDT should better define the phrase 'where a transmission line is put at potential risk due to the constraint.'
This is rather vague and could lead to inconsistent practices between utilities. ORU defines all undesirable species on
the full width of the ROW as 'potential risks to the transmission line' regardless of height or location at the time of
vegetation management. Interim corrective action should only be required when the potential risk is approaching the
imminent threat classification.
Florida Municipal Power
Agency (FMPA) and
Some Members
Yes
In the Applicability section, the use of the term “Other” should be changed to another term, such as Force Majeure,
since its purpose is not to include scope into the standard, but exclude scope from the standard.R4 uses the term
“responsible control center”, which seems inappropriate. Consider using the term “responsible operating entity”. The
M4 is simply a restatement of R4 without an example of types of evidence, e.g., such as voice recording, operator
logs, etc.R5, consider using a different term than “constrained”, which has other transmission related connotations.
Possibly “limited” or “hindered”.FMPA disagrees with a 3 year retention schedule for all of the Requirements and
Measures. R4 and M4 would seem to be supported by operator logs, voice recordings and such and three year
retention for such evidence is inconsistent with other standards.
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
ITC Holding
Yes
In the previous draft the VRF’s R6 and R7 were listed as Medium; and in the latest revision they are listed as High
VRF’s, what is the reason for this change or is this just a mistake?”Temporarily” should be removed from the
requirement (R5 pg.9) this will be an interpretation issue and doesn’t add to the requirement.
Northeast Power
Coordinating Council
Yes
NPCC participating members recognize the hard work the drafting team has done and appreciate the efforts to
address the issues presented. An issue seems to be a recurring theme with the advent of the MVCD. Some believe
that the eventual adoption of this standard with MVCD will result in the reduction of current trimming cycles and
clearance distances. Opinions have been expressed that this may result in increased vegetation contacts and trips.
After reviewing some of the MVCD distances, for example 3.12 feet at sea level for 345kV, some expressed the
opinion that this is much less than what typical trim practices are today, and may actually “lower” the bar for trimming
practices, and effectively allow a TO to trim less and reduce the margin of clearance.Requirement R1 discusses
encroachment. M1 bullet 1 states one way to violate encroachment would be:”Real-time observation of encroachment
into the MVCD...”From a practical standpoint what is meant here? Who would determine this and how would it be
done? The intent is certainly to avoid a sustained outage. However, if a TO was in the process of trimming after an
active growing season, and noticed a slight encroachment while trimming, would it be considered a reportable
violation? How would the RE measure compliance with avoiding something, with the absence of a sustained outage
reported? A statement should be added to the “Definition of Terms Used in Standard” section to indicate how terms
defined in the NERC Glossary and used in the standard are identified (for example capitalizing the first letters of the
term or using italics or bold font). To avoid confusion when a term might be used at the beginning of a sentence,
bolding or italicizing the term should be considered. The Guideline and Technical Basis section should be a separate
document, and not part of the standard (mentioned previously in question 8). It should be included in the Technical
Reference Document.Applicability 4.2.4--A fenced area of a switchyard, station or substation can have vegetation that
could present a potential risk to facilities. What is the reason for this exclusion, and the exclusion in Applicability
Section 5--Background paragraph 3 “...this Standard does not apply...to line sections inside an electric station
boundary.”Referring to our previous responses to questions 1 and 2 for Requirements R1, R2, and R3, what rating is
used? It is possible to operate above a facility’s normal rating for a prescribed time (for example a transmission line
may be operated above its normal rating but below its LTE rating for up to 4 hours). Operating at emergency ratings
should be considered. During emergencies transmission lines might be loaded to their emergency ratings, thus
increasing the sag, thus increasing the likelihood of a vegetation caused trip if the required clearances don’t take into
account the increased loading. Especially in an emergency loading scenario, operating into an avoidable potential risk
is very undesirable. Referring to FAC-003 - Table 2 - Minimum Vegetation Clearance Distances (MVCD), for 345kV
(line to line), 3.12 foot (assuming to ground) clearance is required at sea level. IEEE Std 516-2003 IEEE Guide for
Maintenance Methods on Energized Power Lines dated July 29, 2003, Table 5 (p. 20), lists the MAID (minimum air
insulation distance) for 345kV phase to phase equipment at altitudes below 900 meters (2953 feet) to be 2.88 meters
(9.45 feet) phase to ground. It is understood that MAID is “The shortest distance in air between an energized
electrical apparatus and/or a line worker’s body at different potential...”, but the clearance differences at the various
voltage levels seem very significant. If a figure is referenced in a requirement (R3), it would be preferable to have
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
that figure positioned within that requirement. If that is not possible, it should be explicitly stated where the figure can
be found. Requirement R5--Legal actions and other events that prevent vegetation maintenance work be included in
the Introduction Section 4.3.1. What does “interim corrective action” mean specifically? The requirement as written
needs to be made clearer. Without the Rationale box it loses its meaning (refer to the question 3 response).Interim
Corrective Actions are explained on page 28 of the separate Technical Reference Document, with examples such as
modifying the inspection interval, or limiting the loading on the line (effectively changing its rating) to minimize sag.
“Interim corrective action” should be defined and added to the Glossary.Are voltages referred to in the Standard
(Applicability Section) line to line or line to ground for ac systems? (345kV line to line is 199kV line to ground, below
the 200kV threshold in the standard). Are the voltages also applicable to DC equipment?
Xcel Energy
Yes
On page 6, in paragraph 5 ("Background"), we suggest enhancing the 3rd paragraph by inserting the words "Active
Transmission Right-of-Way", as follows: "...addresses vegetation management in the Active Transmission Right-ofWay along applicable overhead lines..." This change emphasizes that this does not apply to areas outside of the
Active Transmission Right-of-Way. Comments to Requirments and Measures Section (pages 7 -9)The term Minimum
Vegetation Clearance Distance (MVCD) should be explicitly defined as a new "definition" rather than explained in a
"rationale" box. Additionally, formalizing the definition would give weight to how "Table 2" is supposed to be used. As
it is currently drafted, the requirements of the standard don't refer to Table 2 at all. (i.e., - our understanding is that the
rationale boxes are for clarification and the requirements should be able to convey what is necessary on their
own.)MVCD - while we understand this as an 'engineering term', the terminology is difficult to convey since land
owners tend to question the need to do anything more than the "minimum". We recommend revising the term to
"Critical Clearance Distance (CCD)". M1 & M2 should be revised to insert the concept of "verified knowledge" (that is
used in R4). This is because M1 & M2 do not clarify whose real-time obseration it is referencing. As such, we
recommend stating "Real time verified knowledge of encroachement into the MVCD..." instead of just the term
"observation" to make it clear that a trained, knowledgeable individual is making this determination. Also, it may make
sense to turn "verified knowledge" into a defined term since it will be used in M1, M2 and R4. If it is not made a
defined term, then the meaning in M1 & M2 must be clarified in those sections (maybe a cross refefrence to as
defined in R4 and on page 15 will work). However, we think it is best to make it a defined term.R5: Rationale box:
consider enhancing the second sentence by adding the word "significant", to read "...avoid significant risk..."R5:
Requirement & Measure: consider adding exception language when the constraint is known to be longer than
"temporary". e.g. - stand offs can occur on right of ways that cross federal and tribal lands and the entity cannot force
the federal government to do do something.R6: Xcel Energy still believes the requirement in R6 that mandates an
annual inspection is too onerous and is at odds with the results-based approach of these revisions. Xcel Energy
urges the retention of the provision in the existing standard that allows the Transmission Owner to set the frequency of
inspection. In some areas of the country, annual inspections may not be adequate. Yet in other areas, a longer
inspection frequency may be perfectly reasonable and practical. Our point is that inspection frequency should not be
treated as if it were “one size fits all”. If treated this way, we feel this could pose a risk to reliability and is not likely to
be cost-effective. The Transmission Owner should be allowed some flexibility. However, if the drafting team
disagrees and determines that an annual inspection is to be mandated, Xcel Energy believes that an exception to the
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annual inspection is appropriate when a non-subjective advanced technology such as LIDAR is utilized to achieve
actual clearance distances. This places the Transmission Owner in a situation where it can rationally determine that
the objectively measured distances result in a situation where an inspection need not be performed within the next
year. It is suggested that R6 be revised to read as follows: Each Transmission Owner shall perform a Vegetation
Inspection of all applicable transmission lines at least once per calendar year, unless the Transmission Owner, based
on a non-subjective advanced technology, such as LIDAR, determines that a longer inspection period is
appropriate.R7: Revise the requirement to eliminate the superfulous language at the end of the sentence that says "...
to ensure no vegetation encoachments occur wihtin the MVCD", i.e., R7 would read as "Each Transmission Owner
shall execute a flexible annual vegetation work plan."
Independent Electricity
System Operator
Yes
Our comments to this point have focussed exclusively on the proof-of-concept for using the results-based criteria for
developing a reliability standard. We have one comment on the specifics of Requirement R7 and its Measure M7.
The rationale for M7 states that a flexible annual vegetation work plan allows for work to be deferred into the following
calendar year provided it does not have the potential to become an imminent threat. This will evidently require some
kind of assessment in each case. Will entities be expected to document those assessments as evidence in support of
its view that the associated vegetation did not have the potential to become an imminent threat, or would it be
sufficient to look at the outcomes of these decisions to defer items in the work plan - i.e. there were no imminent
threats and sustained outages? Finally, we applaud the drafting team for its efforts in developing this draft. The
industry has often commented about overly prescriptive requirements and I believe this draft has focused on the
“what” of the requirements and left the “how” up to the appropriate entities. In our view this draft, with its succinctly
stated requirements, represents an important first step in the right direction. Thank you.
Ameren
Yes
Page 9, M7 - what are the limits of flexibility in executing "a flexible annual vegetation work plan"?
Duke Energy
Yes
Please review the VRF Guideline because we believe that the VRF’s for R6 and R7 should possibly be changed to
“Medium” instead of “High”. They were “Medium” in the last draft of FAC-003-2.
Westchester County
Board of Legislators
Yes
Please see e-mail sent to [email protected]. Thank you.
Progress Energy
Carolinas
Yes
Progress Energy believes that the VRFs for R6 and R7 should be returned to “medium” since no singular “risk-based”
requirement in a defense in depth strategy should be depended upon to eliminate/prevent risk to grid reliability. In a
defense in depth strategy, no one specific “risk-based” or “competency” requirement should be “high” unless failure to
complete that singular requirement will result in an immediate “high” risk to grid reliability (if that is the case, then the
standard is not truly employing a defense in depth approach). Also, R6 and R7 (which have a zero tolerance) have no
differentiation between grid impacting facilities (IROL) and facilities primary impacting local customer reliability (i.e.,
radial lines to load, etc).
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North Carolina EMC
Yes
R4: The requirement to notify the responsible control center of an imminent threat may potentially result in confusion
at the control center if the transmission lines in question are not part of the control center's actively monitored grid. As
an example, NCEMC has a few short radial 230kV lines that fall under the requirements of this standard, but these
lines are not shown on the BA's control center system because they are downstream from a protective device located
at a tap off networked transmission lines. A vegetation-related outage on these lines would not result in any of the
transmission elements continuously monitored by the control center being outaged, and the operator receiving a call
notifying the imminent threat may not have any familiarity with the line section being identified, since it is not on their
system. If prompt action to respond to any imminent threat is the intended goal, why not consider making it a
significant part of the mitigating factors of an actual outage.
City of Tallahassee
(TAL)
Yes
Recommend deleting the “to avoid a Sustained Outage” in R1 and R2. Has a violation occurred if a momentary
(successful reclose) outage occurs but the TO did not “observe(s) vegetation within the” MVCD? While it may not
have to be reported on the quarterly report, Table 1 for the Lower VSL seems to suggest a violation of the MVCD has
occurred, even if it was not “observed” as “required” in the Guideline and Technical Basis.In the Guideline and
Technical Basis, the final paragraph for R1 and R2, line 3 contains an extra word “...encroachment is not be a
violation...”In the Guideline and Technical Basis, the third paragraph for R6, line 2/3 contains an extra word “...230kV
transmission at least once line during the calendar year.”
Cleco
Yes
Requirement 4:Recommend the SDT consider modifying to make it clear the requirement applies to threats within the
right of way (ROW).Requirement 4.3.1:Recommend adding human activities to the list of causes. Logging activities
are listed but other human activities such as private property owner tree care operations are not.
Exelon
Yes
See R6. Exelon prefers “annual” to “calendar” but notes the requirement runs counter to the results based approach
and could be interpreted to be inconsistent with R7.The Rationale for R6 is ambiguous and without justification
suggests shorter but not longer cycles are acceptable. If local factors can shorten a cycle, they could also increase it.
The Rational is in conflict with the prescriptive nature of the requirement.
NERC Staff (12 staff
members)
Yes
Standard Development TimelineThe Development Steps Completed section of the standard is incomplete. This
section should include the dates of previous postings. Draft 1 of revised standard was posted for stakeholder
comment from 10/27/08 - 11/25/08. Draft 2 of revised standard was posted for stakeholder comment from 09/10/09 10/24/09.Definitions of Terms Used in StandardThe definition of Active Transmission Right-of-Way is ambiguous and
subject to interpretation. This definition need to be revised to add clarity. It is unclear what “active transmission
facilities” are. In the gray box, the SDT should explain what “active portions of corridors” are, and how that is different
than the “land that is occupied by active transmission facilities.” The terminology should be consistent. The example
should state whether the width is the portion that has been cleared or should be cleared and if it was not maintained
and should have been. The SDT should explain the reference to the National Electrical Safety Code in the gray box,
and how it differs from the IEEE clearances. In addition, the team should explain why the Table 2 clearances set forth
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in the standard itself are not referenced. The examples in the “inactive portion” suggest that there are active
transmission facilities (see references to conductors and circuits). The SDT should provide the rationale for excluded
them from vegetation management. While vegetation is permitted to exist at the corridor edge, the SDT should
address why there is no obligation to maintain it. The revised definition of Vegetation Inspection does not seem
necessary. It appears that the SDT is using the definition to set an expectation for enforcement by adding “which may
be combined with a general line inspection.” If both vegetation and general line inspections are to occur concurrently,
there should be minimum background requirements to perform such inspections. We recommend that the last portion
of the draft definition be moved to the Application Guideline section so the definition of Vegetation Inspection should
be “The systematic examination of vegetation conditions on an Active Transmission Line Right of Way.”The team
should consider making Minimum Vegetation Clearance Distance a defined term.Effective DatesThe effective date for
Ontario needs to be tied to the effective date in the U.S.With respect to the second exception, the team should provide
the rationale behind the exception for the effective date for “existing transmission line operated at 200kV or higher that
is newly acquired by an asset owner and was not previously subject to this standard”. All existing transmission lines
operated at 200 kV or higher are currently subject to vegetation management. Please explain why a new owner would
get an exception for this.Based on the wording in the Exceptions section, it appears that some lines in the US could be
brought into this standard prior to regulatory approval. (i.e. Lines operated below 200kV, designated by the Planning
Coordinator as an element of an IROL or as a Major WECC transfer path, become subject to this standard 12 months
after the date the Planning Coordinator or WECC initially designates the lines as being subject to this standard. An
existing transmission line operated at 200kV or higher that is newly acquired by an asset owner and was not
previously subject to this standard, becomes subject to this standard 12 months after the acquisition date of the
line(s))ObjectiveThe purpose of this standard should not be limited to outages that lead to Cascading, but prevention
of all vegetation related outagesApplicabilityThis standard should apply to Generation Owners.The term Facilities is
defined to exclude those in a fenced area of a switchyard, station or substation. The SDT should provide the basis for
the exclusion.Footnote 1 needs to be clarified. It is too cursory.The “Other” section should not be included in this
section. It is the expectation that the Compliance Enforcement Authority will not expect the Transmission Owner to
prevent tree contacts that the TO could not prevent. This might be better suited in the Application Guideline section.In
the “Other” section, the SDT should provide rationale for why the standard is not intended to address “human
errors”.The SDT might consider rewording the “Other” section as:”This Standard shall not apply in circumstances
where a requirement of this Standard was not complied with due to Acts of God, flood, drought, earthquake, major
storms, fire, hurricane, tornado, landslides, logging activities, animals severing trees, lightning, epidemic, strike, war,
riot, civil disturbance, sabotage, vandalism, terrorism, wind shear, or fresh gales that restricts or prevents performance
to comply with this Reliability Standard's requirements, so long as the non-compliance was not caused by the fault or
negligence of the Transmission Owner.”The team should provide justification for the applicability criteria they have
selected; specifically why a 200 kV cutoff was chosen.The team should provide justification for eliminating fall-ins from
outside the ROW.BackgroundAs a general comment, the background section seems repetitive.The fourth paragraph
of the background section notes that this standard is not intended to prevent customer outages due to tree contact
with lower voltage distribution systems. It is clear from the applicability section that this pertains to 200 kV and higher,
although the standard contemplates that some lower voltage facilities could be subject to the standard. The SDT
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should address whether this paragraph also address customer outages due to tree contacts with respect to 200 kV or
higher facilities.Requirements R1 and R2:R1If an auditor were to assess compliance with R1, they would need to have
the list of conductors that were associated with an IROL or a Transfer Path. This list should be identified in the list of
evidence that must be retained.R1 & R2 In the Rationale box, the term “a proven transmission design method” is
used. Please describe what this refers to, and whether these refer to the IEEE minimum clearances. The SDT should
state what the method was and what changes, if any, were made to it.The SDT should address why the requirements
only reference line conductors and not transmission facilities or transmission lines (the VSLs refer to transmission
lines).The word “encroaching” should be replaced with another word/phrase that clearly defines the concept for
compliance purposes. The word, “encroach” could be interpreted differently by different people (how close can
vegetation grow before it enters the MVCD and is it a violation of R1/R2 - is it 2”, 2’, 10”, 10’?), whereas the word
“enter” is explicit.Guidance is offered in the Guideline section of the standard that implies that all TOs should retain
this evidence, yet the evidence is not identified anywhere in the Measures or evidence retention sections of the
standard.We suggest adding the phrase, “of its” to clarify that the TO is only responsible for facilities it owns. “In
addition, the Transmission Owner should maintain detailed records of the findings of its planned inspections. This
documentation constitutes evidence that the Transmission Owner had no encroachments into the MVCD Table
distances.”Immediately after the phrase MVCD, we suggest including the text “as specified in FAC-003-2
Transmission Vegetation Management Table 2 - Minimum Vegetation Clearance Distances (MVCD). Table 2 is not
referenced in any of the requirements. If you require entities to use the MVCD as stated in Table 2, then this should
be referenced in at least R1 and R2.M1 & M2Overall, it appears that these measures are asking for evidence of noncompliance. The initial item under M1 & M2 (shown below) should be rephrased with the addition of the words “verbal
or written report of a,” otherwise the measure doesn’t seem as though it could be used objectively. In addition, the
words Real-time should be removed, as they ad confusion to the issue.”Verbal or written report of a observation of
encroachment into the MVCD, or”The phrase “Multiple Sustained Outages on an individual line, if caused by the same
vegetation, will be reported as one outage regardless of the actual number of outages within a 24-hour period” should
be changed to a footnote that reads “Consider Multiple Sustained Outages on an individual line, if caused by the same
vegetation, as one outage regardless of the actual number of outages due to the same piece of vegetation”Momentary
outages due to vegetation are also a violation of R1. Momentary outages from tree contacts may not result in a
sustained outage but are evidence of a tree within the MVCD. The requirement should not be limited to only
sustained outages. Consider this scenario: An entity self-reports a violation of the standard. Does that mean that if
there is no actual "real-time observation" or a "Sustained Outage" there is no violation? Who must do the observing?
Please explain.Requirement R3 Consider this scenario: A Sustained Outage occurs on a location that was not
considered and therefore was not part of the TO’s TVMP. Would this result in a violation simply because the location
was not considered when the entity developed a TVMP?Requirement R4 Each requirement should identify “who shall
do what under what conditions, for what reliability outcome.” R4 has no identified reliability outcome. What is the
reason for making a prompt notification? Is it to give the real-time system operator information on which to develop
and implement an action plan if there is an outage on the line with the imminent threat? Then that should be stated in
the requirement. R4 contains explanatory information. The sentence “A vegetation imminent threat condition is one
which is likely to cause a Sustained Outage at any moment” should be moved to the blue box.Please explain what
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“verified knowledge” means. The Rationale section does not really address this. While this is in the Guidelines and
Technical Basis section, it defines it as “implies reliable confirmation.” This should be clarified and put in the
measures section.”Imminent threat” should be defined so that it does not evolve into an enforcement issue.”Notify the
responsible control center” should be clarified so that it does not evolve into an enforcement issue.Application
Guideline for R4 should contain provisions in the imminent threat procedure for notification of the land owner.M4
should provide examples of acceptable evidence.Requirement R5 This requirement does not include a reliability
outcome. The requirement should be rewritten to include a reliability outcome.Requirement R6 The Rationale for R6
is that one year “seems to be reasonable.” The SDT should address how this relates to the practice in place now, and
whether it is consistent with current practice or is more or less than current practice. If inconsistent, the SDT should
provide an explanation.The Rationale states the TOs should consider other factors that could warrant more frequent
inspections. If so, the SDT should explain whether we are requiring them to do so if such factors exist.This
requirement does not include a reliability outcome. The requirement should be rewritten to include a reliability
outcome.Requirement R7 R7 is ambiguous; it is not clear how this could be enforced objectively. The rationale for the
“flexible” plan indicates that the owner can delay work as long as it will not pose an “imminent threat.” The SDT
should explain what the Compliance Enforcement Authority would look at to determine that the work that was delayed
was not causing an “imminent threat.” The SDT should address whether it would ever be acceptable to delay work on
a critical line (covered under R1).In Requirement R7, please explain what “execute a work plan” means. Did the SDT
mean implement a work plan? As drafted, it could be read to just have one in place. The SDT should explain what
“flexible” means. Does it mean there will never be a FAC-003 violation if you fail to implement the plan? The
Rationale says the work can be deferred if it does not have the potential to become an imminent threat. Please
explain. Corresponding clarification changes should be made to the VSLs for this requirement.Either M7 or the
evidence retention for M7 needs to include the annual work plan. Without that the Compliance Enforcement Authority
can’t determine if the plan was executed. The VSLs for R7 imply that the entire annual plan will be accomplished. . .
not a “flexible” amount of the plan - the VSLs don’t line up with the use of the word “flexible.”According to the VSL
Guidelines the VSLs should be stated in language that identifies the degree of noncompliance in language that
identifies the amount that was noncompliant, rather than the amount that was compliant. VSLs for R6 and R7 are
stated in terms of the % of the required performance that was compliant and should be rephrased. GuidelinesThe
following guidance is offered in the Guideline section of the standard:Documentation or other evidence of the work
performed typically consists of signed-off work orders, signed contracts, printouts from work management systems,
spreadsheets of planned versus completed work, timesheets, work inspection reports, or paid invoices. Other
evidence may include photographs, work inspection reports and walk-through reports.Documentation is required when
the annual work plan is adjusted or not completely implemented as originally planned. The reasons for the deferrals or
changes and the expected completion date of postponed work should be documented.This implies that all TOs should
retain this evidence, yet the evidence is not identified in nearly this level of detain in the Measures section of the
standard. In addition, no part of the requirement or measure is clear in indicating that documentation is required to
support the need for a work plan adjustment. Evidence Retention The evidence retention periods specified don’t
reflect the guidance in the SDT Guidelines. Should the evidence retention be the later of three years or three years
from the last audit? The second paragraph should be stricken because it seems to contradict the first paragraph
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retention period.VSLsThe SDT should verify that the VSLs for Requirement 3 are properly calibrated.Administrative
ProcedureThe Administrative Procedure does not require prompt reporting of sustained outages; rather it requires
only a quarterly report. This appears to be less stringent than the current requirements as employed today.The SDT
should explain what “blowing together” means, and how this is different from a tree that grows into a
line.FootnotesFootnote 1 should be deleted or modified. It is only relevant in explaining the proposed modifications to
the standard. In footnote 4 the word, “substantially” adds ambiguity.Guideline and Technical BasisIn the Guidelines
and Technical Basis section, it states “Requirements 1 and 2 state if the TO observes vegetation within the distances
prescribed in FAC-003 - Table 2 it is in violation of this Standard.” This is actually in the Measures 1 and 2 and not the
requirements.General commentsThere seems to be a lot of information not captured in the Requirements but rather
are in various other sections. The SDT should clearly delineate whether these other sections are considered part of
the Standard or just informational.With the next posting of the standard, the drafting team should include the following
four points for stakeholder review:1. Justification for selection of the applicable lines. 2. Table listing each FERC
directive and stakeholder issue (from the Issues Database) associated with the standard and identification of how the
team addressed each of these3. Table listing each VRF and identification of how the proposed VRF meets both
NERC criteria for setting VRFs and FERC’s five Guidelines for approving VRFs4. Document identifying how the
proposed VSLs meet both NERC criteria for setting VSLs and FERC’s four Guidelines for approving VSLs.There is a
significant concern with the use of the Gallet equations in this standard. This standard eliminates Clearances 1 and 2
from the previous version and replaces it with a single Minimum Vegetation Clearance Distance (MVCD) based on the
Gallet equations. This approach reflects the most basic lowest common denominator and significantly lowers the bar
versus the performance expected from the existing standard. Further, it would not appear that responsible entities
would use the Gallet equations as the basis for the development of the vegetation management program.
Additionally, whereas the multiple clearance zones provide an indicator of proactive vegetation management, the
current proposal does not provide an equivalent demonstration of proactive performance. This approach appears
inconsistent with Order 693 and the presentation of NERC standards to provide a defense in depth strategy, which is
a fundamental outcome of the results-based standards process. Order 693 states in P24 that the “reliability mandate
of Section 215 of the Federal Power Act....contemplates the prevention of incidents, acts, and events that would
interfere with the reliable operation of the Bulk Power System.” The SDT should consider adding more clarification to
the draft standard and white paper describing the building blocks for determining how much vegetation management
(trimming) needs to be performed based upon growth rate of vegetation and the time between trimmings to reflect a
proactive approach.The SDT should consider the impact of moving the reporting requirement in the existing standard
to the compliance section of the new standard. The team should consider the reporting of this activity on an exception
basis within a pre-defined timeframe following the event. This approach would provide more timely awareness to the
Regional Entity and NERC of an event than the quarterly reporting expectation, and provide opportunities for
identification and implementation of mitigating strategies in a more timely manner. While this approach removes an
administrative type requirement from the standard that is believed to provide a deterrent to responsible entities, the
increased timeliness of reporting in an exception basis would provide greater benefit to the effort to maintain
reliability.Transmission Line is a defined term. The SDT should consider using this term in place of “transmission
line.”The report identified in the administrative section of draft 3 of FAC-003 is really a “Periodic Data Submittal” used
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to assess compliance and does not belong in an administrative section of the standard - it belongs in the compliance
section of the standard. “Periodic Data Submittals” is one of eight different compliance monitoring and enforcement
processes that may be used to monitor and assess compliance. The eight processes are identified in the Uniform
Compliance Monitoring and Enforcement Program of the North American Electric Reliability Corporation and should
not be mixed in with other processes or procedures. Each standard must list the appropriate processes in the
compliance section of the standard so that there is a clear understanding of the purpose of the data submittal.As
drafted, FAC-003-2 applies only to Transmission Owners. It also should apply to Generator Owners. The SDT should
explain whether the issues brought forward in the GO/TO Report been considered and are addressed as part of this
revision.Please update the mapping document so that it compares the last version of the approved standard to the
latest proposed version of the standard so that it is easy to compare the proposed standard to the standard that is in
force now.
Utility Risk Management
Corporation
Yes
Suggested Improvements to M1. and M2.The purpose of Requirements R1 and R2 is to require the prevention of
vegetation encroachments within the MVCD. As made clear in the background and remaining FAC 003-2
requirements, the overarching intent of FAC 003-2 is to prevent sustained outages caused by vegetation that could
lead to cascading. However, both M1 and M2 include real-time observations of encroachment into the MVCD as an
automatic violation of R1 or R2, respectively (even though the violations may not result in penalty or fine). This is
inconsistent with the “defense in depth” goal sought by the committee, as a real time observation using new
technologies may in fact demonstrate that the Transmission Owner is in fact aggressively managing vegetation to
meet the MVDC requirements and is discovering new encroachments and remediating them quickly and effectively
and thereby is not in violation of the standard.Similar to imminent threats, remediation procedures should be permitted
for encroachments as well and serve to make clear the observation is not automatically a violation. Classifying a realtime observation of an encroachment automatically as a violation of R1 or R2 penalizes a Transmission Owner for
identifying vegetation threats, which are less severe than imminent threats. Under Requirement R4, the transmission
owner is permitted to take appropriate actions to alleviate an imminent threat through short term corrective actions
upon observation of any vegetation that is near to or is encroaching into the MVCD. (See FAC-003-2 Guideline and
Technical Basis, Requirement R4). Considering the allowance for remedial action under Requirement R4 when facing
a condition that is “likely to cause a Sustained Outage at any moment,” it seems excessive to qualify a real-time
observation of an encroachment as a violation of R1 or R2. We suggest a better approach is to modify M1 and M2 to
allow for remedial action. Or, in the alternative, the standard should clarify that observations of encroachments using
software-enabled technology, such as LIDAR coupled with work order management systems, do not constitute a “real
time observation of an encroachment.” First, by modifying M1 and M2 to allow for remedial action as suggested below
will deal with the concern we raise:M1. Evidence of violation of Requirement R1 is limited to: o Real-time observation
of encroachment into the MVCD which is not mediated in accordance with R4. o ... M2. Evidence of violation of
Requirement R1 is limited to: o Real-time observation of encroachment into the MVCD which is not mediated in
accordance with R4. o ... In the Alternative, “Real-Time Observation” Should be Clarified. As noted above, a realtime observation of an encroachment is evidence of a violation of Requirements R1 and R2. Observations in real time
mean “an actual field observation or measurement of the conductor-to-vegetation distance and not a calculated
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determination of relevant positions.” (See FAC-003-2 Guidelines and Technical Basis, Requirements R1 and R2)
Given the current definition, it is not clear observations using software-enabled LiDAR would trigger violations and
thereby would discourage the Standard’s emphasis on preventing sustained outages or Cascading due to grow-ins.
This may result in penalties for registered entities that are engaged in good faith activities to prevent sustained
outages. The meaning of “real-time observation” should be clarified as to remove any adverse incentives for
vegetation inspection and management. To implement this suggestion as an alternative to allowing remediation to
prevent an observation from being an automatic violation, the definition could be reworded to state:”Real-time
observation” means an actual field observation or measurement of the conductor-to-vegetation distance which is not
performed under the regular Vegetation Inspection of Requirement R6 or annual vegetation work plans in accordance
with Requirement R7. Such observations do not include calculated determinations of relative vegetation positions.
Conclusion:Adopting one or both of these proposed changes would help R1 and R2 measures more fully meet the
goal of preventing overgrown vegetation and systemic failures triggered by flash over, as stated in the background
section on page 6 of FAC-003-2. The current M1 and M2 use of real-time observations conflicts with the expectation
that utilities engage in “defense in depth” measures. As the guidelines conclude regarding Requirements R1 and R2,
the Transmission Owner is expected to have a cohesive vegetation management program for managing vegetation in
such a manner as to maintain separation between conductors and vegetation. This is to function in conjunction with
the imminent threat procedure to facilitate interim corrective action. “However, brief encroachments by falling
vegetation are not considered to be a violation.” Making the changes suggested above - coupled with the existing
requirement that the utility mitigate an observation in accordance with the utility TVMP through a response schedule thereby advance the goals of the standard and take away an impediment to aggressive defense in depth.
SERC OC Standards
Review Group
Yes
The requirements (R6 and R7) for inspections and the performance of work plans are part of a defense-in-depth
approach and as such the TO is not depending on singular requirements to prevent sustained outages, therefore, the
VRF for R6 and R7 should remain medium not high. We applaud the attempt to improve the readability and ultimate
comprehension of reliability standards by changing to this new template. We have included some comments also
made by the SERC Vegetation Management Subcommittee (VMS).”The comments expressed herein represent a
consensus of the views of the above named members of the SERC OC Standards Review group only and should not
be construed as the position of SERC Reliability Corporation, its board or its officers.”
SERC Vegetation
Management Subcommittee
Yes
The requirements (R6 and R7) for inspections and the performance of work plans are part of a defense-in-depth
approach and as such the TO is not depending on singular requirements to prevent sustained outages, therefore, the
VRF for R6 and R7 should remain medium not high.
GCPD
Yes
The standard should include only R1, R2 and the Clearance Table. Everything else should be in guidelines as to how
you might comply with the standard. If R3 thru R7 remain in the standard then it is virtually the same as it exists today,
just put in a different order.
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CenterPoint Energy
Yes or No
Question 13 Comment
Yes
The term "Active Transmission Line Right-of-way" (ATLROW) is not defined in sufficient detail in the Definition of
Terms Used in the Standard section to know how to apply it to the Requirements and Measures. The Technical
Reference merely depicts the relative position of energized conductors, but it does not show a graphical determination
of the limits of the ATLROW. The ATLROW is missing a definable and determinable width in its current definition
within the Standard which makes it an arbitrary term and does not allow for a clear and measurable expected outcome
of each requirement. In several sections, the Standard relies on the specific determination of the physical width of the
ATLROW to determine applicability of the requirements. The Vegetation Inspection definition refers to “on” an
ATLROW. The Background section refers to “outside” the ATLROW. Table 1 refers to “within” and “on” the
ATLROW. M1 and M2 refer to “inside” the ATLROW. R3 and M3 refer to “on” the ATLROW. The Administrative
Procedure refers to “inside and/or outside” and “within” the ATLROW. The Guideline and Technical Basis section
refers to “on or near” the ATLROW and the “limited” ATLROW “width”. It also says that, “The Transmission Owner
should, therefore, endeavor to maintain its ATLROW to the full extent of its legal rights at all times in all cases.” Since
the Standard does not currently define how a Transmission Owner is to determine the specific boundaries of the
ATLROW, it would appear that the Transmission Owner is to make that determination on a case by case basis at its
discretion. Should that not be the intent, we recommend the definition for the ATLROW to be, “A strip or corridor of
land or aerial space that is occupied by energized transmission conductors with its operational clearance limits defined
by the Transmission Owner’s specific legal rights but in no case less confining than the MVCD applied to the
movement of the conductors within their Rating and Rated Electrical Operating Conditions.” This definition contains
sufficient detail to determine the physical limits of the ATLROW, and it allows for vegetation management to apply
within the full extent of the legal rights of the Transmission Owner while requiring a minimum area for vegetation
management in undefined ROW’s to ensure Sustained Outages are minimized.M1 contains a reference to “real-time
observation of encroachment into the MVCD” but does not explain who is to make the observation and where it is to
be documented. If this is to be done by the Transmission Owner, then perhaps it should be a Measurement under R6
and recorded under M6.The language in R6 refers to inspecting “transmission lines” and Table 1 for R6 refers to
inspecting “ROW”. Both areas should use consistent terminology.M1 and M2 have the potential for double jeopardy
when a Sustained Outage occurs because the Violation Severity Level has an entry for an MVCD encroachment
(which causes the outage) and another sister entry for the type of Sustained Outage. Some additional clarity in the
application of M1 and M2 is necessary.R5 should include the exception stated in the Rationale text box to add clarity
to the Requirement. R5 should read, “Each Transmission Owner shall take interim corrective action when it is
temporarily constrained from performing planned vegetation work, where a transmission line is put at potential risk due
to a constraint, except where the risk is avoided by implementing an alternate work methodology.” In the Guideline
and Technical Basis section for R1 and R2 (page 15), there is a reference to records of “planned inspections” and
“evidence” for no encroachment into the MVCD. This reference should be moved to R6 where the inspections are
required. If R6 is intended to provide evidence for M1, then that should be stated in R6.In the Guideline and Technical
Basis section for R6, the reference to the VSL calculation units and the example units should be consistent-the
example should use “line miles”, not just “miles”.Table 2 contains several “*” in the voltage column that are not
defined.In the Technical Reference on page 21, the following sentence should be deleted, “If constraints cannot be
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
overcome and if design clearances are sufficient, an exception to the Transmission Owner’s 10-foot guideline might
be made.” The Technical Reference should not provide examples of granting exceptions as they may be
misinterpreted as an endorsement by NERC to increase the planting of trees near and under transmission lines
without taking into account several other factors such as ROW access, changing design conditions, future line
additions and rebuilds. The inclusion of modifications to the wire zone on page 24 regarding the wire-border zone
model should be re-examined to be sure they are specific to an environmental conservancy requirement while
allowing for construction and inspection access as needed.In the Technical Reference on page 22 under Planning and
Implementation, delete the sentence, “While designed primarily with transmission systems in mind, t is also applicable
to distribution projects.” The Standard should not imply its applicability to distribution systems since it is intended only
as a transmission standard.In the Technical Reference, the last sentence on page 26 starting with “Appropriate
actions...” should be moved to R5 where it applies. In general, the proposed FAC-003-2 has gone FAR beyond what
was contemplated by the Commission in FERC Order 693 and equates to a total re-writing of the Standard for no
apparent reason. The Commission's determination dealt with the following areas: (1) applicability; (2) inspection
cycles; and (3) minimum clearances on National Forest Service lands. For instance in Paragraph 729, the
Commission states, “As proposed in the NOPR, the Commission approves Reliability Standard FAC-003-1 with no
proposed modification on the issue of clearances. The Commission reaffirms its interpretation that FAC-003-1 requires
sufficient clearances to prevent outages due to vegetation management practices under all applicable conditions....”
Rewriting the minimum clearances introduced a new set of confusing definitions, and further burdens the
Transmission Owners with new documentation requirements with little if any benefit when compared to the Clearance
2 concept in the existing Standard.A preferred approach would have been to incorporate the following few items into
the existing Standard: (1) the RC versus the RRO; (2) the designation of a specific inspection frequency; (3) the Gallet
equation; and (4) the applicability to National Forest Service lands.
Ad Hoc Group subteam
formed to review draft
standard
Yes
The wording in R7 is troublesome. We believe that the process for developing the annual work plan is imbedded in
R3. As discussed in question 2, demonstrating capability to actually perform those actions necessary to ensure no
vegetation encroachments occur within the MVCD is the primary concern. Deferring such work into the next calendar
year appears contrary to this concern and neutralizes the defense-in-depth concept by diminishing the imminent threat
requirement of R4 to a primary means of defense. While we don’t want to incent vague annual work-plans, we also
don’t want to remove the imperative that the work must be done.
Nebraska Public Power
District
Yes
Under section 4.3.1 add in ice storms as one of the force majeure events. This type of event may impact many TOs
and should be included.
Oncor Electric Delivery
Yes
Use of the Gallet equation to determine the minimum gap between vegetation and conductor to prevent sparkover
seems to be appropriate. No utility should be managing to this distance but developing a distance beyond this would
be arbitrary. This is a reliability standard not a worker safety or vegetation management practices standard. As
Federal agencies and other entities are interpreting the Standard to limit normal vegetation management efforts, the
FERC should develop and adopt an overarching memo allowing utilities to maintain vegetation under any agency
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
jurisdiction as a utility manages vegetation along the entire right-of-way corridor.
Western Area Power
Administration - Upper
Great Plains Region
Yes
WAPA - UGPR would like to see "ice storms" specifically mentioned in Section 4.3.1. Having additional clarification as
to what is considered a "major storm" would also be helpful.
Bonneville Power
Administration
Yes
We believe the minimum vegetation distances are very granular and nearly un-measurable in real life. When a person
considers the table to be a list of minimums it seems that the regulated entities, or land owners would want the
distances to be as close to the wire as possible. We would not want a non-technical manager to believe that any small
distance outside of the noted distances is ok.
Omaha Public Power
District
Yes
We have concern over establishing proof an outage is exempt due to fresh gale. A fresh gale, or even a localized
thunderstorm, can easily produce wind gusts that exceed the lines rated capacity for blow out. If an outage occurs
under these conditions, the standard provides an exemption under Section 4.3.1, but there is often no way to
empirically prove conditions exceeded the lines normal operating conditions. How should a utility handle these
situations?
Southen Company
Yes
We have concern over establishing proof an outage is exempt due to fresh gale. A fresh gale, or even a localized
thunderstorm, can easily produce wind gusts that exceed the lines rated capacity for blow out. If an outage occurs
under these conditions, the standard provides an exemption under Section 4.3.1, but there is often no way to
empirically prove conditions exceeded the lines normal operating conditions. How should a utility handle these
situations? Please note there is a typographical error in the third paragraph on page 15, “...encroachment violation is
not be a violation...”We would like to thank the Standard Drafting Team for their hard work. The time and effort they
have put into developing this standard is obvious.
Dominion
Yes
While not related solely to this standard, we suggest that no future standard be effective until approval has been
granted by the applicable regulatory authority. Having an effective date that differs from the mandatory date is causing
confusion/chaos on the part of the applicable registered entity(ies). With the current process, it is possible to have a
standard that is mandatory conflict with a superseding newer version (or a new standard that contains requirements
meant to supersede those in the mandatory standard). Applicable entity(ies) may not be able to comply with both
when this is true, and may not be able to take steps necessary to transition from mandatory requirement to
superseding requirement without becoming non-compliant.
Westchester County
Board of Legislators
1.
Bulk Electricity System NOPR – FERC recently issued a notice of proposed rulemaking to revise the definition of
“bulk electric system” (BES) to include all transmission facilities with a rating of 100 kV or above. 130 FERC ¶ 61,204
(Mar. 18, 2010). If approved, such revision might significantly increase the amount of transmission facilities subject to
standard FAC-003. In areas with dense residential and commercial development, this revision will exacerbate
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
existing conflicts between homeowners, municipalities, affected transmission owners (TOs), and regulating agencies.
As described in comments below, compliance with the existing or perceived requirements in FAC-003 has produced
numerous conflict in areas of dense development and narrow rights-of-way between homeowners, TOs, and
regulating agencies because of economic, environmental, and aesthetic impacts. If FERC adopts the proposed BES
definition, then the FAC-003 standard (current 001 and draft 002) should be extensively reviewed by the drafting
team to evaluate the amount of affected facilities and the need for standard revision to avoid as far as possible further
conflicts.
2.
“Background” Section 5 – The draft adds a new section titled “Background” (Section 5). The existing standard FAC003-1 does not include a similar section. This narrative section appears to provide interpretation on the rationale for
a vegetation management reliability standard and to clarify the standard applicability. This discussion may be more
appropriate in the accompanying technical reference, which describes and clarifies standard FAC-003. While
identifying overgrown vegetation as cause of major outages and operational problems, this section fails to state that
many other causes can lead to Cascading events. Indeed, of the many NERC reliability standards, only one, FAC003, concerns vegetation management. While the August 2003 blackout was initiated by a tree contact, there were
numerous other factors that caused this power outage to spread to over a dozen states. Section 5 should therefore
be revised to clarify that FAC-003 is only one of many factors that can lead to a large-scale grid failure.
3.
Standard Applicability Across Land Uses – Standard FAC-003-1 and the proposed draft do not vary in applicability,
even though the types of land uses within and adjacent to transmission facilities vary widely. Among certain land
uses, such as dense residential development, this can lead to substantial conflict between the TO and adjacent
landowners, especially concerning environmental, aesthetic, and economic impacts. The Westchester County Board
of Legislators identified such problems in its recent resolution, available at
http://meetings.westchesterlegislators.com/Citizens/FileOpen.aspx?Type=4&ID=2828&AgencyName=WestchesterCo
unty .
Notwithstanding the reliability imperative expressed by Congress in enacting Section 1211 of the 2005 Energy Policy
Act, the implementation of reliability standard FAC-003 has produced significant challenges for all parties in suburban
areas. In particular, surburban area homeowners, often on small parcels, that abut or are near to transmission rightsof-way have experienced dramatic impacts upon their properties and property values when TOs exercise their “full
extent of legal rights at all times and in all cases”, as stated on page 18 of the draft. Therefore, the development of
standard FAC-003 must consider this backdrop and select requirements and accompanying text that provide some
balancing of electric reliabilty with environmental and economic impacts. As presently written, the draft does not
acknowledge such balance.
4.
Varying Conditions – Requirement R1.2.1 of Standard FAC-003-1 identifies numerous local conditions that should be
considered in determining appropriate clearance distances. This balanced evaluation of factors should be retained in
FAC-003-2.
5.
Full Legal Rights – The draft encourages TOs to exercise full legal rights at all times and in all cases. This language
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Consideration of Comments on Draft 3 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 13 Comment
is not included in present standard FAC-003-1. As noted above, electric reliabilty and TO compliance with FAC-003
must not preclude other important societal factors. The language encouraging full exercise of legal rights should be
removed from the draft.
KCPL
Yes
Requirement 4:
Recommend the SDT consider modifying R4 to make it clear the requirement applies to that which is within the Right
Of Way (ROW) for the transmission facility. Obviously, the Transmission Owner has no authority or control beyond
the ROW. This is also an audit concern regarding “triggering” this requirement on a subjective evaluation of
“imminent threat”. How does a Registered Entity, Regional Entity or Auditor determine what constitutes an “imminent
threat”? This will be a matter of opinion and makes this a difficult requirement regarding compliance when a
difference of opinion arises.
In addition, as proposed, this requirement does not address the need to take immediate corrective actions to mitigate
an imminent threat. The previous FAC-003 Standard included taking action to remove the “imminent threat” which is
not included in this proposed version 2. What was the intention of the SDT in this regard? Recommend the SDT
consider language to include taking action to remove the imminent threat.
In the “Guideline and Technical Basis” section:
1. Under R6: believe the word “per” is missing in the first sentence of the third paragraph between “once (per) line”.
2. Under R7: concerned regarding the use of words such as “never”, “at all times”, and “in all cases” in the bulleted
items with paragraph 6 in this section as a guiding document. This is the kind of material that is creeping into
compliance audits and recommend softening this language.
Violation Severity Levels
1. Do not agree with the zero tolerance for encroachments that do not result in a service interruption for R1 and R2.
2. Not notifying the Control Center should be a HIGH and not removing the imminent threat should be a SEVERE.
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FAC-003-2 — Transmission Vegetation Management
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. SC approved SAR for initial posting (January 11, 2007).
2. SAR posted for comment (January 15–February 14, 2007).
3. SAR posted for comment (April 10–May 9, 2007).
4. SC authorized moving the SAR forward to standard development (June 27, 2007).
Proposed Action Plan and Description of Current Draft
This is the second posting of the proposed revisions to the standard in accordance with ResultsBased Criteria.
Future Development Plan
Anticipated Actions
Drafting team considers comments, makes conforming changes, and
requests SC approval to proceed to formal comment and ballot.
Anticipated Date
June –July 2010
Recirculation ballot of standards.
July-August 2010
Receive BOT approval
August 2010
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
Effective Dates
1. First calendar day of the first calendar quarter one year after applicable regulatory
authority approval for all requirements
2. First calendar day of the first calendar quarter one year following Board of Trustees
adoption unless governmental authority withholds approval
3. First calendar day of the first calendar quarter that is at least one year following Board of
Trustees adoption
Exceptions:
A line operated below 200kV, designated by the Planning Coordinator as an element of
an IROL or as a Major WECC transfer path, becomes subject to this standard 12
months after the date the Planning Coordinator or WECC initially designates the lines
as being subject to this standard.
An existing transmission line operated at 200kV or higher that is newly acquired by an
asset owner and was not previously subject to this standard, becomes subject to this
standard 12 months after the acquisition date of the line.
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
Version History
Version
1
Date
TBA
Action
1. Added “Standard Development
Roadmap.”
Change Tracking
01/20/06
2. Changed “60” to “Sixty” in section
A, 5.2.
3. Added “Proposed Effective Date:
April 7, 2006” to footer.
4. Added “Draft 3: November 17,
2005” to footer.
1
2
April 4, 2007
Draft 4: June 16, 2010
Regulatory Approval — Effective Date
New
3
FAC-003-2 — Transmission Vegetation Management
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary. When this standard has received ballot approval, the text
boxes will be moved to the Guideline and Technical Basis Section.
Vegetation Inspection
The systematic examination of vegetation
conditions on a maintained transmission line Rightof-Way which may be combined with a general line
inspection.
Draft 4: June 16, 2010
The current glossary definition of this NERC term is
modified to allow both maintenance inspections and
vegetation inspections to be performed concurrently.
Current definition of Vegetation Inspection: The
systematic examination of a transmission corridor to
document vegetation conditions.
4
FAC-003-2 — Transmission Vegetation Management
Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-2
3. Objectives:
To improve the reliability of the electric Transmission system by
preventing those vegetation related outages that could lead to Cascading.
4. Applicability
4.1. Functional Entities:
Transmission Owners
4.2. Facilities: Defined below, including but not limited to those that cross lands owned by
federal 1, state, provincial, public, private, or tribal entities:
4.2.1.
Overhead transmission lines operated at 200kV or higher.
4.2.2.
Overhead transmission lines operated below 200kV having been identified as
included in the definition of an Interconnection Reliability Operating Limit
(IROL) under NERC Standard FAC 014 by the Planning Coordinator.
4.2.3.
Overhead transmission lines operated below 200 kV having been identified as
included in the definition of one of the Major WECC Transfer Paths in the
Bulk Electric System.
4.2.4.
This Standard does not apply to Facilities identified above (4.2.1 through
4.2.3) located in the fenced area of a switchyard, station or substation.
4.3. Enforcement: The reliability obligations of the applicable entities and facilities are
contained within the technical requirements of this standard. [Straw proposal]
4.4. Other:
This Standard does not apply to any occurrence, non-occurrence, or other set of
circumstances that are beyond the control of a Transmission Owner subject to this
reliability standard, including acts of God, flood, drought, earthquake, major storms,
fire, hurricane, tornado, landslides, ice storms, vehicle contact with tree, human activity
involving: removal of, installation of, or digging around vegetation, animals severing
trees, lightning, epidemic, strike, war, riot, civil disturbance, sabotage, vandalism,
terrorism, wind shear, or fresh gale (or higher wind speed) that restricts or prevents
performance to comply with this reliability standard’s requirements. Nothing in this
1
EPAct 2005 section 1211c: “Access approvals by Federal agencies”.
Draft 4: June 16, 2010
5
FAC-003-2 — Transmission Vegetation Management
section should be construed to limit the Transmission Owner’s right to exercise its full
legal rights on the active transmission line ROW 2.
5. Background:
This NERC Vegetation Management Standard (“Standard”) uses a defense-in-depth
approach to improve the reliability of the electric Transmission System by preventing those
vegetation related outages that could lead to Cascading. This Standard is not intended to
address non-preventable outages such as those due to vegetation fall-ins or blow-ins from
outside the Active Transmission Line Right-of-Way, vandalism, human activities and acts of
nature. Operating experience indicates that trees that have grown out of specification have
contributed to Cascading, especially under heavy electrical loading conditions.
With a defense-in-depth strategy, this Standard utilizes three types of requirements to provide
layers of protection to prevent vegetation related outages that could lead to Cascading:
a)
Performance-based — defines a particular reliability objective or outcome to be
achieved.
b)
Risk-based — preventive requirements to reduce the risks of failure to acceptable
tolerance levels.
c)
Competency-based — defines a minimum capability an entity needs to have to
demonstrate it is able to perform its designated reliability functions.
The defense-in-depth strategy for reliability standards development recognizes that each
requirement in a NERC reliability standard has a role in preventing system failures, and that
these roles are complementary and reinforcing. Reliability standards should not be viewed as
a body of unrelated requirements, but rather should be viewed as part of a portfolio of
requirements designed to achieve an overall defense-in-depth strategy and comport with the
quality objectives of a reliability standard. For this Standard, the requirements have been
developed as follows:
•
Performance-based: Requirements 1 and 2
•
Competency-based: Requirement 3
•
Risk-based: Requirements 4, 5, 6 and 7
Thus the various requirements associated with a successful vegetation program could be
viewed as using R1, R2 and R3 as first levels of defense; while R4 could be a subsequent or
final level of defense. R6 depending on the particular vegetation approach may be either an
initial defense barrier or a final defense barrier.
2
A strip or corridor of land that is occupied by active transmission facilities. This corridor does not include the parts
of the Right-of-Way that are unused or intended for other facilities. However, it is not to be less than the width of
the easement itself unless the easement exceeds distances as shown in Table 3 for various voltage classes.
Draft 4: June 16, 2010
6
FAC-003-2 — Transmission Vegetation Management
Major outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations.
Adherence to the Standard requirements for applicable lines on any kind of land or easement,
whether they are Federal Lands, state or provincial lands, public or private lands, franchises,
easements or lands owned in fee, will reduce and manage this risk. For the purpose of the
Standard the term “public lands” includes municipal lands, village lands, city lands, and a
host of other governmental entities.
This Standard addresses vegetation management along applicable overhead lines and does
not apply to underground lines, submarine lines or to line sections inside an electric station
boundary.
This Standard focuses on transmission lines to prevent those vegetation related outages that
could lead to Cascading. It is not intended to prevent customer outages due to tree contact
with lower voltage distribution system lines. For example, localized customer service might
be disrupted if vegetation were to make contact with a 69kV transmission line supplying
power to a 12kV distribution station. However, this Standard is not written to address such
isolated situations which have little impact on the overall electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses an
increased outage risk, especially when numerous transmission lines are operating at or near
their Rating. This can present a significant risk of multiple line failures and Cascading.
Conversely, most other outage causes (such as trees falling into lines, lightning, animals,
motor vehicles, etc.) are statistically intermittent. These events are not any more likely to
occur during heavy system loads than any other time. There is no cause-effect relationship
which creates the probability of simultaneous occurrence of other such events. Therefore
these types of events are highly unlikely to cause large-scale grid failures. Thus, this
Standard’s emphasis is on vegetation grow-ins.
Draft 4: June 16, 2010
7
FAC-003-2 — Transmission Vegetation Management
Requirements and Measures
Rationale
R1. Each Transmission Owner shall manage
The MVCD is a calculated minimum
vegetation to prevent encroachment that
distance stated in feet (meters) to prevent
could result in a Sustained Outage of any
spark-over between conductors and
line identified as an element of an
vegetation, for various altitudes and
Interconnection Reliability Operating
operating voltages. The distances in Table
Limit (IROL) or Major Western Electricity
2 were derived using a proven
Coordinating Council (WECC) transfer
transmission design method.
path (operating within Rating and Rated
Electrical Operating Conditions). Types of encroachment include:
1. An encroachment into the Minimum Vegetation Clearance Distance (MVCD) as shown
in Table 2, observed in real time, absent a Sustained Outage,
2. An encroachment due to a fall-in from inside the active transmission line ROW that
caused a vegetation-related Sustained Outage,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the active transmission line ROW that caused a vegetation-related Sustained
Outage,
4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage.
[VRF – High] [Time Horizon – Real-time]
M1. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-Time observations of any MVCD encroachments.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. If an investigation of a Fault by a qualified person confirms that a
vegetation encroachment within the MVCD occurred, then it shall be considered a
Real-time observation.
Draft 4: June 16, 2010
8
FAC-003-2 — Transmission Vegetation Management
R2. Each Transmission Owner shall manage
Rationale
vegetation to prevent encroachment that
The MVCD is a calculated minimum
could result in a Sustained Outage of
distance stated in feet (meters) to prevent
applicable lines that are not elements of
spark-over between conductors and
an Interconnection Reliability Operating
vegetation, for various altitudes and
Limit (IROL) or Major Western
operating voltages. The distances in Table 2
Electricity Coordinating Council
were derived using a proven transmission
(WECC) transfer path (operating within
design method.
Rating and Rated Electrical Operating
Conditions). Types of encroachment
include:
1. An encroachment into the Minimum Vegetation Clearance Distance (MVCD) as shown
in Table 2, observed in real time, absent a Sustained Outage,
2. An encroachment due to a fall-in from inside the active transmission line ROW that
caused a vegetation-related Sustained Outage,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the active transmission line ROW that caused a vegetation-related Sustained
Outage,
4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage.
[VRF – Medium] [Time Horizon – Real-time]
M2. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R2. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-Time observations of any MVCD encroachments.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. If an investigation of a Fault by a qualified person confirms that a
vegetation encroachment within the MVCD occurred, then it shall be considered a
Real-time observation.
Draft 4: June 16, 2010
9
FAC-003-2 — Transmission Vegetation Management
R3. Each Transmission Owner shall
document the procedures, processes, or
specifications it uses to prevent the
encroachment of vegetation into the
MVCD. Such documentation will
incorporate the dynamics of a
transmission line conductor’s movement
throughout its Rating and Rated
Electrical Operating Conditions and the
inter-relationships between vegetation
growth rates, vegetation control
methods, and inspection frequency, for
the Transmission Owner’s applicable
lines.
Rationale
Provide a basis for evaluation on the intent
and competency of the Transmission Owner
in maintaining vegetation. There may be
many acceptable approaches to maintain
clearances. However, the Transmission
Owner should be able to state what its
approach is and how it conducts work to
maintain clearances. See Figure 1 for an
illustration of possible conductor locations.
[VRF – Lower] [Time Horizon – Long Term Planning]
M3. The procedures, processes, or specifications provided demonstrate that the
Transmission Owner can prevent encroachment into the MVCD considering the
factors identified in the requirement.
R4. Each Transmission Owner, without any
intentional time delay, shall notify the
control center holding switching authority
for the associated transmission line when
qualified personnel confirm the existence
of a vegetation condition that is likely to
cause a Fault at any moment.
Rationale
To ensure expeditious communication
between qualified field personnel and
proper operating personnel when a critical
situation is confirmed. Qualified field
personnel may include lineworkers and
utility arborists.
[VRF – Medium] [Time Horizon – Realtime]
M4. Each Transmission Owner that has a vegetation condition likely to cause a Fault at
any moment, as confirmed by qualified personnel, will have evidence that it notified
the control center holding switching authority for the associated transmission line
without any intentional time delay. Examples of evidence may include control center
logs, voice recordings, switching orders, clearance orders and subsequent work
orders.
Draft 4: June 16, 2010
10
FAC-003-2 — Transmission Vegetation Management
R5. Each Transmission Owner shall take
corrective action when it is constrained
from performing planned vegetation
work, where a transmission line is put at
potential risk due to the constraint.
[VRF – Medium] [Time Horizon –
Operations Planning]
M5. Each Transmission Owner has
evidence of the corrective action
taken for each constraint where a
transmission line was put at
potential risk. Examples of
acceptable forms of evidence may
include initially-planned work
orders, documentation of
constraints from landowners, court
orders, inspection records of
increased monitoring,
documentation of the de-rating of
lines, revised work orders, invoices,
and evidence that a line was deenergized.
R6. Each Transmission Owner shall perform a
Vegetation Inspection of all applicable
transmission lines at least once per
calendar year.
[VRF – Medium] [Time Horizon –
Operations Planning]
M6. Each Transmission Owner has
evidence that it conducted
Vegetation Inspections at least once
per calendar year for all applicable
transmission lines. Examples of
acceptable forms of evidence may
include completed and dated work
orders, dated invoices, or dated
inspection records.
Draft 4: June 16, 2010
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
Transmission Owner from performing
planned vegetation maintenance work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the Transmission Owner to put interim
measures in place, rather than do nothing.
For example, in the 2003 NE blackout a
Transmission Owner was prevented by a
court order from performing planned work.
However, when the court order expired, the
TO failed to take action to maintain the
vegetation resulting in a sustained outage
that contributed to the cascade.
The corrective action process is not
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
Rationale
Inspections are used by Transmission
Owners to assess the condition of the
ROW. The information from the
assessment can be used to determine risk,
determine future work and evaluate
recently-completed work. This requirement
sets a minimum Vegetation Inspection
frequency of once per calendar year.
Based upon average growth rates across
North America and on common utility
practice, this minimum frequency is
reasonable. Transmission Owners should
consider local and environmental factors
that could warrant more frequent
inspections.
11
FAC-003-2 — Transmission Vegetation Management
R7. Each Transmission Owner shall complete the
work in an annual vegetation work plan to
ensure no vegetation encroachments occur
within the MVCD. Modifications to the
work plan in response to changing
conditions or to findings from vegetation
inspections may be made and documented
provided they do not put the transmission
system at risk of a vegetation encroachment.
Examples of reasons for modification to
annual plan may include:
Rationale
This requirement sets the expectation
that the work identified in the annual
work plan will be completed as planned.
An annual vegetation work plan allows
for work to be modified for changing
conditions, taking into consideration
anticipated growth of vegetation and all
other environmental factors, provided
that the changes do not violate the
encroachment within the MVCD.
• Change in expected growth rate/
environmental factors
• Major storms
• Rescheduling work between growing seasons
• Crew or contractor availability/ Mutual assistance agreements
• Identified unanticipated high priority work
• Weather conditions/Accessibility
• Permitting delays
• Land ownership changes/Change in land use by the landowner
• Funding adjustments (increase or decrease)
• Emerging technologies
[VRF – Medium] [Time Horizon – Operations Planning]
M7. Each Transmission Owner has evidence that it completed its annual vegetation work
plan. Examples of acceptable forms of evidence may include a copy of the completed
annual work plan (including modifications if any), dated work orders, dated invoices,
or dated inspection records.
Draft 4: June 16, 2010
12
FAC-003-2 — Transmission Vegetation Management
Compliance
Compliance Enforcement Authority
•
Regional Entity
Compliance Monitoring and Enforcement Processes:
•
•
•
•
•
•
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
Evidence Retention
The Transmission Owner retains data or evidence of Requirements R1 through R7, Measures
M1 through M7 for three calendar years to show compliance unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation.
If a Transmission Owner is found non-compliant, it shall keep information related to the noncompliance until found compliant, or for the duration specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all requested
and submitted subsequent audit records.
Additional Compliance Information
Periodic Data Submittal: The Transmission Owner will submit a quarterly report to its
Regional Entity, or the Regional Entity’s designee, identifying all Sustained Outages of
transmission lines determined by the Transmission Owner to have been caused by vegetation
that includes, as a minimum, the following:
o The name of the circuit(s), the date, time and duration of the outage; the voltage
of the circuit; a description of the cause of the outage; the category associated
with the Sustained Outage; other pertinent comments; and any countermeasures
taken by the Transmission Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation growing into
applicable transmission lines, that are identified as an element of an IROL or
Major WECC Transfer Path, by vegetation inside and/or outside of the active
transmission line ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation growing into
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, by vegetation inside and/or outside of the active
transmission line ROW;
Draft 4: June 16, 2010
13
FAC-003-2 — Transmission Vegetation Management
o Category 2 — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines from within the active transmission line ROW;
o Category3 4 — Blowing together: Sustained Outages caused by vegetation and
applicable transmission lines blowing together from within the active
transmission line ROW.
The Regional Entity will report the outage information provided by Transmission Owners, as
per the above, quarterly to NERC, as well as any actions taken by the Regional Entity as a
result of any of the reported Sustained Outages.
3
Category 3 reporting is eliminated.
Draft 4: June 16, 2010
14
FAC-003-2 — Transmission Vegetation Management
Time Horizons, Violation Risk Factors, and Violation Severity Levels
At the request of the Standards Committee,
stakeholders are asked to review and comment on
the proposed VSLs for R1 and R2. Following the
comment period and nonbinding poll, only one set of
VSLs will move forward for R1 and R2.
Table 1
R#
R1SDT
Version
R1 Staff
Version
R2SDT
Version
Time
Horizon
Realtime
Realtime
Realtime
VRF
Violation Severity Level
Lower
High
The Transmission Owner
had an encroachment into
the MVCD observed in
real time, absent a
Sustained Outage.
Moderate
The Transmission Owner
had an encroachment due to
a fall-in from inside the
active transmission line
ROW that caused a
vegetation-related
Sustained Outage.
High
Medium
The Transmission Owner
had an encroachment into
the MVCD observed in
real time, absent a
Draft 4: June 16, 2010
The Transmission Owner
had an encroachment due to
a fall-in from inside the
active transmission line
High
Severe
The Transmission Owner had an
encroachment due to blowing
together of applicable lines and
vegetation located inside the
active transmission line ROW
that caused a vegetation-related
Sustained Outage.
The Transmission Owner had an
encroachment due to a grow-in
that caused a vegetation-related
Sustained Outage.
The Transmission Owner failed
to manage vegetation to prevent
encroachment into the MVCD of
a line identified as an element of
an IROL or Major WECC
transfer path and encroachment
into the MVCD as identified in
FAC-003-Table 2 was observed
in real time absent a Sustained
Outage.
The Transmission Owner failed
to manage vegetation to prevent
encroachment into the MVCD of
a line identified as an element of
an IROL or Major WECC
transfer path and a vegetationrelated Sustained Outage was
caused by one of the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside the
active transmission line
ROW
• A grow-in
The Transmission Owner had an
encroachment due to a grow-in
that caused a vegetation-related
Sustained Outage.
The Transmission Owner had an
encroachment due to blowing
together of applicable lines and
vegetation located inside the
15
FAC-003-2 — Transmission Vegetation Management
Table 1
R#
Time
Horizon
VRF
Violation Severity Level
Lower
Sustained Outage.
R2 Staff
Version
R3
Realtime
LongTerm
Planning
Moderate
ROW that caused a
vegetation-related
Sustained Outage.
Draft 4: June 16, 2010
The Transmission Owner
has documented the
procedures, processes, or
specifications but does not
incorporate the interrelationships between
vegetation growth rates,
vegetation control methods,
and inspection frequency,
Severe
active transmission line ROW
that caused a vegetation-related
Sustained Outage.
The Transmission Owner failed
to manage vegetation to prevent
encroachment into the MVCD of
a line not identified as an element
of an IROL or Major WECC
transfer path and encroachment
into the MVCD as identified in
FAC-003-Table 2 was observed
in real time absent a Sustained
Outage.
Medium
Lower
High
The Transmission Owner has
documented the procedures,
processes, or specifications but
does not incorporate the
dynamics of a transmission line
conductor’s movement
throughout its Rating and Rated
Electrical Operating Conditions,
for the Transmission Owner’s
The Transmission Owner failed
to manage vegetation to prevent
encroachment into the MVCD of
a line not identified as an
element of an IROL or Major
WECC transfer path and a
vegetation-related Sustained
Outage was caused by one of the
following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside the
active transmission line
ROW
• A grow-in
The Transmission Owner does
not have any documented
procedures, processes or
specifications used to prevent the
encroachment of vegetation into
the MVCD, for the Transmission
Owner’s applicable lines.
16
FAC-003-2 — Transmission Vegetation Management
Table 1
R#
Time
Horizon
VRF
Violation Severity Level
Lower
Moderate
for the Transmission
Owner’s applicable lines.
R4
R5
Realtime
Operatio
ns
Planning
R6
Operatio
ns
Planning
R7
Operatio
ns
Planning
High
applicable lines.
The Transmission Owner
experienced a vegetation threat
confirmed by qualified personnel
and notified the control center
holding switching authority for
that transmission line, but there
was intentional delay in that
notification.
Medium
Medium
The Transmission Owner
experienced a vegetation threat
confirmed by qualified personnel
and did not notify the control
center holding switching
authority for that transmission
line.
The Transmission Owner did not
take corrective action when it
was constrained from performing
planned vegetation work where a
transmission line was put at
potential risk.
Medium
Medium
Severe
The Transmission Owner
failed to inspect 5% or less
of the ROW as measured
by applicable-line miles
(kilometers) (based on
units of choice: circuit,
pole line, ROW, etc.).
The Transmission Owner
failed to inspect more than
5% up to and including
10% of the ROW as
measured by applicable-line
miles (kilometers) (based
on units of choice: circuit,
pole line, ROW, etc.).
The Transmission Owner failed
to inspect more than 10% up to
and including 15% of the ROW
as measured by applicable-line
miles (kilometers) (based on units
of choice: circuit, pole line,
ROW, etc.).
The Transmission Owner failed
to inspect more than 15% of the
ROW as measured by applicableline miles (kilometers) (based on
units of choice: circuit, pole line,
ROW, etc.).
The Transmission Owner
failed to complete up to
5% of its annual work plan
(including modifications if
any).
The Transmission Owner
failed to complete more
than 5% and up to 10% of
its annual work plan
(including modifications if
The Transmission Owner failed
to complete more than 10% and
up to 15% of its annual work plan
(including modifications if any).
The Transmission Owner failed
to complete more than 15% of its
annual work plan (including
modifications if any).
Draft 4: June 16, 2010
17
FAC-003-2 — Transmission Vegetation Management
Table 1
R#
Time
Horizon
VRF
Violation Severity Level
Lower
Moderate
High
Severe
any).
Draft 4: June 16, 2010
18
FAC-003-2 — Transmission Vegetation Management
Variances
None.
Interpretations
None.
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
Guidelines and Technical Basis
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the prevention of vegetation encroachments within a minimum distance of
transmission lines. Content-wise, R1 and R2 are the same requirements; however, they apply to
different Facilities. Both R1 and R2 require each Transmission Owner to prevent vegetation
from encroaching within the Minimum Vegetation Clearance Distance of transmission lines. R1
is applicable to lines “identified as an element of an Interconnection Reliability Operating Limit
(IROL) or Major Western Electricity Coordinating Council (WECC) transfer path (operating
within Rating and Rated Electrical Operating Conditions) to avoid a Sustained Outage”. R2
applies to all other applicable lines that are not an element of an IROL or Major WECC Transfer
Path.
The separation of applicability (between R1 and R2) recognizes that an encroachment into the
MVCD of an IROL or Major WECC Transfer Path transmission line is a greater risk to the
electric transmission system. Applicable lines that are not an element of an IROL or Major
WECC Transfer Path are required to be clear of vegetation but these lines are comparatively less
operationally significant. As a reflection of this difference in risk impact, the Violation Risk
Factors (VRFs) are assigned as High for R1 and Medium for R2.
These requirements (R1 and R2) state that if vegetation encroaches within the distances
prescribed in Table 2, it is in violation of the standard. Table 2 delineates the distances necessary
to prevent spark-over based on the Gallet equations as described more fully in a supplemental
Transmission Vegetation Management Standard FAC-003-2 Technical Reference.
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating
(potentially in violation of other standards), the occurrence of a clearance encroachment may
occur. For example, emergency actions taken by a Transmission Operator or Reliability
Coordinator to protect an Interconnection may cause the transmission line to sag more and come
closer to vegetation, potentially causing an outage. Such vegetation-related outages are not a
violation of these requirements.
Evidence of violation of Requirement R1 and R2 include real-time observation of a vegetation
encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related encroachment
resulting in a Sustained Outage due to a fall-in from inside the active transmission line ROW, or
a vegetation-related encroachment resulting in a Sustained Outage due to blowing together of
applicable lines and vegetation located inside the active transmission line ROW, or a vegetationrelated encroachment resulting in a Sustained Outage due to a grow-in. If an investigation of a
Fault by a qualified person confirms that a vegetation encroachment within the MVCD occurred,
then it shall be considered a Real-time observation.
With this approach, the VSLs were defined such that they directly correlate to the severity of a
failure to keep vegetation away from conductors and to the corresponding performance level of
the Transmission Owner’s vegetation program’s ability to meet the goal of “preventing a
Sustained Outage that could lead to Cascading.” Thus violation severity increases with a
Transmission Owner’s inability to meet this goal and its potential of leading to a Cascading
event. The additional benefits of such a combination are that it simplifies the standard and clearly
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
defines performance for compliance. A performance-based requirement of this nature will
promote high quality, cost effective vegetation management programs that will deliver the
overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation, for
example a limb that only partially breaks and intermittently contacts a conductor. Such events
are considered to be a single vegetation-related Sustained Outage under the Standard where the
Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will help prevent transmission outages.
Requirement R3:
Requirement R3 is a competency based requirement concerned with the procedures, processes,
or specifications, a Transmission Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the
Transmission Owner uses to plan and perform vegetation work to prevent transmission Sustained
Outages and minimize risk to the Transmission System. The approach provides the basis for
evaluating the intent, allocation of appropriate resources and the competency of the Transmission
Owner in managing vegetation. There are many acceptable approaches to manage vegetation
and avoid Sustained Outages. However, the Transmission Owner must be able to state what its
approach is and how it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach a
Transmission Owner chooses to use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the Transmission Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing as a reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figure 1 below.
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
Figure 1
Cross-section view of a single conductor at a given point along the span showing six possible
conductor positions due to movement resulting from thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the
Transmission Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4
involves the notification of potentially threatening vegetation conditions, without any intentional
delay, to the control center holding switching authority for that specific transmission line.
Examples of acceptable unintentional delays may include communication system problems (for
example, cellular service or two-way radio disabled), crews located in remote field locations
with no communication access, delays due to severe weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of a qualified employee who personally identifies such a threat in the field.
Confirmation could also be made by sending out a qualified person to evaluate a situation
reported by a landowner or an unqualified employee.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an assessment
of the possible sag or movement of the conductor while operating between no-load conditions
and its rating.
The Transmission Owner has the responsibility to ensure the proper communication between
field personnel and the control center to allow the control center to take the appropriate action
until the vegetation threat is relieved. Appropriate actions may include a temporary reduction in
the line loading, switching the line out of service, or positioning the system in recognition of the
increasing risk of outage on that circuit. The notification of the threat should be communicated in
terms of minutes or hours as opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some Transmission Owners may have a danger tree identification
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
program that identifies trees for removal with the potential to fall near the line. These trees
would not require notification to the control center unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
Transmission Owner for the mitigation of Sustained Outage risk when temporarily constrained
from performing vegetation maintenance. The intent of this requirement is to deal with situations
that prevent the Transmission Owner from performing planned vegetation management work
and, as a result, have the potential to put the transmission line at risk. Constraints to performing
vegetation maintenance work as planned could result from legal injunctions filed by property
owners, the discovery of easement stipulations which limit the Transmission Owner’s rights, or
other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
Transmission Owner is not under any immediate time constraint for achieving the management
objective, can easily reschedule work using an alternate approach, and therefore does not need to
take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the Transmission Owner is required to take corrective action to mitigate the potential risk to the
transmission line. A wide range of actions can be taken to address various situations. General
considerations include:
•
Identifying locations where the Transmission Owner is constrained from performing
planned vegetation maintenance work which potentially leaves the transmission line
at risk.
•
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for each location.
In developing the specific action to mitigate the potential risk to the transmission line
the Transmission Owner could consider location specific measures such as modifying
the inspection and/or maintenance intervals. Where a legal constraint would not allow
any vegetation work, the interim corrective action could include limiting the loading
on the transmission line.
The Transmission Owner should document and track the specific corrective action
taken at each location. This location may be indicated as one span, one tree or a
combination of spans on one property where the constraint is considered to be
temporary.
•
•
•
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections that fits general industry practice. In addition, the fact that Vegetation
Inspections can be performed in conjunction with general line inspections further facilitates a
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
Transmission Owner’s ability to meet this requirement. However, the Transmission Owner may
determine that more frequent inspections are needed to maintain reliability levels, dependent
upon such factors as anticipated growth rates of the local vegetation, length of the growing
season for the geographical area, limited Active Transmission ROW width, and rainfall amounts.
Therefore it is expected that some transmission lines may be designated with a higher frequency
of inspections.
The VSL for Requirement R6 has VSL categories ranked by the percentage of the required ROW
inspections completed. To calculate the percentage of inspection completion, the Transmission
Owner may choose units such as: line miles or kilometers, circuit miles or kilometers, pole line
miles, ROW miles, etc.
For example, when a Transmission Owner operates 2,000 miles of 230 kV transmission lines this
Transmission Owner will be responsible for inspecting all 2,000 miles of 230 kV transmission
lines at least once during the calendar year. If one of the included lines was 100 miles long, and
if it was not inspected during the year, then the amount failed to inspect would be 100/2000 =
0.05 or 5%. The “Low VSL” for R6 would apply in this example.
Requirement R7:
R7 is a risk-based requirement. The Transmission Owner is required to implement an annual
work plan for vegetation management to accomplish the purpose of this standard. Modifications
to the work plan in response to changing conditions or to findings from vegetation inspections
may be made and documented provided they do not put the transmission system at risk. The
annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a
“line-by-line” detailed description of all work to be performed. It is only intended to require that
the Transmission Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation into
the MVCD.
The ability to modify the work plan allows the Transmission Owner to change priorities or
treatment methodologies during the year as conditions or situations dictate. For example recent
line inspections may identify unanticipated high priority work, weather conditions (drought)
could make herbicide application ineffective during the plan year, or a major storm could require
redirecting local resources away from planned maintenance. This situation may also include
complying with mutual assistance agreements by moving resources off the Transmission
Owner’s system to work on another system. Any of these examples could result in acceptable
deferrals or additions to the annual work plan. Modifications to the annual work plan must
always ensure the reliability of the electric Transmission system.
In general, the vegetation management maintenance approach should use the full extent of the
Transmission Owner’s easement, fee simple and other legal rights allowed. A comprehensive
approach that exercises the full extent of legal rights on the active transmission line ROW is
superior to incremental management in the long term because it reduces the overall potential for
encroachments, and it ensures that future planned work and future planned inspection cycles are
sufficient.
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
When developing the annual work plan the Transmission Owner should allow time for
procedural requirements to obtain permits to work on federal, state, provincial, public, tribal
lands. In some cases the lead time for obtaining permits may necessitate preparing work plans
more than a year prior to work start dates. Transmission Owners may also need to consider those
special landowner requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the Transmission
Owner, evidence of successful annual work plan execution could consist of signed-off work
orders, signed contracts, printouts from work management systems, spreadsheets of planned
versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence
may include photographs, and walk-through reports.
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 4
For Alternating Current Voltages
( AC )
Nominal
System
Voltage
(kV)
( AC )
Maximum
System
Voltage
(kV)
765
800
500
550
345
362
230
242
161*
169
138*
145
115*
121
88*
100
69*
72
MVCD
feet
(meters)
sea level
8.06ft
(2.46m)
5.06ft
(1.54m)
3.12ft
(0.95m)
2.97ft
(0.91m)
2ft
(0.61m)
1.7ft
(0.52m)
1.41ft
(0.43m)
1.15ft
(0.35m)
0.82ft
(0.25m)
MVCD
feet
(meters)
3,000ft
(914.4m)
MVCD
feet
(meters)
4,000ft
(1219.2m)
MVCD
feet
(meters)
5,000ft
(1524m)
MVCD
feet
(meters)
6,000ft
(1828.8m)
8.89ft
(2.71m)
5.66ft
(1.73m)
3.53ft
(1.08m)
3.36ft
(1.02m)
2.28ft
(0.69m)
1.94ft
(0.59m)
1.61ft
(0.49m)
1.32ft
(0.40m)
0.94ft
(0.29m)
9.17ft
(2.80m)
5.86ft
(1.79m)
3.67ft
(1.12m)
3.49ft
(1.06m)
2.38ft
(0.73m)
2.03ft
(0.62m)
1.68ft
(0.51m)
1.38ft
(0.42m)
0.99ft
(0.30m)
9.45ft
(2.88m)
6.07ft
(1.85m)
3.82ft
(1.16m)
3.63ft
(1.11m)
2.48ft
(0.76m)
2.12ft
(0.65m)
1.75ft
(0.53m)
1.44ft
(0.44m)
1.03ft
(0.31m)
9.73ft
(2.97m)
6.28ft
(1.91m)
3.97ft
(1.21m)
3.78ft
(1.15m)
2.58ft
(0.79m)
2.21ft
(0.67m)
1.83ft
(0.56m)
1.5ft
(0.46m)
1.08ft
(0.33m)
MVCD
feet
(meters)
7,000ft
(2133.6m)
MVCD
feet
(meters)
8,000ft
(2438.4m)
MVCD
feet
(meters)
9,000ft
(2743.2m)
MVCD
feet
(meters)
10,000ft
(3048m)
MVCD
feet
(meters)
11,000ft
(3352.8m)
10.01ft
(3.05m)
6.49ft
(1.98m)
4.12ft
(1.26m)
3.92ft
(1.19m)
2.69ft
(0.82m)
2.3ft
(0.70m)
1.91ft
(0.58m)
1.57ft
(0.48m)
1.13ft
(0.34m)
10.29ft
(3.14m)
6.7ft
(2.04m)
4.27ft
(1.30m)
4.07ft
(1.24m)
2.8ft
(0.85m)
2.4ft
(0.73m)
1.99ft
(0.61m)
1.64ft
(0.50m)
1.18ft
(0.36m)
10.57ft
(3.22m)
6.92ft
(2.11m)
4.43ft
(1.35m)
4.22ft
(1.29m)
2.91ft
(0.89m)
2.49ft
(0.76m)
2.07ft
(0.63m)
1.71ft
(0.52m)
1.23ft
(0.37m)
10.85ft
(3.31m)
7.13ft
(2.17m)
4.58ft
(1.40m)
4.37ft
(1.33m)
3.03ft
(0.92m)
2.59ft
(0.79m)
2.16ft
(0.66m)
1.78ft
(0.54m)
1.28ft
(0.39m)
11.13ft
(3.39m)
7.35ft
(2.24m)
4.74ft
(1.44m)
4.53ft
(1.38m)
3.14ft
(0.96m)
2.7ft
(0.82m)
2.25ft
(0.69m)
1.86ft
(0.57m)
1.34ft
(0.41m)
* Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above).
4
The distances in this Table are the minimums required to prevent Flashover; however prudent vegetation maintenance practices dictate that substantially greater
distances will be achieved at time of vegetation maintenance.
Draft 4: June 16, 2010
26
FAC-003-2 — Transmission Vegetation Management
Table 2 (cont.) — Minimum Vegetation Clearance Distances (MVCD)
For Direct Current Voltages
sea level
MVCD feet
(meters)
3,000ft
(914.4m)
Alt.
MVCD feet
(meters)
4,000ft
(1219.2m)
Alt.
MVCD feet
(meters)
5,000ft
(1524m)
Alt.
MVCD feet
(meters)
6,000ft
(1828.8m)
Alt.
MVCD
feet
(meters)
7,000ft
(2133.6m)
Alt.
MVCD
feet
(meters)
(8,000ft
(2438.4m)
Alt.
MVCD
feet
(meters)
9,000ft
(2743.2m)
Alt.
MVCD
feet
(meters)
10,000ft
(3048m)
Alt.
MVCD
feet
(meters)
11,000ft
(3352.8m)
Alt.
±750
13.92ft
(4.24m)
15.07ft
(4.59m)
15.45ft
(4.71m)
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.9ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
±600
10.07ft
(3.07m)
11.04ft
(3.36m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
(13.54ft
4.13m)
±500
7.89ft
(2.40m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
±400
4.78ft
(1.46m)
5.35ft
(1.63m)
5.55ft
(1.69m)
5.75ft
(1.75m)
5.95ft
(1.81m)
6.15ft
(1.87m)
6.36ft
(1.94m)
6.57ft
(2.00m)
6.77ft
(2.06m)
6.98ft
(2.13m)
±250
3.43ft
(1.05m)
4.02ft
(1.23m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5ft
(1.52m)
5.17ft
(1.58m)
( DC )
Nominal Pole
to Ground
Voltage
(kV)
MVCD feet
(meters)
Draft 4: June 16, 2010
27
FAC-003-2 — Transmission Vegetation Management
Table 3 – Minimum Distance from the Centerline of the Circuit to the edge of the active transmission line ROW
Draft 4: June 16, 2010
69 - 138 kV
37.5 ft.
139 - 230 kV
50 ft.
231 - 345 kV
75 ft.
346 - 500 kV
87.5 ft.
501 - 765 kV
100 ft.
28
FAC-003-2 — Transmission Vegetation Management
Standards Committee Executive Commit
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. SC approved SAR for initial posting (January 11, 2007).
2. SAR posted for comment (January 15–February 14, 2007).
3. SAR posted for comment (April 10–May 9, 2007).
4. SC authorized moving the SAR forward to standard development (June 27, 2007).
Proposed Action Plan and Description of Current Draft
This is the secondfirst posting of the proposed revisions to the standard in accordance with
Results-Based Criteria. The drafting team requests posting for a 30-day informal comment
period.
Future Development Plan
Anticipated Actions
Anticipated Date
Drafting team considers comments, makes conforming changes, posts April 2010
for 30-day informal comment period.
Drafting team considers comments, makes conforming changes, and
requests SC approval to proceed to formal comment and ballot.
June –July 2010
Recirculation ballot of standards.
July-August 2010
Receive BOT approval
AugustSeptember
2010
Draft 4: June 163: March 1, 2010
FAC-003-2 — Transmission Vegetation Management
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Active Transmission Line Right-of-Way
A strip or corridor of land that is occupied by active
transmission facilities. This corridor does not
include the parts of the Right-of-Way that are
unused or intended for other facilities.
Examples of active portions of corridors
include:
The width of any Active Transmission Line Right-ofWay (ROW) is the portion of the ROW that has been
cleared of vegetation to meet design clearance
requirements such as National Electrical Safety Code or
other design criteria, for the reliable operation of active
facilities.
Examples of inactive portions of corridors
include:
1) The portions of the ROW acquired to
accommodate future Facilities. Power plant
exits are examples where large ROWs are
obtained for maximum corridor utilization and
may currently have fewer circuits constructed.
2) The portion of the ROW where corridor edge
zones are designated by regulatory bodies for
vegetation to exist.
3) The portions of the ROW where double-circuit
structures are installed but only one circuit is
currently strung with conductors.
Vegetation Inspection
The systematic examination of vegetation conditions on
an Active Transmission Line Right-of-Way which may
be combined with a general line inspection.
The current glossary definition of this NERC term
is modified to allow both maintenance inspections
and vegetation inspections to be performed
concurrently.
Current definition of Vegetation Inspection: The
systematic examination of a transmission corridor
to document vegetation conditions.
Draft 4: June 163: March 1, 2010
FAC-003-2 — Transmission Vegetation Management
Effective Dates
Requirement
Jurisdiction
Alberta
British
Columbia
Manitoba
New
Brunswick
Newfoundland
Nova
Scotia
Ontario
Quebec
R1
1
1
1
3
TBD
TBD
2
TBD
R2
1
1
1
3
TBD
TBD
2
TBD
R3
1
1
1
3
TBD
TBD
2
TBD
R4
1
1
1
3
TBD
TBD
2
TBD
R5
1
1
1
3
TBD
TBD
2
TBD
R6
1
1
1
3
TBD
TBD
2
TBD
R7
1
1
1
3
TBD
TBD
2
TBD
1. First calendar day of the first calendar quarter one year after applicable regulatory
authority approval for all requirements
2. First calendar day of the first calendar quarter one year following Board of Trustees
adoption unless governmental authority withholds approval
3. First calendar day of the first calendar quarter that is at least one year following Board of
Trustees adoption
Exceptions:
A lineLines operated below 200kV, designated by the Planning Coordinator as an
element of an IROL or as a Major WECC transfer path, becomesbecome subject to
this standard 12 months after the date the Planning Coordinator or WECC
initially designates the lines as being subject to this standard.
An existing transmission line operated at 200kV or higher that is newly acquired
by an asset owner and was not previously subject to this standard, becomes
subject to this standard 12 months after the acquisition date of the line.(s).
Draft 4: June 16, 2010
3
FAC-003-2 — Transmission Vegetation Management
Version History
Version
1
Date
TBA
Action
1. Added “Standard Development
Roadmap.”
Change Tracking
01/20/06
2. Changed “60” to “Sixty” in section
A, 5.2.
3. Added “Proposed Effective Date:
April 7, 2006” to footer.
4. Added “Draft 3: November 17,
2005” to footer.
1
2
April 4, 2007
Draft 4: June 16, 2010
Regulatory Approval — Effective Date
New
43
FAC-003-2 — Transmission Vegetation Management
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary. When this standard has received ballot approval, the text
boxes will be moved to the Guideline and Technical Basis Section.
Vegetation Inspection
The systematic examination of vegetation
conditions on a maintained transmission line Rightof-Way which may be combined with a general line
inspection.
Draft 4: June 16, 2010
The current glossary definition of this NERC term is
modified to allow both maintenance inspections and
vegetation inspections to be performed concurrently.
Current definition of Vegetation Inspection: The
systematic examination of a transmission corridor to
document vegetation conditions.
53
FAC-003-2 — Transmission Vegetation Management
Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-2
3. Objectives:
To improve the reliability of the electric Transmission system by
preventing those vegetation related outages that could lead to Cascading.
4. Applicability
4.1. Functional Entities:
4.1.1 Transmission Owners
4.2. Facilities: Defined below, including but not limited to those that cross lands owned by
federal 1, state, provincial, public, private, or tribal entities:
4.2.1.
4.2.1.
Overhead transmission lines operated at 200kV or higher.
4.2.2.
4.2.2.
Overhead transmission lines operated below 200kV having been
identified as included in the definitionelements of an Interconnection
Reliability Operating Limit (IROL) under NERC Standard FAC 014 by the
Planning Coordinator.).
4.2.3.
4.2.3.
Overhead transmission lines operated below 200 kV having been
identified as included in the definition of one of the Major WECC Transfer
Paths in the Bulk Electric System.
4.2.4.
4.2.4.
This Standard does not apply to Facilities identified above (4.2.1
through 4.2.3) located in the fenced area of a switchyard, station or substation.
4.3. Enforcement: The reliability obligations of the applicable entities and facilities are
contained within the technical requirements of this standard. [Straw proposal]
4.3.4.4.
Other:
4.3.1.
This Standard does not apply to any occurrence, non-occurrence, or other
set of circumstances that are beyond the reasonable control of a Transmission Owner
subject to this reliability standardReliability Standard, and are not caused by the fault or
negligence of the Transmission Owner, including acts of God, flood, drought,
earthquake, major storms, fire, hurricane, tornado, landslides, ice storms, vehicle
contact with tree, human activity involving: removal of, installation of, or digging
around vegetationlogging activities, animals severing trees, lightning, epidemic, strike,
war, riot, civil disturbance, sabotage, vandalism, terrorism, wind shear, or fresh gale (or
higher wind speed)gales that restricts or prevents performance to comply with this
reliability standard’s requirements. Nothing in this section should be construed to limit
1
EPAct 2005 section 1211c: “Access approvals by Federal agencies”.
Draft 4: June 16, 2010
63
FAC-003-2 — Transmission Vegetation Management
the Transmission Owner’s right to exercise its full legal rights on the active
transmission line ROW 2.
5. Background:
This NERC Vegetation Management Standard (“Standard”) uses a defense-in-depth
approach to improve the reliability of the electric Transmission System by preventing those
vegetation related outages that could lead to Cascading. This Standard is not intended to
address non-preventable outages such as those due to vegetation fall-ins or blow-ins from
outside the Active Transmission Line Right-of-Way, vandalism, human activitieserrors and
acts of nature. Operating experience indicates that trees that have grown out of specification
have contributed to Cascading, especially under heavy electrical loading conditions.
With a defense-in-depth strategy, this Standard utilizes three types of requirements to provide
layers of protection to prevent vegetation related outages that could lead to Cascading:
a)
Performance-based — defines a particular reliability objective or outcome to be
achieved.
b)
Risk-based — preventive requirements to reduce the risks of failure to acceptable
tolerance levels.
c)
Competency-based — defines a minimum capability an entity needs to have to
demonstrate it is able to perform its designated reliability functions.
The defense-in-depth strategy for reliability standards development recognizes that each
requirement in a NERC reliability standard has a role in preventing system failures, and that
these roles are complementary and reinforcing. Reliability standards should not be viewed as
a body of unrelated requirements, but rather should be viewed as part of a portfolio of
requirements designed to achieve an overall defense-in-depth strategy and comport with the
quality objectives of a reliability standard. For this Standard, the requirements have been
developed as follows:
•
Performance-based: Requirements 1 and 2
•
Competency-based: Requirement 3
•
Risk-based: Requirements 4, 5, 6 and 7
Thus the various requirements associated with a successful vegetation program could be
viewed as using R1, R2 and R3 as first levels of defense; while R4 could be a subsequent or
final level of defense. R6 depending on the particular vegetation approach may be either an
initial defense barrier or a final defense barrier.
2
A strip or corridor of land that is occupied by active transmission facilities. This corridor does not include the parts
of the Right-of-Way that are unused or intended for other facilities. However, it is not to be less than the width of
the easement itself unless the easement exceeds distances as shown in Table 3 for various voltage classes.
Draft 4: June 16, 2010
73
FAC-003-2 — Transmission Vegetation Management
Major outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations.
Adherence to the Standard requirements for applicable lines on any kind of land or easement,
whether they are Federal Lands, state or provincial lands, public or private lands, franchises,
easements or lands owned in fee, will reduce and manage this risk. For the purpose of the
Standard the term “public lands” includes municipal lands, village lands, city lands, and a
host of other governmental entities.
This Standard addresses vegetation management along applicable overhead lines andthat
serve to connect one electric station to another. However, this Standard does not apply to
underground lines, submarine lines or to line sections inside an electric station boundary.
This Standard focuses on transmission lines to prevent those vegetation related outages that
could lead to Cascading. It is not intended to prevent customer outages due to tree contact
with lower voltage distribution system lines. For example, localized customer service might
be disrupted if vegetation were to make contact with a 69kV transmission line supplying
power to a 12kV distribution station. However, this Standard is not written to address such
isolated situations which have little impact on the overall electric transmission systemBulk
Electric System.
Since vegetation growth is constant and always present, unmanaged vegetation poses an
increased outage risk, especially when numerous transmission lines are operating at or near
their Rating. This can present a significant risk of multiple line failures and Cascading.
Conversely, most other outage causes (such as trees falling into lines, lightning, animals,
motor vehicles, etc.) are statistically intermittent. These events are not any more likely to
occur during heavy system loads than any other time. There is no cause-effect relationship
which creates the probability of simultaneous occurrence of other such events. Therefore
these types of events are highly unlikely to cause large-scale grid failures. Thus, this
Standard’s emphasis is on vegetation grow-ins.
Draft 4: June 16, 2010
83
FAC-003-2 — Transmission Vegetation Management
Requirements and Measures
R1. Each Transmission Owner shall manage
Rationale
prevent vegetation to prevent encroachment
The MVCD is a calculated minimum
that could result in a Sustained Outagefrom
distance stated in feet (meters) to prevent
encroaching within the Minimum Vegetation
spark-over between conductors and
Clearance Distance (MVCD) of anyeach line
vegetation, for various altitudes and
conductor that is identified as an element of an
operating voltages. The distances in Table 2
Interconnection Reliability Operating Limit
were derived using a proven transmission
(IROL) or Major Western Electricity
design method.
Coordinating Council (WECC) transfer path
(operating within Rating and Rated Electrical Operating Conditions). Types of
encroachment include:) to avoid a Sustained Outage.
An
M1. Evidence of violation of Requirement R1 is limited to:
•1. Real-time observation of encroachment into the Minimum Vegetation Clearance
Distance (MVCD) as shown in Table 2, observed in real time, absent a Sustained
Outage,, or
• An encroachmentA vegetation-related Sustained Outage due to a fall-in from
inside the active transmission lineActive Transmission Line ROW that
caused a, or
2. A vegetation-related Sustained Outage,
• An encroachment due to blowing together of applicable lines and vegetation
located inside the active transmission lineActive Transmission Line ROW
that caused a, or
3. A vegetation-related Sustained Outage,
4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage.
[VRF – High] [Time Horizon – Real-time]
M1. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-Time observations of any MVCD encroachments.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. If an investigation of a Fault by a qualified person confirms that a
vegetation encroachment within the MVCD occurred, then it shall be considered a
Real-time observation.
Draft 4: June 16, 2010
93
FAC-003-2 — Transmission Vegetation Management
R2. Each Transmission Owner shall manage
Rationale
vegetation to prevent encroachment that
The MVCD is a calculated minimum
could result in a Sustained Outage of
distance stated in feet (meters) to prevent
applicable lines that are not elements of
spark-over between conductors and
an Interconnection Reliability Operating
vegetation, for various altitudes and
Limit (IROL) or Major Western
operating voltages. The distances in Table 2
Electricity Coordinating Council
were derived using a proven transmission
(WECC) transfer path (operating within
design method.
Rating and Rated Electrical Operating
Conditions). Types of encroachment
include:
1. An encroachment into the Minimum Vegetation Clearance Distance (MVCD) as shown
in Table 2, observed in real time, absent a Sustained Outage,
2. An encroachment due to a fall-in from inside the active transmission line ROW that
caused a vegetation-related Sustained Outage,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the active transmission line ROW that caused a vegetation-related Sustained
Outage,
4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage.
[VRF – Medium] [Time Horizon – Real-time]
• M2. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R2. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-Time observations of any MVCD encroachments.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. If an investigation of a Fault by a qualified person confirms that a
vegetation encroachment within the MVCD occurred, then it shall be considered a
Real-time observation.
Draft 4: June 16, 2010
10
3
FAC-003-2 — Transmission Vegetation Management
R3R2.
Each Transmission Owner shall
Rationale
document the procedures, processes,
The MVCD is a calculated minimum
or specifications it uses to prevent the
distance stated in feet (meters) to prevent
encroachment of vegetation intofrom
spark-over between conductors and
encroaching within the MVCD. Such
vegetation, for various altitudes and
documentation will incorporate the
operating voltages. The distances in Table
dynamics of a transmission of each
2 were derived using a proven
applicable line conductor’s
Transmission design method.
Rationale
movement throughout its
Provide a basis for evaluation on the intent
conductor, which are not elements of
and competency of the Transmission Owner
an IROL and are not a Major WECC
in maintaining vegetation. There may be
transfer path, (operating within Rating
many acceptable approaches to maintain
and Rated Electrical Operating
clearances. However, the Transmission
Conditions and the interOwner should be able to state what its
relationships between vegetation
approach is and how it conducts work to
growth rates, vegetation control
maintain clearances. See Figure 1 for an
methods, and inspection
illustration of possible conductor locations.
frequency, for the Transmission
Owner’s applicable lines) to avoid
a Sustained Outage.
[VRF – Lower] [Time Horizon – Long Term Planning]
M3. The procedures, processes, or specifications provided demonstrate that the Transmission
Owner can prevent
M2. Evidence of violation of Requirement R2 is limited to:
• Real-time observation of encroachment into the MVCD, or
• A vegetation-related Sustained Outage due to a fall-in from inside the Active
Transmission Line ROW, or
• A vegetation-related Sustained Outage due to blowing together of applicable
lines and vegetation located inside the Active Transmission Line ROW, or
• A vegetation-related Sustained Outage due to a grow-in.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a
24-hour period.
R3. Each Transmission Owner shall have a documented transmission vegetation
management program that describes how it conducts work on its Active Transmission
Line ROWs to avoid Sustained Outages due to vegetation, considering the factors
identified in the requirementall possible locations the conductor may occupy
assuming operation within Rating and Rated Electrical Operating Conditions.
Draft 4: June 16, 2010
Rationale
To ensure expeditious communication
between qualified field personnel and
proper operating personnel when a critical 11
3
situation is confirmed. Qualified field
personnel may include lineworkers and
utility arborists.
Rationale
Provide a basis for evaluation on the intent
FAC-003-2 — Transmission Vegetation Managementand competency of the Transmission Owner
in maintaining vegetation. There may be
many acceptable approaches to maintain
clearances. However, the Transmission
M3. Each Transmission Owner has a
Owner should be able to state what its
documented transmission vegetation
approach is and how it conducts work to
management program that describes
maintain clearances. See Figure 1 for an
how it conducts work on its Active
illustration of possible conductor locations.
Transmission Line ROW to avoid
Sustained Outages due to vegetation,
considering all possible locations the
conductor may occupy assuming operation within Rating and Rated Electrical
Operating Conditions.
R4. Each Transmission Owner, without any
intentional time delay, shall notify the
responsible control center holding switching
authority for the associated transmission line
when qualified personnel confirm the
existenceit has verified knowledge of a
vegetation imminent threat condition that .
A vegetation imminent threat condition is
one which is likely to cause a FaultSustained
Outage at any moment.
Rationale
To ensure rapid notification of the correct
personnel when an occurrence of a critical
situation is observed. Verified knowledge
includes observations by journeyman lineman,
utility arborist, or other qualified personnel, or a
report verified by these personnel.
[VRF – Medium] [Time Horizon – Realtime]
M4. Each Transmission Owner that has a vegetation condition likely to cause a Fault at
any moment, as confirmed by qualified personnel,experienced a verified vegetation
imminent threat will have evidence that it notified the responsible control center
holding switching authority for the associated transmission line without any
intentional time delay. Examples of evidence may include control center logs, voice
recordings, switching orders, clearance orders and subsequent work orders.
Draft 4: June 16, 2010
12
3
FAC-003-2 — Transmission Vegetation Management
R5. Each Transmission Owner shall take
interim corrective action when it is
temporarily constrained from performing
planned vegetation work, where a
transmission line is put at potential risk
due to the constraint.
[VRF – Medium] [Time Horizon –
Operations Planning]
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
Transmission Owner from performing
planned vegetation maintenance work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for
the Transmission Owner to put interim
Rationale
measures
in place,
than domay
nothing.
Legal actions
and rather
other events
occur
For
example,
2003 NEthat
blackout
which
result in the
constraints
preventa the
Transmission
prevented
by a
TransmissionOwner
Ownerwas
from
performing
court
order
from
performing
planned
work.
planned vegetation maintenance work.
However,
courtand
order
When thiswhen
eventthe
occurs
theexpired,
work is the
TO
failed
to
take
action
to
maintain
the
essential avoid risk to the transmission
vegetation
resulting in aOwner
sustained
line the Transmission
mustoutage
establish
that
to to
theprevent
cascade.
andcontributed
act on a plan
an imminent
The
corrective
processtoisaddress
not
threat.
This is action
not intended
intended
towhere
address
situations
where a
situations
a planned
work
planned
work methodology
cannot be
methodology
cannot be performed
but an
performed
but anmethodology
alternate work
alternate work
can be used.
methodology can be used.
M5. Each Transmission Owner has
evidence of the interim corrective
action taken for each temporary
constraint where a transmission line
was put at potential risk. Examples
of acceptable forms of evidence
may include initially-planned work
orders, documentation of
constraints from landowners, court
orders, inspection records of
increased monitoring,
documentation of the de-rating of
lines, revised work orders, invoices, and evidence that a line was de-energizedor
inspection records.
R6. Each Transmission Owner shall perform a
Vegetation Inspection of all applicable
transmission lines at least once per calendar
year.
[VRF – Medium] [Time Horizon – Operations
Planning]
Rationale
Inspections are used by Transmission
Owners to assess the condition of the
ROW. The information from the
assessment can be used to determine risk,
determine future work and evaluate
recently-completed work. This
requirement sets a minimum Vegetation
Inspection frequency of once per calendar
M6. Each Transmission Owner has evidence
that it conducted Vegetation Inspections at
least once per calendar year for all applicable transmission lines. Examples of
acceptable forms of evidence may include completed and dated work orders, dated
invoices, or dated inspection records.
Draft 4: June 16, 2010
13
3
FAC-003-2 — Transmission Vegetation Management
R7. Each Transmission Owner shall complete the
work in anexecute a flexible annual
vegetation work plan to ensure no vegetation
encroachments occur within the MVCD.
Modifications to the work plan in response
to changing conditions or to findings from
vegetation inspections may be made and
documented provided they do not put the
transmission system at risk of a vegetation
encroachment. Examples of reasons for
modification to annual plan may include:
•
•
•
•
•
•
•
•
•
•
Rationale
ThisRationale
requirement sets the expectation
This
requirement
setsinthe
that
that the work
identified
theexpectation
annual
the
work
identified
in
the
annual
work
work plan will be completed as planned.
willvegetation
be completed
planned.
An plan
annual
workasplan
allowsA
flexible
annual
vegetation
work
plan
for work to be modified for changing
allows for
workinto
to be
deferred into the
conditions,
taking
consideration
following
calendar
year
provided
it does
anticipated growth of vegetation
and all
notenvironmental
have the potential
to become
other
factors,
providedan
imminent
threat.
that the changes do not violate the
encroachment within the MVCD.
Change in expected growth rate/ environmental factors
Major storms
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Funding adjustments (increase or decrease)
Emerging technologies
[VRF – Medium] [Time Horizon – Operations Planning]
M7. Each Transmission Owner has evidence that it completed itsexecuted a flexible
annual vegetation work plan. Examples of acceptable forms of evidence may include
a copy of the completed annual work plan (including modifications if any), dated
work orders, dated invoices, or dated inspection records.
Draft 4: June 16, 2010
14
3
FAC-003-2 — Transmission Vegetation Management
Compliance
Compliance Enforcement Authority
•
Regional Entity
Compliance Monitoring and Enforcement Processes:
•
•
•
•
•
•
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
Evidence Retention
The Transmission Owner retains data or evidence of Requirements R1 through R7, Measures
M1 through M7 for three calendar years to show compliance unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation.
If a Transmission Owner is found non-compliant, it shall keep information related to the noncompliance until found compliant, or for the duration specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all requested
and submitted subsequent audit records.
Additional Compliance Information
Periodic Data Submittal: (See Administrative Procedure)
Draft 4: June 16, 2010
15
3
FAC-003-2 — Transmission Vegetation Management
Time Horizons, Violation Risk Factors, and Violation Severity Levels
Table 1
R#
R1
R2
R3
Time
Horizon
Real-time
Real-time
Long-Term
Planning
VRF
Violation Severity Level
Lower
High
Medium
Lower
Draft 4: June 16, 2010
Moderate
High
Severe
The Transmission Owner
failed to prevent vegetation
from encroaching within the
MVCD of a transmission
line as described in R1.
The Transmission Owner
incurred a Sustained
Outage due to vegetation
falling into a transmission
line as described in R1
from within the Active
Transmission Line ROW.
The Transmission Owner
incurred a Sustained Outage
due to the blowing together of
vegetation and a transmission
line as described in R1 from
within the Active
Transmission Line ROW.
The Transmission Owner
incurred a Sustained Outage due
to vegetation growing into a
transmission line as described in
R1.
The Transmission Owner
failed to prevent vegetation
from encroaching within the
MVCD of a transmission
line as described in R2.
The Transmission Owner
incurred a Sustained
Outage due to vegetation
falling into a transmission
line as described in R2
from within the Active
Transmission Line ROW.
The Transmission Owner
incurred a Sustained Outage
due to the blowing together of
vegetation and a transmission
line as described in R2 from
within the Active
Transmission Line ROW.
The Transmission Owner
incurred a Sustained Outage due
to vegetation growing into a
transmission line as described in
R2.
The Transmission Owner
has a documented
transmission vegetation
management program, but
the transmission vegetation
management program does
not describe how work is
conducted on the Active
Transmission Line ROWs
to avoid Sustained Outages
due to vegetation.
The Transmission Owner has
a documented transmission
vegetation management
program, but the transmission
vegetation management
program does not consider all
possible locations the
conductor may occupy
assuming operation within
Rating and Rated Electrical
Operating Conditions
The Transmission Owner does
not have a documented
transmission vegetation
management program.
16
3
FAC-003-2 — Transmission Vegetation Management
R4
R5
R6
R7
Real-time
Operations
Planning
Operations
Planning
Operations
Planning
The Transmission Owner had
verified knowledge of a
vegetation imminent threat
condition and did not notify the
responsible control center.
Medium
The Transmission Owner did not
take interim corrective action
when it was temporarily
constrained from performing
planned vegetation work where
an applicable transmission line
was put at potential risk.
Medium
High
The Transmission Owner
inspected greater than 95%
but less than 100% of the
ROW as measured by
applicable-line miles
(kilometers) (based on units
of choice: circuit, pole line,
ROW, etc.).
The Transmission Owner
inspected greater than 90%
but less than or equal to
95% of the ROW as
measured by applicable-line
miles (kilometers) (based
on units of choice: circuit,
pole line, ROW, etc.).
The Transmission Owner
inspected greater than 85%
but less than or equal to 90%
of the ROW as measured by
applicable-line miles
(kilometers) (based on units
of choice: circuit, pole line,
ROW, etc.).
The Transmission Owner
inspected less than or equal to
85% of the ROW as measured by
applicable-line miles
(kilometers) (based on units of
choice: circuit, pole line, ROW,
etc.).
High
The Transmission Owner
executed greater than 95%
but less than 100% of its
annual work plan as
adjusted.
The Transmission Owner
executed greater than 90%
but less than or equal to
95% of its annual work
plan as adjusted.
The Transmission Owner
executed greater than 85%
but less than or equal to 90%
of its annual work plan as
adjusted.
The Transmission Owner
executed less than or equal to
85% of its annual work plan as
adjusted.
Draft 4: June 16, 2010
17
3
FAC-003-2 — Transmission Vegetation Management
Administrative Procedure
The Transmission Owner will submit a quarterly report to its Regional Entity, or the
Regional Entity’s designee, identifying all Sustained Outages of transmission lines
determined by the Transmission Owner to have been caused by vegetation that includes, as a
minimum, the following::.
o The name of the circuit(s), the date, time and duration of the outage; the voltage
of the circuit; a description of the cause of the outage; the category associated
with the Sustained Outage; other pertinent comments; and any countermeasures
taken by the Transmission Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation growing into
applicable transmission lines, that are identified as an element of an IROL or
Major WECC Transfer Path, by vegetation inside and/or outside of the active
transmission lineActive Transmission Line ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation growing into
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, by vegetation inside and/or outside of the active
transmission lineActive Transmission Line ROW;
o Category 2 — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines from within the active transmission lineActive
Transmission Line ROW;
o Category3 4 — Blowing together: Sustained Outages caused by vegetation and
applicable transmission lines blowing together from within the active
transmission lineActive Transmission Line ROW.
The Regional Entity will report the outage information provided by Transmission Owners, as
per the above, quarterly to NERC, as well as any actions taken by the Regional Entity as a
result of any of the reported Sustained Outages.
3
Category 3 reporting is eliminated.
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
Time Horizons, Violation Risk Factors, and Violation Severity Levels
At the request of the Standards Committee,
stakeholders are asked to review and comment on
the proposed VSLs for R1 and R2. Following the
comment period and nonbinding poll, only one set of
VSLs will move forward for R1 and R2.
Table 1
R#
R1SDT
Version
R1 Staff
Version
R2SDT
Version
Time
Horizon
Realtime
Realtime
Realtime
VRF
Violation Severity Level
Lower
High
The Transmission Owner
had an encroachment into
the MVCD observed in
real time, absent a
Sustained Outage.
Moderate
The Transmission Owner
had an encroachment due to
a fall-in from inside the
active transmission line
ROW that caused a
vegetation-related
Sustained Outage.
High
Medium
The Transmission Owner
had an encroachment into
the MVCD observed in
real time, absent a
Draft 4: June 16, 2010
The Transmission Owner
had an encroachment due to
a fall-in from inside the
active transmission line
High
Severe
The Transmission Owner had an
encroachment due to blowing
together of applicable lines and
vegetation located inside the
active transmission line ROW
that caused a vegetation-related
Sustained Outage.
The Transmission Owner had an
encroachment due to a grow-in
that caused a vegetation-related
Sustained Outage.
The Transmission Owner failed
to manage vegetation to prevent
encroachment into the MVCD of
a line identified as an element of
an IROL or Major WECC
transfer path and encroachment
into the MVCD as identified in
FAC-003-Table 2 was observed
in real time absent a Sustained
Outage.
The Transmission Owner failed
to manage vegetation to prevent
encroachment into the MVCD of
a line identified as an element of
an IROL or Major WECC
transfer path and a vegetationrelated Sustained Outage was
caused by one of the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside the
active transmission line
ROW
• A grow-in
The Transmission Owner had an
encroachment due to a grow-in
that caused a vegetation-related
Sustained Outage.
The Transmission Owner had an
encroachment due to blowing
together of applicable lines and
vegetation located inside the
25
FAC-003-2 — Transmission Vegetation Management
Table 1
R#
Time
Horizon
VRF
Violation Severity Level
Lower
Sustained Outage.
R2 Staff
Version
R3
Realtime
LongTerm
Planning
Moderate
ROW that caused a
vegetation-related
Sustained Outage.
Draft 4: June 16, 2010
The Transmission Owner
has documented the
procedures, processes, or
specifications but does not
incorporate the interrelationships between
vegetation growth rates,
vegetation control methods,
and inspection frequency,
Severe
active transmission line ROW
that caused a vegetation-related
Sustained Outage.
The Transmission Owner failed
to manage vegetation to prevent
encroachment into the MVCD of
a line not identified as an element
of an IROL or Major WECC
transfer path and encroachment
into the MVCD as identified in
FAC-003-Table 2 was observed
in real time absent a Sustained
Outage.
Medium
Lower
High
The Transmission Owner has
documented the procedures,
processes, or specifications but
does not incorporate the
dynamics of a transmission line
conductor’s movement
throughout its Rating and Rated
Electrical Operating Conditions,
for the Transmission Owner’s
The Transmission Owner failed
to manage vegetation to prevent
encroachment into the MVCD of
a line not identified as an
element of an IROL or Major
WECC transfer path and a
vegetation-related Sustained
Outage was caused by one of the
following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside the
active transmission line
ROW
• A grow-in
The Transmission Owner does
not have any documented
procedures, processes or
specifications used to prevent the
encroachment of vegetation into
the MVCD, for the Transmission
Owner’s applicable lines.
25
FAC-003-2 — Transmission Vegetation Management
Table 1
R#
Time
Horizon
VRF
Violation Severity Level
Lower
Moderate
for the Transmission
Owner’s applicable lines.
R4
R5
Realtime
Operatio
ns
Planning
R6
Operatio
ns
Planning
R7
Operatio
ns
Planning
High
applicable lines.
The Transmission Owner
experienced a vegetation threat
confirmed by qualified personnel
and notified the control center
holding switching authority for
that transmission line, but there
was intentional delay in that
notification.
Medium
Medium
The Transmission Owner
experienced a vegetation threat
confirmed by qualified personnel
and did not notify the control
center holding switching
authority for that transmission
line.
The Transmission Owner did not
take corrective action when it
was constrained from performing
planned vegetation work where a
transmission line was put at
potential risk.
Medium
Medium
Severe
The Transmission Owner
failed to inspect 5% or less
of the ROW as measured
by applicable-line miles
(kilometers) (based on
units of choice: circuit,
pole line, ROW, etc.).
The Transmission Owner
failed to inspect more than
5% up to and including
10% of the ROW as
measured by applicable-line
miles (kilometers) (based
on units of choice: circuit,
pole line, ROW, etc.).
The Transmission Owner failed
to inspect more than 10% up to
and including 15% of the ROW
as measured by applicable-line
miles (kilometers) (based on units
of choice: circuit, pole line,
ROW, etc.).
The Transmission Owner failed
to inspect more than 15% of the
ROW as measured by applicableline miles (kilometers) (based on
units of choice: circuit, pole line,
ROW, etc.).
The Transmission Owner
failed to complete up to
5% of its annual work plan
(including modifications if
any).
The Transmission Owner
failed to complete more
than 5% and up to 10% of
its annual work plan
(including modifications if
The Transmission Owner failed
to complete more than 10% and
up to 15% of its annual work plan
(including modifications if any).
The Transmission Owner failed
to complete more than 15% of its
annual work plan (including
modifications if any).
Draft 4: June 16, 2010
25
FAC-003-2 — Transmission Vegetation Management
Table 1
R#
Time
Horizon
VRF
Violation Severity Level
Lower
Moderate
High
Severe
any).
Draft 4: June 16, 2010
25
FAC-003-2 — Transmission Vegetation Management
Variances
None.
Interpretations
None.
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
Guidelines
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
Guideline and Technical Basis
Requirements R1 and R2:
Requirements R1 and R2 are performance-based requirements. The reliability objective or
outcome to be achieved is the prevention of vegetation encroachments within a minimum
distance of transmission lines. Content-wise, R1 and R2 are the same requirements; however,
they apply to different Facilities. Both R1 and R2 require each state that if a Transmission
Owner to prevent vegetation from encroaching within the Minimum Vegetation Clearance
Distance of transmission lines. R1 is applicable to lines “identified as an element of an
Interconnection Reliability Operating Limit (IROL) or Major Western Electricity Coordinating
Council (WECC) transfer path (operating within Rating and Rated Electrical Operating
Conditions) to avoid a Sustained Outage”. R2 applies to all other applicable lines that are not an
element of an IROL or Major WECC Transfer Path.
The separation of applicability (between R1 and R2) recognizes that an encroachment into the
MVCD of an IROL or Major WECC Transfer Path transmission line is a greater risk to the
electric transmission system. Applicable lines that are not an element of an IROL or Major
WECC Transfer Path are required to be clear of vegetation but these lines are comparatively less
operationally significant. As a reflection of this difference in risk impact, the Violation Risk
Factors (VRFs) are assigned as High for R1 and Medium for R2.
These requirements (R1 and R2) state that if vegetation encroaches observes vegetation within
the distances prescribed in FAC-003 - Table 2, it is in violation of the standard. Table 2
delineatesthis Standard. The MVCD table contains the distances necessary to prevent which are
required to ensure that spark-over will not occur; the distances are based on the Gallet equations
as described more fully in a supplemental Transmission Vegetation Management Standard FAC003-2 Technical Reference.
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating
(potentially in violation of other standards), the occurrence of a clearance encroachment may
occur. For example, emergency actions taken by a Transmission Operator or Reliability
Coordinator to protect an Interconnection may cause the transmission line to sag more and come
closer to vegetation, potentially causing an outage. Such vegetation-related outages are not a
violation of these requirements.
Evidence of violation of Requirement. Requirements R1 and R2 include real-time refer to
observation of a vegetation encroachment into the MVCD (absent a Sustained Outage), or a
vegetation-related encroachment resulting in a Sustained Outage due to a fall-in from inside the
active transmission line ROW, or a vegetation-related encroachment resulting in a Sustained
Outage due to blowing together of applicable lines and vegetation located inside the active
transmission line ROW, or a vegetation-related encroachment resulting in a Sustained Outage
due to a grow-in. If an investigation of a Fault by a qualified person confirms that a vegetation
encroachment within the MVCD occurred, then it shall be considered a Real-timein “real time”.
This means an actual field observation. or measurement of the conductor-to-vegetation distance
and not a calculated determination of relative positions.
With this approach, the VSLs were defined such that they directly correlate to the severity of a
failure to keep vegetation away from conductors and to the corresponding performance level of
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
the Transmission Owner’s vegetation program’s ability to meet the goal of “preventing a
Sustained Outage that could lead to Cascading.” Thus violation severity increases with a
Transmission Owner’s inability to meet this goal and its potential of leading to a Cascading
event. The additional benefits of such a combination are that it simplifies the standard and clearly
defines performance for compliance. A performance-based requirement of this nature will
promote high quality, cost effective vegetation management programs that will deliver the
overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation, for
example a limb that only partially breaks and intermittently contacts a conductor. Such events
are considered to be a single vegetation-related Sustained Outage under the Standard where the
Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will help prevent transmission outages. The
movement of the transmission line conductor and the MVCD is illustrated in Figure 1 below.
Requirement R3:
Requirement R3 is a competency based requirement concerned with the procedures, processes,
or specifications, a Transmission Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the
Transmission Owner uses to plan and perform vegetation work to prevent transmission Sustained
Outages and minimize risk to the Transmission System. The approach provides the basis for
evaluating the intent, allocation of appropriate resources and the competency of the Transmission
Owner in managing vegetation. There are many acceptable approaches to manage vegetation
and avoid Sustained Outages. However, the Transmission Owner must be able to state what its
approach is and how it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach a
Transmission Owner chooses to use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the Transmission Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing as a reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figure 1 below.
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
Figure 1
Cross-section view of a single conductor at a given point along the span showing six possible
conductor positions due to movement resulting from thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the
Transmission Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
involves the notification of potentially threatening vegetation conditions, without any intentional
delay, to the control center holding switching authority for that specific transmission line.
Examples of acceptable unintentional delays may include communication system problems (for
example, cellular service or two-way radio disabled), crews located in remote field locations
with no communication access, delays due to severe weather, etc.
Confirmation is key that aBy complying with encroachment-prevention Requirements R1 and
R2, together with the competency-based Requirement R3 (for a documented transmission
vegetation management program), the Transmission Owner will have a cohesive vegetation
management program for managing vegetation in such a manner as to maintain separation
between conductors and vegetation. Additionally, an effective imminent threat process and
interim corrective action plan strategies should be executed to be successful in meeting these
requirements. The Transmission Owner’s maintenance approach should result in vegetation
never approaching the distances listed in the MVCD Table. However, brief encroachments by
falling vegetation are not considered to be a violation.
In addition, the Transmission Owner should maintain detailed records of the findings of its
planned inspections. This documentation constitutes evidence that the Transmission Owner had
no encroachments into the MVCD Table distances.
These requirements assume that transmission lines are operating within their Rating. If a line
conductor is intentionally or inadvertently operated beyond its rating (potentially in violation of
other standards), the occurrence of a clearance encroachment is not be a violation of this
Standard. Conductor position, and the associated vegetation distance, that result from operation
of a transmission line beyond its Rating (for example emergency actions taken by a TOP or RC
to protect an Interconnection) is beyond the scope of this Standard.
Requirement R3:
An adequate transmission vegetation management program formally establishes the guidelines
that are used by the Transmission Owner to plan and perform vegetation work that is necessary
to prevent transmission outages and minimize risk to the Transmission System.
There may be many acceptable approaches to maintain clearances. However, the Transmission
Owner should be able to state what its approach is and how it conducts work to maintain
clearances. See Figure 1 for illustration of possible conductor locations.
Requirement R4:
The term “verified knowledge” implies reliable confirmation that an imminent threat actually
exists due to vegetation. This confirmation Verification could be in that the form ofinitial callin came from a qualifiedtrained employee who personally identifiesable to identify such a threat
in the field. Confirmation or it could also be madeverified by sending out such a qualifiedtrained
person to evaluate a situation reported by a landowner or an unqualified employee.confirm a
call-in from a citizen.
VegetationTwo key elements of an acceptable imminent threat procedure are outlined below:
• Specify the vegetation-related conditions that warrant a response :
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
Examples of these vegetation-related conditions include vegetation that is near or encroaching
into the MVCD (a grow-in growth issue) or vegetation that could fallpresents an imminent
danger of falling into the transmission conductor (a fall-in issue). A knowledgeable verification
of the risk would include an assessment of the possible sag or movement of the conductor while
operating between no-load conditions and its rating.)
• Notify the appropriate operating authority:
The Transmission Owner has the responsibility to ensure the proper communication between
field personnel and the control centeroperating authority to allow the control centeroperating
authority to take the appropriate action until the vegetation threat is relieved. Appropriate
actions may include a temporary reduction in the line loading, or switching the line out of
service, or positioning the system in recognition of the increasing risk of outage on that circuit.
The notification of the threat should be communicated in terms of minutes or hours as opposed to
a longer time frame for corrective action plans (see R5)..
The protocol for contacting the operating authority should be defined. Some
Transmission Owners’ processes may require a call directly to the operating authority,
while other Transmission Owners may require a call to a supervisor or field forester who
will in turn notify the proper operating authority.
The term “responsible control center” refers to personnel with direct responsibility for
operating the transmission lines, such as the Transmission Owner’s control center, an
Independent System Operator, or other operating entity. In the case where the operating
authority is not the Transmission Operator the communication between the Transmission
Operator and the operating authority will occur by the normal policies that govern their
relationship.
The imminent threat process should be implemented in terms of minutes or hours as opposed to a
longer time frame for interim corrective action plans (see R5).
All potential grow-inserious growth or fall-in vegetation-related conditions will are not
necessarily cause a Fault at any moment.considered imminent threats under this Standard. For
example, some Transmission Owners may have a danger tree identification program that
identifies trees for removal trees with the potential to fall near the line. These trees wouldare not
require notification tonecessarily considered imminent threats under the control centerStandard
unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
Transmission Owner for the mitigation of Sustained Outage risk when temporarily constrained
from performing vegetation maintenance.
There can be situations involving vegetation that are not considered vegetation-related imminent
threats under this Standard. For example, a logging operation on or near the Active
Transmission Line ROW can pose an immediate threat of a sustained outage and result in the
initiation of an imminent threat process in the same manner as the presence of a nearby crane or
the notification of a hot-spot on a conductor connector. Although the logging threat in this
example tangentially involves vegetation, it is not considered a vegetation-related imminent
threat under the Standard.
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
Requirement R5:
The intent of this requirement is to deal with situations that prevent the Transmission Owner
from performing planned vegetation management work and, as a result, have the potential to put
the transmission line at risk. Constraints to performing vegetation maintenance work as planned
could result from legal injunctions filed by property owners, the discovery of easement
stipulations which limit the Transmission Owner’s rights, or other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potentialimmediate risk and the work event can be rescheduled or re-planned using an alternate
work methodology. For example, a land owner may prevent the planned use of chemicals on
non-threatening, low growth vegetation but agree to the use of mechanical clearing. In this case
the Transmission Owner is not under any immediate time constraint for achieving the
management objective, can easily reschedule work using an alternate approach, and therefore
does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the Transmission Owner is required to take an interim corrective action to mitigate the potential
risk to the transmission line. A wide range of actions can be taken to address various situations.
General considerations include:
•
•
•
•
•
Identifying locations where the Transmission Owner is constrained from performing
planned vegetation maintenance work which potentially leaves the transmission line
at risk.
Developing the specific action to immediately mitigate any potential risk associated
with not performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for each location.
In developing the specific action to mitigate the potential risk to the transmission line
the Transmission Owner could consider location specific measures such as modifying
the inspection and/or maintenance intervals. Where a legal constraint would not
allow any vegetation work, the interim corrective action could include limiting the
loading on the transmission line.
The Transmission Owner should document and track the specific corrective action
taken at each location. This location may be indicated as one span, one tree or a
combination of spans on one property where the constraint is considered to be
temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing the
Vegetation Inspections that fits general industry practice. In addition, the fact that Vegetation
Inspections can be performed in conjunction with general line inspections further facilitates a
Transmission Owner’s ability to meet this requirement. However, the Transmission Owner may
determine that more. More frequent inspections aremay be needed to maintain reliability levels,
dependentdepending upon such factors as anticipated growth rates of the local vegetation, length
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
of the growing season for the geographical area, limited Active Transmission ROW width, and
rainfall amounts. Therefore it is expected that some transmissionsome lines may be designated
with a higher frequency of inspections.
The VSL for Requirement R6 has VSL categories ranked by the percentage of the required ROW
inspections completed. To calculate the percentage of inspection completion, the Transmission
Owner lines may choose units such as: line miles or kilometers, circuit miles or kilometers, pole
line miles, ROW miles, etc.
For example, whenIf a Transmission Owner operates 2,000 miles of 230 kV transmission lines
this Transmission Owner will be responsible for inspecting all 2,000 miles of 230 kV
transmission lines at least once line during the calendar year. If one of the included lines was
100 miles long, and if it was not inspected during the year, then the amount failed to
inspectinspected would be 1001900/2000 = 0.0595 or 5%.95%. The “LowLower VSL” for R6
would apply in this example.
The standard allows Vegetation Inspections to be performed in conjunction with general line
inspections as per the definition.
Requirement R7:
R7 is a risk-based requirement. The Transmission Owner is required to implement an annual
work plan for vegetation management to accomplish the purpose of this standard. Modifications
to the work plan in response to changing conditions or to findings from vegetation inspections
may be made and documented provided they do not put the transmission system at risk. The
annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a
“line-by-line” detailed description of all work to be performed. It is only intended to require that
the Transmission Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation into
the MVCD.
The ability to modify the work plan allows Documentation or other evidence of the work
performed typically consists of signed-off work orders, signed contracts, printouts from work
management systems, spreadsheets of planned versus completed work, timesheets, work
inspection reports, or paid invoices. Other evidence may include photographs, work inspection
reports and walk-through reports.
Documentation is required when the annual work plan is adjusted or not completely
implemented as originally planned. The reasons for the deferrals or changes and the expected
completion date of postponed work should be documented.
The flexibility to adjust the annual work plan must always ensure the reliability of the electric
Transmission system. Flexibility is meant to address changing conditions of the vegetation on
the Active Transmission Line ROW, emergencies, and other significant changing conditions.
This standard requires that the annual work plan be flexible to allow the Transmission Owner to
change priorities or treatment methodologies during the year as conditions or situations dictate.
For example recent line inspections may identify unanticipated high priority work, weather
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
conditions (drought) could make herbicide application ineffective during the plan year, or.
Another situational variance could be a major storm could require redirectingthat redirects local
resources away from planned maintenance. This situation may also include complying with
mutual assistance agreements by moving resources off the Transmission Owner’s system to work
on another system. AnyExamples of these examples could result in acceptabledocumented
adjustments may include deferrals or additions to the annual work plan. Modifications to the
annual work plan must always ensure the reliability of the electric Transmission system.
In general, the
The work plan is not intended to be a “span-by-span” detailed description of all work to be
performed. It is intended to require the Transmission Owner to annually plan and schedule
vegetation work to prevent encroachment into the MVCD.
The Transmission Owner is required to implement the annual work plan for vegetation
management to accomplish the purpose of this standard. This means that vegetation maintenance
approach should useought to be performed to the full extent of the Transmission Owner’s
easement, fee simple and other legal rights. It is intended to address the importance of
maintaining all locations on the Active Transmission Line ROWs for reliability purposes in lieu
of making special exceptions.
•
Property owners and other interested parties occasionally request special considerations
to leave undesirable vegetation conditions. Such considerations must never be allowed.
to impact reliability.
• These undesirable vegetation conditions require more frequent work or inspections than
other locations with similar vegetation threats and similar easement rights which are not
subject to the special property owner requests.
• The Transmission Owner's vegetation maintenance work necessary to implement the
annual work plan is most effective when performed to the maximum extent allowed by
any easement, fee simple and other legal rights.
• The Transmission Owner should, therefore, endeavor to maintain its Active Transmission
Line ROW to the full extent of its legal rights at all times and in all cases.
A comprehensive approach that exercises the full extent of legal rights on the active transmission
line ROW is superior to incremental management in the long term because it reduces the overall
potential for encroachments, and it ensures that future planned work and future planned
inspection cycles are sufficient. at all locations on the Active Transmission Line ROW .
When developing the annual work plan the Transmission Owner should allow time for
procedural requirements to obtain permits to work on federal, state, provincial, public, tribal
lands. In some cases the lead time for obtaining permits may necessitate preparing work plans
more than a year prior to work start dates. Transmission Owners may also need to consider those
special landowner requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the Transmission
Owner, evidence of successful annual work plan execution could consist of signed-off work
orders, signed contracts, printouts from work management systems, spreadsheets of planned
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence
may include photographs, and walk-through reports.
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
The following conditions may result in adjustments to the annual work plan: abnormal weather
such as drought, major storms, excessive rainfall, other environmental conditions such as
infestation, disease, fire, etc. These conditions may be found as part of a special or scheduled
Vegetation Inspection. Examples of annual work plan adjustments that are permitted may
include revising the work plan priorities, rescheduling work to another time or selecting alternate
vegetation control methods. Changes in land usage made by a property owner, such as timber
clearing, may be another condition that warrants an adjustment.
Draft 4: June 16, 2010
FAC-003-2 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 4
For Alternating Current Voltages
( AC )
Nominal
System
Voltage
(kV)
( AC )
Maximum
System
Voltage
(kV)
765
800
500
550
345
362
230
242
161*
169
138*
145
115*
121
88*
100
69*
72
MVCD
feet
(meters)
sea level
8.06ft
(2.46m)
5.06ft
(1.54m)
3.12ft
(0.95m)
2.97ft
(0.91m)
2ft
(0.61m)
1.7ft
(0.52m)
1.41ft
(0.43m)
1.15ft
(0.35m)
0.82ft
(0.25m)
MVCD
feet
(meters)
3,000ft
(914.4m)
MVCD
feet
(meters)
4,000ft
(1219.2m)
MVCD
feet
(meters)
5,000ft
(1524m)
MVCD
feet
(meters)
6,000ft
(1828.8m)
8.89ft
(2.71m)
5.66ft
(1.73m)
3.53ft
(1.08m)
3.36ft
(1.02m)
2.28ft
(0.69m)
1.94ft
(0.59m)
1.61ft
(0.49m)
1.32ft
(0.40m)
0.94ft
(0.29m)
9.17ft
(2.80m)
5.86ft
(1.79m)
3.67ft
(1.12m)
3.49ft
(1.06m)
2.38ft
(0.73m)
2.03ft
(0.62m)
1.68ft
(0.51m)
1.38ft
(0.42m)
0.99ft
(0.30m)
9.45ft
(2.88m)
6.07ft
(1.85m)
3.82ft
(1.16m)
3.63ft
(1.11m)
2.48ft
(0.76m)
2.12ft
(0.65m)
1.75ft
(0.53m)
1.44ft
(0.44m)
1.03ft
(0.31m)
9.73ft
(2.97m)
6.28ft
(1.91m)
3.97ft
(1.21m)
3.78ft
(1.15m)
2.58ft
(0.79m)
2.21ft
(0.67m)
1.83ft
(0.56m)
1.5ft
(0.46m)
1.08ft
(0.33m)
MVCD
feet
(meters)
7,000ft
(2133.6m)
MVCD
feet
(meters)
8,000ft
(2438.4m)
MVCD
feet
(meters)
9,000ft
(2743.2m)
MVCD
feet
(meters)
10,000ft
(3048m)
MVCD
feet
(meters)
11,000ft
(3352.8m)
10.01ft
(3.05m)
6.49ft
(1.98m)
4.12ft
(1.26m)
3.92ft
(1.19m)
2.69ft
(0.82m)
2.3ft
(0.70m)
1.91ft
(0.58m)
1.57ft
(0.48m)
1.13ft
(0.34m)
10.29ft
(3.14m)
6.7ft
(2.04m)
4.27ft
(1.30m)
4.07ft
(1.24m)
2.8ft
(0.85m)
2.4ft
(0.73m)
1.99ft
(0.61m)
1.64ft
(0.50m)
1.18ft
(0.36m)
10.57ft
(3.22m)
6.92ft
(2.11m)
4.43ft
(1.35m)
4.22ft
(1.29m)
2.91ft
(0.89m)
2.49ft
(0.76m)
2.07ft
(0.63m)
1.71ft
(0.52m)
1.23ft
(0.37m)
10.85ft
(3.31m)
7.13ft
(2.17m)
4.58ft
(1.40m)
4.37ft
(1.33m)
3.03ft
(0.92m)
2.59ft
(0.79m)
2.16ft
(0.66m)
1.78ft
(0.54m)
1.28ft
(0.39m)
11.13ft
(3.39m)
7.35ft
(2.24m)
4.74ft
(1.44m)
4.53ft
(1.38m)
3.14ft
(0.96m)
2.7ft
(0.82m)
2.25ft
(0.69m)
1.86ft
(0.57m)
1.34ft
(0.41m)
* Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above).
4
The distances in this Table are the minimums required to prevent Flashoverflashover; however prudent vegetation maintenance practices dictate that
substantially greater distances will be achieved at time of vegetation maintenance.
Draft 3: March 1, 2010
35
FAC-003-2 — Transmission Vegetation Management
Table 2 (cont.) — Minimum Vegetation Clearance Distances (MVCD)
For Direct Current Voltages
sea level
MVCD feet
(meters)
3,000ft
(914.4m)
Alt.
MVCD feet
(meters)
4,000ft
(1219.2m)
Alt.
MVCD feet
(meters)
5,000ft
(1524m)
Alt.
MVCD feet
(meters)
6,000ft
(1828.8m)
Alt.
MVCD
feet
(meters)
7,000ft
(2133.6m)
Alt.
MVCD
feet
(meters)
(8,000ft
(2438.4m)
Alt.
MVCD
feet
(meters)
9,000ft
(2743.2m)
Alt.
MVCD
feet
(meters)
10,000ft
(3048m)
Alt.
MVCD
feet
(meters)
11,000ft
(3352.8m)
Alt.
±750
13.92ft
(4.24m)
15.07ft
(4.59m)
15.45ft
(4.71m)
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.9ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
±600
10.07ft
(3.07m)
11.04ft
(3.36m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
(13.54ft
4.13m)
±500
7.89ft
(2.40m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
±400
4.78ft
(1.46m)
5.35ft
(1.63m)
5.55ft
(1.69m)
5.75ft
(1.75m)
5.95ft
(1.81m)
6.15ft
(1.87m)
6.36ft
(1.94m)
6.57ft
(2.00m)
6.77ft
(2.06m)
6.98ft
(2.13m)
±250
3.43ft
(1.05m)
4.02ft
(1.23m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5ft
(1.52m)
5.17ft
(1.58m)
( DC )
Nominal Pole
to Ground
Voltage
(kV)
MVCD feet
(meters)
Draft 3: March 1, 2010
36
FAC-003-2 — Transmission Vegetation Management
Table 3 – Minimum Distance from the Centerline of the Circuit to the edge of the active transmission line ROW
Draft 3: March 1, 2010
69 - 138 kV
37.5 ft.
139 - 230 kV
50 ft.
231 - 345 kV
75 ft.
346 - 500 kV
87.5 ft.
501 - 765 kV
100 ft.
37
Implementation Plan for FAC-003-2
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress
or approved, that must be implemented before this standard can be implemented.
FAC-003-2 – Vegetation Management
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. There is a
revised definition in the proposed standard. FAC-003-1 will be retired when FAC-003-2
becomes effective.
Compliance with Standard
The standard applies to Transmission Owners.
Effective Date
The effective date is the date entities are expected to meet the performance identified in this
standard. The effective date allows entities time to make revisions to their existing transmission
vegetation management programs to comply with the new requirements.
1. First calendar day of the first calendar quarter one year after applicable regulatory
authority approval for all requirements
2. First calendar day of the first calendar quarter one year following Board of Trustees
adoption unless governmental authority withholds approval
3. First calendar day of the first calendar quarter that is at least one year following Board of
Trustees adoption
Exceptions:
A line operated below 200kV, designated by the Planning Coordinator as an element of
an IROL or as a Major WECC transfer path, becomes subject to this standard 12
months after the date the Planning Coordinator or WECC initially designates the line as
being subject to this standard.
An existing transmission line operated at 200kV or higher that is newly acquired by an
asset owner and was not previously subject to this standard, becomes subject to this
standard 12 months after the acquisition date of the line.
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com
Implementation Plan for FAC-003-2
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress
or approved, that must be implemented before this standard can be implemented.
FAC-003-2 —– Vegetation Management
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. There is a
revised definition in the proposed standard. FAC-003-1 will be retired when FAC-003-2
becomes effective.
When FAC-003-2 is approved, a new definition for Active Transmission Line Right-of-Way and
a revised definition for Vegetation Inspection should become effective.
The original definition of Vegetation Inspection should be retired when the new definition
becomes effective.
FAC-003-1 will be retired when FAC-003-2 becomes effective.
Compliance with Standard
The standard applies to Transmission Owners.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Effective Date
The effective date is the date entities are expected to meet the performance identified in this standard. The effective date allows entities time to make
revisions to their existing transmission vegetation management programs to comply with the new requirements.
Requirement
Jurisdiction
Alberta
British
Columbia
Manitoba
New
Brunswick
Newfoundland
Nova
Scotia
Ontario
Quebec
Saskatchewan
USA
R1
1
1
1
3
TBD
TBD
2
TBD
1
1
R2
1
1
1
3
TBD
TBD
2
TBD
1
1
R3
1
1
1
3
TBD
TBD
2
1
1
R4
1
1
1
3
TBD
TBD
2
TBD
1
1
R5
1
1
1
3
TBD
TBD
2
TBD
1
1
R6
1
1
1
3
TBD
TBD
2
TBD
1
1
R7
1
1
1
3
TBD
TBD
2
TBD
1
1
1. First calendar day of the first calendar quarter one year after applicable regulatory authority approval for all requirements
2. First calendar day of the first calendar quarter one year following Board of Trustees adoption unless governmental authority withholds
approval
3. First calendar day of the first calendar quarter that is at least one year following Board of Trustees adoption
Exceptions:
LinesA line operated below 200kV, designated by the Planning Coordinator as an element of an IROL or as a Major WECC Transfer
Path, becometransfer path, becomes subject to this standard 12 months after the date the Planning Coordinator or WECC initially
designates the linesline as being subject to this standard.
An existing transmission line operated at 200kV or higher that is newly acquired by an asset owner and was not previously subject to this
standard, becomes subject to this standard 12 months after the acquisition date of the line(s)..
March 1, 2010
2
Unofficial Comment Form for 4th Draft of FAC-003-2 Transmission
Vegetation Management —Project 2007-07 Vegetation Management
Please DO NOT use this form to submit comments. Please use the electronic form located at
the site below to submit comments on the 4th Draft of FAC-003-2 Transmission Vegetation
Management. Comments must be submitted by, July 18, 2010
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
If you have questions please contact Harry Tom at [email protected] or by telephone at
(860) 550-4157.
Background Information
The purpose of Project 2007-07 Vegetation Management is to:
•
Assist in providing an adequate level of reliability for the North American electric
Transmission System by verifying that the FAC-003-2 Transmission Vegetation
Management standard is complete and that its requirements are set at an
appropriate level to ensure reliability.
•
Incorporate other general improvements described in the Standard Review
Guidelines to bring FAC-003-2 Transmission Vegetation Management into
conformance with the latest version of the Reliability Standards Development
Procedure and the ERO Sanctions Guidelines.
•
Consider comments received from ERO regulatory authorities and stakeholders on
FAC-003-1 Transmission Vegetation Management as noted in the NERC Standards
Issues Database.
•
Satisfy the requirement for review of FAC-003-2 Transmission Vegetation
Management within five-year review cycle.
In addition, on January 14, 2010, the NERC Standards Committee endorsed the use of
Project 2007-07 Vegetation Management as the prototype for the proof-of-concept for using
the results-based criteria for developing a reliability standard. The results-based initiative is
intended to focus the collective effort of NERC and industry participants on improving the
clarity and quality of NERC reliability standards by developing performance-based, riskbased and competency-based requirements that accomplish a reliability objective through a
defense-in-depth strategy, while eliminating documentation-driven requirements that do not
have an impact on bulk power system reliability.
The first draft of the revised standard was posted in a ‘new’ format from March 1-31, 2010
for an ‘informal’ comment period.
A summary of the SDT considerations for the responses to the March 1, 2010 submittal has
been posted on the NERC website in lieu of a full Consideration of Comments Report.
Note-worthy modifications incorporated into this draft 4 of FAC-003-2 Transmission
Vegetation Management include:
•
Replaced the defined term “Active Transmission Line Right of Way” with footnote
number 2 that provides a description of “active transmission line ROW” and added
Table 3, “Minimum Distance from the Centerline of the Circuit to the edge of the
active transmission line ROW” to support that description.
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com
Unofficial Comment Form for 3rd Draft of FAC-003-2 — Project 2007-07 Vegetation
Management
•
Terminology changes in the “Force Majeure” statement related to the terms
“reasonable” and “human activity”
•
Terminology changes to Measures M1 and M2 related to observation in real time and
the investigation of Faults.
•
Changes to Requirement R3 to incorporate the various terms the industry uses for
program documentation, and further changes to R3 that address the nature of the
mutually dependent variables that can drive different approaches to vegetation
maintenance.
•
Clarifying verbiage in Requirement R4.
•
Removal of the term “flexible” in R7
•
Footnote changes for clarification to Table 2
The following questions will assist the SDT in finalizing the development of FAC-003-2
Transmission Vegetation Management. In addition, question #7, relative to Violation
Severity Levels, has been included at the direction of the Standards Committee.
For questions where you agree with indicated statement, please state that you agree and if
able, please provide supporting documentation. If you disagree with the statement, please
explain why you disagree and provide a rationale to support your position. We would
appreciate responses to as many of the following questions as possible.
1. The SDT replaced the defined term “Active Transmission Line Right of Way” with
footnote number 2 that provides a description of “active transmission line ROW” and
added Table 3, “Minimum Distance from the Centerline of the Circuit to the edge of the
active transmission line ROW” to support that description. Do you agree? Please explain.
Yes
No
Comments:
2. In response to comments received regarding the terms “reasonable” and “human
errors/human activity”, the SDT modified the Other Section and Background Section. Do
you agree? Please explain.
Yes
No
Comments:
3. In response to comments received regarding the language in M1 and M2, the SDT
modified the first bulleted item and added a sentence to the end of the paragraph in M1
and M2. Do you agree? Please explain.
Yes
No
Comments:
4. In response to comments received that requirement R3 is deficient in detail, the SDT
modified the requirement. Do you agree? Please explain.
Yes
No
2
Unofficial Comment Form for 3rd Draft of FAC-003-2 — Project 2007-07 Vegetation
Management
Comments:
5. In response to comments received that requirement R7 is unclear with respect to flexible
work plans, the SDT modified the requirement. Do you agree? Please explain.
Yes
No
Comments:
6. In response to comments received that requirement R1/R2 may not adequately protect
the transmission conductors under all conditions of sag and sway, the SDT drafted
alternate language for the industry to provide feedback. The SDT did not opt to
incorporate this language into “Draft 4” until further comment was solicited from
industry. Which do you prefer? Please comment on your choice in the comment box
below:
“Alternate R1/R2. Each Transmission Owner shall manage the floor of
its Active Transmission Line ROW in accordance to one of the following at
all times:
A) A fixed maximum vegetation height of 15 feet from the ground at
the mid-half of the span and 20 feet in the outside quarters of the
span, or,
B) A calculated maximum vegetation height that is the difference
between the minimum conductor height at “max sag” minus MVCD
minus cycle growth, or,
C) A calculated minimum vegetation to conductor clearance that is the
sum of “max sag” in the span plus MVCD plus cycle growth, or,
D) A value determined by the Transmission Owner to provide a
separation between the conductor and the vegetation that is
comparable to options A, B, or C.
E) Any alternative approach that ensures no encroachment occurs
within MVCD, considering the sag and sway of the conductor
throughout its operating range under rated conditions.
F) A value to provide a separation between the conductor and the
vegetation that is the sum of MVCD, and a value that considers the
sag and sway of the conductor throughout its operating range
under rated conditions plus 10 feet.”
NOTE: The SDT suggests similar language as found in the posted draft for
measures M1/M2 may be appropriate with this alternate R1/R2.
Draft 4 version of R1/R2
Alternate version of R1/R2
Comment:
7. The drafting team and NERC staff disagree on an appropriate set of VSLs for
Requirements R1 and R2 and the Standards Committee has directed that both sets of
VSLs be posted for stakeholder comments.
The drafting team has proposed the following VSLs for R1 and R2:
3
Unofficial Comment Form for 3rd Draft of FAC-003-2 — Project 2007-07 Vegetation
Management
VSLs for R1 and R2 Proposed by the VM SDT
R#
Lower
Moderate
High
Severe
R1
VM
SDT
The Transmission Owner had
an encroachment into the
MVCD observed in real time,
absent a Sustained Outage.
The Transmission Owner
had an encroachment due to
a fall-in from inside the active
transmission line ROW that
caused a vegetation-related
Sustained Outage.
The Transmission Owner had
an encroachment due to
blowing together of applicable
lines and vegetation located
inside the active transmission
line ROW that caused a
vegetation-related Sustained
Outage.
The Transmission Owner
had an encroachment
due to a grow-in that
caused a vegetationrelated Sustained
Outage.
R2
VM
SDT
The Transmission Owner had
an encroachment into the
MVCD observed in real time,
absent a Sustained Outage.
The Transmission Owner
had an encroachment due to
a fall-in from inside the active
transmission line ROW that
caused a vegetation-related
Sustained Outage.
The Transmission Owner had
an encroachment due to
blowing together of applicable
lines and vegetation located
inside the active transmission
line ROW that caused a
vegetation-related Sustained
Outage.
The Transmission Owner
had an encroachment
due to a grow-in that
caused a vegetationrelated Sustained
Outage.
VSLs for R1 and R2 Proposed by the VM SDT
The SDT assigned VSLs for R1 and R2 in accordance with its interpretation of the VSL
Guidelines. To support that interpretation, the SDT cites page 3 of the VSL Guideline as
justification. The VSL Guideline states that for – “Requirements with Parts that Contribute
Unequally to the Requirement: If a requirement has several parts, and the parts contribute
unequally to the reliability-related objective of the requirement, then noncompliance with
each of the parts should be clearly associated with at least one of the VSLs.”
The VSL Guidelines also goes on to say, “Requirements with Wide Range of Noncompliant
Performance: If a requirement has a wide range of noncompliant performance that at least
partially meets the intent of the requirement, then that requirement should have multiple
VSLs. There are many different ways of developing VSLs to categorize different degrees of
noncompliant performance. A set of VSLs developed should collectively address all of the
elements in the requirement. Thus, if a requirement includes both specific actions and a
timeframe for completion of those actions, then the VSLs should address noncompliance
with both the completeness of the actions and the timeliness of those actions. Not all VSLs
need to address both components of the requirement, but collectively the set of VSLs must
address all aspects of the requirement.” The SDT asserts that for Requirement R1 there is
indeed a wide range of possible noncompliance for a failure to manage vegetation.
Examples could include failure to manage vegetation along an entire line, failure to manage
the floor of the right of way, failure to manage the edges of the right of way, or a failure to
manage a single tree out of an otherwise-well-managed right of way.
The SDT points to the reliability objectives contained in requirements R1 and R2. The
Transmission Owner is required to manage vegetation to prevent encroachments within the
MVCD that could lead to Sustained Outages. These objectives address different degrees or
types of vegetation encroachments and associated reliability results. For example, not all
encroachments lead to Sustained Outages. Moreover, there is an operational differentiation
between a fall-in, blow-together or grow-in event. A fall-in has never been known to cause
a cascading outage. Therefore the team feels that a Lower VSL is appropriate. A blowingtogether-caused fault is somewhat more egregious than a fall-in, as it has the potential for
re-occurring and is therefore assigned a Higher VSL. A grow-in from vegetation on the
active ROW that causes a sustained outage, on the other hand, has been the only known
cause for the initiation of cascading outages to date in North America and this type of
4
Unofficial Comment Form for 3rd Draft of FAC-003-2 — Project 2007-07 Vegetation
Management
vegetation should be appropriately addressed by a Transmission Owner; thus the Severe
VSL. For these reasons the SDT feels that the VSL assignments are appropriate.
VSLs for R1 and R2 Proposed by NERC Staff
The Standards Staff is concerned that the VSLs proposed by the VM SDT seem to be based
on the likelihood that a violation of the requirement will result in a sustained outage – not in
the degree to which the entity violated the requirement. As such, the VSLs developed by
the VM SDT don’t support NERC’s VSL Guidelines. Both R1 and R2 require the responsible
entity to “. . . manage vegetation to prevent encroachment that could result in a Sustained
Outage . . .” Thus, any sustained outage associated with vegetation-related encroachment
into the MVCD totally misses the intent of the requirement and meets the criteria for a
Severe VSL. The drafting team’s proposed VSL would assign some vegetation-related
sustained outages of transmission lines as “moderate” or “high” VSLs.
NERC’s VSL Criteria
Lower
Moderate
High
Severe
Missing a minor element
(or a small percentage) of
the required performance
The performance or
product measured has
significant value as it
almost meets the full
intent of the requirement.
Missing at least one
significant element (or a
moderate percentage) of
the required performance.
The performance or
product measured still has
significant value in
meeting the intent of the
requirement.
Missing more than one
significant element (or is
missing a high
percentage) of the
required performance or
is missing a single vital
component.
The performance or
product has limited value
in meeting the intent of
the requirement.
Missing most or all of the
significant elements (or a
significant percentage) of
the required performance.
The performance
measured does not meet
the intent of the
requirement or the
product delivered cannot
be used in meeting the
intent of the requirement.
The Standards Staff proposes the following VSLs:
VSLs for R1 and R2 Proposed by NERC Staff
R#
R1
NERC
Staff
Lower
Not applicable.
Moderate
Not applicable.
High
Severe
The Transmission Owner
failed to manage vegetation
to prevent encroachment into
the MVCD of a line identified
as an element of an IROL or
Major WECC transfer path
and encroachment into the
MVCD as identified in FAC003-Table 2 was observed in
real time absent a Sustained
Outage.
The Transmission Owner
failed to manage
vegetation to prevent
encroachment into the
MVCD of a line identified
as an element of an IROL
or Major WECC transfer
path and a vegetationrelated Sustained Outage
was caused by one of the
following:
•
A fall-in from inside
the active
transmission line
ROW
•
Blowing together of
applicable lines and
vegetation located
inside the active
transmission line
ROW
•
A grow-in
5
Unofficial Comment Form for 3rd Draft of FAC-003-2 — Project 2007-07 Vegetation
Management
VSLs for R1 and R2 Proposed by NERC Staff
R#
R2
NERC
Staff
Lower
Not applicable.
Moderate
Not applicable.
High
Severe
The Transmission Owner
failed to manage vegetation
to prevent encroachment into
the MVCD of a line not
identified as an element of an
IROL or Major WECC transfer
path and encroachment into
the MVCD as identified in
FAC-003-Table 2 was
observed in real time absent
a Sustained Outage.
The Transmission Owner
failed to manage
vegetation to prevent
encroachment into the
MVCD of a line not
identified as an element
of an IROL or Major
WECC transfer path and
a vegetation-related
Sustained Outage was
caused by one of the
following:
•
A fall-in from inside
the active
transmission line
ROW
•
Blowing together of
applicable lines and
vegetation located
inside the active
transmission line
ROW
•
A grow-in
Which set of proposed VSLs best supports NERC’s VSL Criteria?
VSLs proposed by the VM SDT
VSLs proposed by NERC staff
Comments:
8. Is there anything that you have not addressed above regarding the draft FAC-003-2
Transmission Vegetation Management standard or the Technical Reference Document? If
yes, please provide what you believe should be changed, added or deleted and the
rationale for your proposal.
Yes
No
Comments:
6
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
Standard FAC-003-1
Comment
Proposed Standard FAC-003-2 RBS Draft 4
Standard Development Roadmap
Modified per proposed SCPSC format for RBS
Standard Development Timeline
Definitions of Terms Used in Standard
During the first comment period, the SDT received
several comments noting that many utilities typically
combine the vegetation inspection with other
maintenance inspections. Due to the comments, the SDT
proposed a modified Vegetation Inspection definition to
document the acceptability of this industry practice. As
noted in the “Guidelines and Technical Basis” section,
this broader definition facilitates a Transmission Owner’s
ability to meet the requirement and the added clarification
aides compliance understanding to meet Requirement 6.
Definitions of Terms Used in Standard
Effective Dates
5. Effective Dates:
5.1. One calendar year from the date
of adoption by the NERC Board of
Trustees for Requirements 1 and 2.
5.2. Sixty calendar days from the date
of adoption by the NERC Board of
Trustees for Requirements 3 and 4.
In order to fully implement any new standard or
requirement it is necessary to factor in a reasonable
transitional period. As with the current version of FAC003, the proposed version allows a reasonable time
period before the standard is fully applicable. In addition
to standardizing the implementation date to coincide with
the beginning of a calendar month, the new version
improves upon the current standard by recognizing that
new lines may be added by the Planning Coordinator at
any given time in the future. These new lines will
necessarily require an extended effective date before the
standard is applicable.
Vegetation Inspection
The systematic examination of vegetation conditions on a
maintained transmission line Right-of-Way which may be
combined with a general line inspection.
The current glossary definition of this NERC term is
modified to allow both maintenance inspections and
vegetation inspections to be performed concurrently.
Current definition of Vegetation Inspection: The systematic
examination of a transmission corridor to document
vegetation conditions.
Effective Dates
1. First calendar day of the first calendar quarter one year
after applicable regulatory authority approval for all
requirements
2. First calendar day of the first calendar quarter one year
following Board of Trustees adoption unless governmental
authority withholds approval
3. First calendar day of the first calendar quarter that is at
least one year following Board of Trustees adoption
Exceptions:
A line operated below 200kV, designated by the Planning
Coordinator as an element of an IROL or as a Major WECC
transfer path, becomes subject to this standard 12 months
after the date the Planning Coordinator or WECC initially
designates the lines as being subject to this standard.
An existing transmission line operated at 200kV or higher that
is newly acquired by an asset owner and was not previously
subject to this standard, becomes subject to this standard 12
July 14, 2010
1
Standard FAC-003-1
Proposed Standard FAC-003-2 RBS Draft 4
months after the acquisition date of the line.
1. Title: Transmission Vegetation
Management Program
1. Title: Transmission Vegetation Management
2. Number: FAC-003-1
2. Number: FAC-003-2
3. Purpose: To improve the reliability of the
electric transmission systems by preventing
outages from vegetation located on
transmission rights-of-way (ROW) and
minimizing outages from vegetation located
adjacent to ROW, maintaining clearances
between transmission lines and vegetation on
and along transmission ROW, and reporting
vegetation related outages of the transmission
systems to the respective Regional Reliability
Organizations (RRO) and the North American
Electric Reliability Council (NERC).
The SDT tightened up the Purpose statement to remove
unnecessary wording and to remove redundant verbiage
also contained in the Applicability section. The SDT also
removed from the Purpose any mention of the reporting
of vegetation-caused outages, in part because the
Standard no longer requires reporting of outages due to
vegetation falling from outside the right of way. The new,
shorter Purpose statement is more goal-oriented as a
Purpose statement should be, instead of containing
rambling verbiage that re-states tasks and activities
covered elsewhere in the Applicability or Requirements.
The new Purpose statement is better because it provides
clarity to industry stakeholders that only a narrow class of
vegetation issues lead to large-scale blackouts. For
instance, no cascading-style outage – anytime or
anywhere – has ever been caused by a tree falling into a
transmission line. This Purpose statement appropriately
focuses the Standard’s requirements on the areas of
vegetation management that pose significant risk of
cascading blackouts.
3. Objective: To improve the reliability of the electric
Transmission system by preventing those vegetation related
outages that could lead to Cascading.
4. Applicability:
The Drafting team divided the Applicability section into
two parts (entity and facility) in order to provide structural
clarity. This improvement in readability makes this
structure better than that existing in Version 1.
4. Applicability:
4.1. Transmission Owner
4.2. Regional Reliability Organization
4.3. This Standard shall apply to all
transmission lines operated at 200
kV and above and to any lower
voltage lines designated by the
RRO as critical to the reliability of
the electric system in the region.
1
Comment
4.1.
4.1.1
4.2.
In the Functional Entity section, the team removed the
RRO as directed by FERC since the RRO(s) have no
Requirement compliance responsibilities. Additionally,
the data reporting which was why the RRO had been
included in this section, is no longer a Requirement.
Functional Entities:
Transmission Owners
Facilities: Defined below, including but not
limited to those that cross lands owned by
1
federal , state, provincial, public, private, or
tribal entities:
4.2.1.
Transmission lines operated at 200kV
EPAct 2005 section 1211c: “Access approvals by Federal agencies”
July 14, 2010
2
Standard FAC-003-1
Comment
In the Facility section, the team added specific references
to specific land types on which Transmission rights-ofway may exist. This change was made to make it clear
where the Standard applies in response to industry
comments indicating confusion with the existing Standard
which did not specifically address the issue. This addition
is an improvement from Version 1 since the issue will
now be clearly addressed.
Additionally, the team modified the entity to identify sub200 kV lines which are covered by this standard. In
keeping with the removal of the RRO from the Standards,
the team received valuable input from industry and FERC
staff. It became clear that for the time horizon needed for
the activities associated with vegetation management,
the Planning Coordinator had the appropriate wide-area
view and time horizon. FERC staff expressed a strong
preference for NERC standards to be consistent in the
determination of sub-200 kV lines that are sufficiently
important to be covered by this standard and others that
have the 200 kV bright lines. Thus the team chose to use
an existing identification process (found in Standard
FAC-014). These changes make this version much better
than Version 1 because a responsible entity has been
identified and an already FERC-approved NERC
Standard process replaces an undefined process in
Version 1.
The FERC Order also outlined that NERC should
determine if the identification “net” caught all the sub-200
kV lines of importance. The Drafting team identified that
WECC has developed a classification of lines that have
importance to the Western Interconnection. Therefore,
the Drafting team added those lines. This addition makes
this version better than Version 1 by including important
lines that might otherwise be potentially omitted.
Finally, the Drafting team added the exclusions in 4.2.4 in
response to significant industry comments for clarity in
interpretation and implementation of the standard. The
ambiguity of the existing Standard has led to confusion in
industry and in compliance. This addition makes this
version better than Version 1 because it clearly describes
which facilities are applicable which will eliminate the
confusion.
July 14, 2010
Proposed Standard FAC-003-2 RBS Draft 4
or higher.
4.2.2.
Overhead transmission lines operated
below 200kV having been identified as
included in the definition of an
Interconnection Reliability Operating
Limit (IROL) under NERC Standard
FAC 014 by the Planning Coordinator.
4.2.3.
Overhead transmission lines operated
below 200 kV having been identified as
included in the definition of one of the
Major WECC Transfer Paths in the
Bulk Electric System.
4.2.4.
This Standard does not apply to
Facilities identified above (4.2.1
through 4.2.3) located in the fenced
area of a switchyard, station or
substation.
3
Standard FAC-003-1
Comment
Proposed Standard FAC-003-2 RBS Draft 4
4.3. Enforcement: The reliability obligations of the
applicable entities and facilities are contained
within the technical requirements of this
standard. [Straw proposal]
Vegetation-related Sustained Outages that occur due to
natural disasters are beyond the control of the
Transmission Owner. These events are not classified as
vegetation-related Sustained Outages and are therefore
exempt from the Standard. Transmission lines are not
designed to withstand the impacts of natural disasters
such as flood, drought, earthquake, major storms, fire,
hurricane, tornado, landslides, ice storms, etc. In the
aftermath of catastrophic system damage from natural
disasters the Transmission Owner’s focus is on electric
system restoration for public safety and critical support
infrastructure.
Sustained Outages due to human or animal activity are
beyond the control of the Transmission Owner. These
outages are not classified as vegetation-related
Sustained Outages and are therefore exempt from the
Standard. Examples of these events may include new
plantings by outside parties of tall vegetation under the
transmission line planted since the last Vegetation
Inspection, tree contacts with line initiated by vehicles,
logging activities, etc.
This clarification of which outages are not applicable is
an improvement to the language in requirement R3.2 in
Version 1 and maintains the same level of reliability.
4.4. Other:
This Standard does not apply to any occurrence, nonoccurrence, or other set of circumstances that are
beyond the control of a Transmission Owner subject to
this reliability standard, including acts of God, flood,
drought, earthquake, major storms, fire, hurricane,
tornado, landslides, ice storms, vehicle contact with
tree, human activity involving: removal of, installation
of, or digging around vegetation, animals severing
trees, lightning, epidemic, strike, war, riot, civil
disturbance, sabotage, vandalism, terrorism, wind
shear, or fresh gale (or higher wind speed) that restricts
or prevents performance to comply with this reliability
standard’s requirements. Nothing in this section should
be construed to limit the Transmission Owner’s right to
exercise its full legal rights on the active transmission
2
line ROW
2
A strip or corridor of land that is occupied by active
transmission facilities. This corridor does not include the parts
of the Right-of-Way that are unused or intended for other
facilities. However, it is not to be less than the width of the
easement itself unless the easement exceeds distances as
shown in Table 3 for various voltage classes.
The term “active transmission line ROW” as defined in
footnote 2 is included to differentiate between Sustained
Outages caused by vegetation growing either within or
outside the ROW. This is in contrast to the version I
definition of a simple ROW. This change is important
because all Sustained Outages from vegetation growing
on the ROW are violations of the Standard while all “offROW” Sustained Outages are not. The inclusion of the
active transmission line ROW definition aids in
compliance reporting and monitoring and helps
Transmission Owner’s implement their ROW
management programs. This clarification places a
July 14, 2010
4
Standard FAC-003-1
R1. The Transmission Owner shall prepare,
and keep current, a formal transmission
vegetation management program (TVMP).
The TVMP shall include the Transmission
Owner’s objectives, practices, approved
procedures, and work specifications1.
R1.1. The TVMP shall define a schedule for
and the type (aerial, ground) of ROW
vegetation inspections. This schedule should
be flexible enough to adjust for changing
conditions. The inspection schedule shall be
based on the anticipated growth of
vegetation and any other environmental or
operational factors that could impact the
relationship of vegetation to the Transmission
Owner’s transmission lines.
R1.2. The Transmission Owner, in the
TVMP, shall identify and document
clearances between vegetation and any
overhead, ungrounded supply conductors,
taking into consideration transmission line
voltage, the effects of ambient temperature on
conductor sag under maximum design
loading, and the effects of wind velocities on
conductor sway. Specifically, the
Transmission Owner shall establish
clearances to be achieved at the time of
vegetation management work identified herein
as Clearance 1, and shall also establish and
July 14, 2010
Comment
minimum limit on the distance between the circuit and the
ROW edge for use on ROW’s where a transmission
Owner has excessive ROW width that is far wider then is
typically managed for that voltage class.
Proposed Standard FAC-003-2 RBS Draft 4
Added new section titled, “Background” per SCPSC
format.
5. Background
R1 and its five subparts outlining the TVMP have been
replaced by R1, R2, R3, R4, R5 and R6.
R1 in Version 1 is a documentation requirement defining
what should be in a TVMP. The requirements in Version
2 were crafted to be “results based” that define the
desired end result and not necessarily the route to get to
the end result.
The TVMP document in version 1 is replaced by the
competency requirement R3 in version 2. The TO must
demonstrate that it understands the complex relationship
of conductor movement under thermal load and wind
and a vegetation growing and moving in proximity to the
line. In version 1 the TO can simply state that it mows or
trims and what its Clearance 1 and 2 is. In version 2, the
TO must define the concepts used by an inspector or a
tree crew in making decisions about which tree needs
maintenance and how much should be removed. The
improvement is that the TO’s documentation can be
evaluated to specific construction and maintenance
standards.
R1.1 has been moved to R6. It requires that each line be
inspected annually and clarifies, through the definition of
a Vegetation Inspection, that these inspection may be
part of a broader line inspection. This improvement takes
out the ambiguity of the frequency of inspections.
R1.2 in version 1 requires that the TO document
Clearances 1 and 2. The results based requirements in
R1 and R2 in version 2 require that the TO achieve
conductor to vegetation separation by preventing
encroachments into MVCD, a clearance defining “spark-
R1. Each Transmission Owner shall manage vegetation to
prevent encroachment that could result in a Sustained Outage
of any line identified as an element of an Interconnection
Reliability Operating Limit (IROL) or Major Western Electricity
Coordinating Council (WECC) transfer path (operating within
Rating and Rated
Electrical Operating Conditions). Types of encroachment
include:
1. An encroachment into the Minimum Vegetation
Clearance Distance (MVCD) as shown in Table 2,
observed in real time, absent a Sustained Outage,
2. An encroachment due to a fall-in from inside the active
transmission line ROW that caused a vegetation-related
Sustained Outage,
3. An encroachment due to blowing together of applicable
lines and vegetation located inside the active
transmission line ROW that caused a vegetation-related
Sustained Outage,
4. An encroachment due to a grow-in that caused a
vegetation-related Sustained Outage.
This NERC Vegetation Management Standard
(“Standard”) uses a defense-in-depth approach to improve
the reliability of the electric Transmission system by
preventing those vegetation related outages that could
lead to Cascading. This Standard is…
R2. Each Transmission Owner shall manage vegetation to
prevent encroachment that could result in a Sustained Outage
of applicable lines that are not elements of an Interconnection
Reliability Operating Limit (IROL) or Major Western Electricity
Coordinating Council (WECC) transfer path (operating within
Rating and Rated Electrical Operating Conditions). Types of
encroachment
include:
5
Standard FAC-003-1
maintain a set of clearances identified herein
as Clearance 2 to prevent flashover between
vegetation and overhead ungrounded supply
conductors.
R1.2.1. Clearance 1 — The Transmission
Owner shall determine and document
appropriate clearance distances to be
achieved at the time of transmission
vegetation management work based upon
local conditions and the expected time frame
in which the Transmission Owner plans to
return for future vegetation management
work. Local conditions may include, but are
not
limited to: operating voltage, appropriate
vegetation management techniques,
fire risk, reasonably anticipated tree and
conductor movement, species types
and growth rates, species failure
characteristics, local climate and rainfall
patterns, line terrain and elevation, location of
the vegetation within the span,
and worker approach distance requirements.
Clearance 1 distances shall be
greater than those defined by Clearance 2
below.
R1.2.2. Clearance 2 — The Transmission
Owner shall determine and document
specific radial clearances to be maintained
between vegetation and conductors
under all rated electrical operating conditions.
These minimum clearance distances are
necessary to prevent flashover between
vegetation and conductors and will vary due
to such factors as altitude and operating
voltage.
These Transmission Owner-specific minimum
clearance distances shall be no less than
those set forth in the Institute of Electrical and
Electronics Engineers (IEEE) Standard 516July 14, 2010
Comment
over” distances derived scientifically from the Gallet
equations. FERC, in order 693, along with several
commenters questioned the use of the MAID tables in
Version 1. Version 2 offers appropriate clearances that
are based in science. In addition, there are separate
requirements for lines that could be part of an
IROL/WECC transfer path event and those that are not.
This allows for different Violation Risk Factors.
R1.3 of Version1 required that personnel in the TVMP be
qualified. The requirement did not clearly specify what
the qualification would be and left it up to the TO. This is
considered a ‘fill in the blank’ requirement and was
eliminated.
R1.4 in version 1 required the TO to have a mitigation
plan where clearances could not be attained. This is
replaced in Version 2 by R5. The new wording resolves
the confusion in using the term mitigation plan (an
enforcement mitigation plan vs. a vegetation mitigation
plan). It also allows for different VRF and VSL from the
other components of version 1 R1.
R1.5 the imminent threat process in version 1 is replaced
by R4 in version 2. It is an improvement over version 1 in
that reporting is directed to the switching authority which
has direct ability to take action.
Proposed Standard FAC-003-2 RBS Draft 4
1. An encroachment into the Minimum Vegetation
Clearance Distance (MVCD) as shown in Table 2,
observed in real time, absent a Sustained Outage,
2. An encroachment due to a fall-in from inside the active
transmission line ROW that caused a vegetationrelated Sustained Outage,
3. An encroachment due to blowing together of applicable
lines and vegetation located inside the active
transmission line ROW that caused a vegetationrelated Sustained Outage,
4. An encroachment due to a grow-in that caused a
vegetation-related Sustained Outage.
Rationale (R1 and R2)
The MVCD is a calculated minimum distance stated
in feet (meters) to prevent spark-over between
conductors and vegetation, for various altitudes and
operating voltages. The distances in Table 2 were
derived using a proven transmission design method.
R3. Each Transmission Owner shall document the
procedures, processes, or specifications it uses to
prevent the encroachment of vegetation into the
MVCD. Such documentation will incorporate the
dynamics of a transmission line conductor’s movement
throughout its Rating and Rated Electrical Operating
Conditions and the inter-relationships between
vegetation growth rates, vegetation control methods,
and inspection frequency, for the Transmission
Owner’s applicable lines.
Rationale (R3)
Provide a basis for evaluation on the intent and competency
of the Transmission Owner in maintaining vegetation. There
may be many acceptable approaches to maintain clearances.
However, the Transmission Owner should be able to state
what its approach is and how it conducts work to maintain
clearances. See Figure 1 for an illustration of possible
conductor locations.
6
Standard FAC-003-1
2003 (Guide for Maintenance Methods on
Energized Power Lines) and as specified in its
Section 4.2.2.3, Minimum Air Insulation
Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system
transient overvoltage factors are not
known, clearances shall be derived from
Table 5, IEEE 516-2003, phase-to-ground
distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system
transient overvoltage factors are known,
clearances shall be derived from Table 7,
IEEE 516-2003, phase-to-phase voltages,
with appropriate altitude correction factors
applied.
R1.3. All personnel directly involved in the
design and implementation of the TVMP shall
hold appropriate qualifications and training, as
defined by the Transmission Owner, to
perform their duties.
R1.4. Each Transmission Owner shall
develop mitigation measures to achieve
sufficient clearances for the protection of the
transmission facilities when it identifies
locations on the ROW where the
Transmission Owner is restricted from
attaining the clearances specified in
Requirement 1.2.1.
R1.5. Each Transmission Owner shall
establish and document a process for the
immediate communication of vegetation
conditions that present an imminent threat of
a transmission line outage. This is so that
action (temporary reduction in line rating,
switching line out of service, etc.) may be
taken until the threat is relieved.
R2. The Transmission Owner shall create
and implement an annual plan for
vegetation management work to ensure
July 14, 2010
Comment
R4.
Proposed Standard FAC-003-2 RBS Draft 4
Each Transmission Owner, without any intentional time
delay, shall notify the control center holding switching
authority for the associated transmission line when
qualified personnel confirm the existence of a
vegetation condition that is likely to cause a Fault at
any moment.
Rationale (R4)
To ensure expeditious communication between qualified field
personnel and proper operating personnel when a critical
situation is confirmed. Qualified field personnel may include
lineworkers and utility arborists.
R5. Each Transmission Owner shall take corrective action
when it is constrained from performing planned
vegetation work, where a transmission line is put at
potential risk due to the constraint.
Rationale (R5)
Legal actions and other events may occur which result in
constraints that prevent the Transmission Owner from
performing planned vegetation maintenance work.
In cases where the transmission line is put at potential risk
due to constraints, the intent is for the Transmission Owner
to put interim measures in place, rather than do nothing. For
example, in the 2003 NE blackout a Transmission Owner
was prevented by a court order from performing planned
work. However, when the court order expired, the TO failed
to take action to maintain the vegetation resulting in a
sustained outage that contributed to the cascade.
The corrective action process is not intended to address
situations where a planned work methodology cannot be
performed but an alternate work methodology can be used.
The Standard Drafting Team revised the language in the
existing standard which reads in part, “The Transmission
Owner shall create and implement an annual plan...” to
R7. Each Transmission Owner shall complete the work in an
annual vegetation work plan to ensure no vegetation
encroachments occur within the MVCD. Modifications to
7
Standard FAC-003-1
the reliability of the system. The plan
shall describe the methods used, such
as manual clearing, mechanical
clearing, herbicide treatment, or other
actions. The plan should be flexible
enough to adjust to changing conditions,
taking into consideration anticipated
growth of vegetation and all other
environmental factors that may have an
impact on the reliability of the
transmission systems. Adjustments to
the plan shall be documented as they
occur. The plan should take into
consideration the time required to obtain
permissions or permits from landowners
or regulatory authorities. Each
Transmission Owner shall have systems
and procedures for documenting and
tracking the planned vegetation
management work and ensuring that the
vegetation management work was
completed according to work
specifications.
R3. The Transmission Owner shall report
quarterly to its RRO, or the RRO’s designee,
sustained transmission line outages
determined by the Transmission Owner to
have been caused by vegetation.
R3.1. Multiple sustained outages on an
individual line, if caused by the same
vegetation,
shall be reported as one outage regardless of
the actual number of outages within a 24July 14, 2010
Comment
“Each Transmission Owner shall complete the work in an
annual vegetation work plan…” setting an expectation
that the work identified will be completed, as noted in the
Rationale. In addition, the Team eliminated prescriptive
language in R2 of the existing standard.
The revised requirement is an improvement upon the
current standard in that it clearly establishes the true
intent of this requirement, completing the work in the plan
and ensuring no vegetation encroaches into the MVCD.
Proposed Standard FAC-003-2 RBS Draft 4
the work plan in response to changing conditions or to
findings from vegetation inspections may be made and
documented provided they do not put the transmission
system at risk of a vegetation encroachment. Examples
of reasons for modification to annual plan may include:
• Change in expected growth rate/
environmental factors
• Major storms
• Rescheduling work between growing seasons
• Crew or contractor availability/ Mutual assistance
agreements
• Identified unanticipated high priority work
• Weather conditions/Accessibility
• Permitting delays
• Land ownership changes/Change in land use by the
landowner
• Funding adjustments (increase or decrease)
• Emerging technologies
Rationale (R7)
This requirement sets the expectation that the work
identified in the annual work plan will be completed as
planned. An annual vegetation work plan allows for work
to be modified for changing conditions, taking into
consideration anticipated growth of vegetation and all other
environmental factors, provided that the changes do not
violate the encroachment within the MVCD.
R3 Moved: In general, reporting requirement elements
are moved to the Additional Compliance Information
section of the standard. Reporting elements are, in
themselves, documentation rudiments and do not add or
subtract from electric system reliability. Format changes
R3.1 Moved: Explanatory text moved to M1 and M2
Informational in nature. Format change.
R3.2 Moved: The exclusions for reporting an outage were
Additional Compliance Information
Periodic Data Submittal: The Transmission Owner will
submit a quarterly report to its Regional Entity, or the Regional
Entity’s designee, identifying all Sustained Outages of
transmission lines determined by the Transmission Owner to
have been caused by vegetation that includes, as a minimum,
the following:
o The name of the circuit(s), the date, time and
duration of the outage; the voltage of the circuit; a
8
Standard FAC-003-1
hour period.
R3.2. The Transmission Owner is not
required to report to the RRO, or the RRO’s
designee, certain sustained transmission line
outages caused by vegetation: (1) Vegetation
related outages that result from vegetation
falling into lines from outside the ROW that
result from natural disasters shall not be
considered reportable (examples of disasters
that could create non-reportable outages
include, but are not limited to, earthquakes,
fires, tornados, hurricanes, landslides, wind
shear, major storms as defined either by
the Transmission Owner or an applicable
regulatory body, ice storms, and floods), and
(2) Vegetation-related outages due to human
or animal activity shall not be considered
reportable (examples of human or animal
activity that could cause a non-reportable
outage include, but are not limited to, logging,
animal severing tree, vehicle contact with tree,
arboricultural activities or horticultural or
agricultural activities, or removal or digging of
vegetation).
R3.3. The outage information provided by
the Transmission Owner to the RRO, or the
RRO’s designee, shall include at a minimum:
the name of the circuit(s) outaged, the date,
time and duration of the outage; a description
of the cause of the outage; other pertinent
comments; and any countermeasures taken
by the Transmission Owner.
R3.4. An outage shall be categorized as one
of the following:
R3.4.1. Category 1 — Grow-ins:
Outages caused by vegetation growing
into lines from vegetation inside and/or
outside of the ROW;
R3.4.2. Category 2 — Fall-ins: Outages
July 14, 2010
Comment
placed in the Applicability Section – Other. The
placement at the beginning of the Standard call attention
to the overall impact to all requirements in the Standard
R3.3 Moved: Outage information moved to Additional
Compliance Information section. Informational in nature
R3.4 Moved: Outage categories moved to Additional
Compliance Information section. Informational in nature
R3.4.1 Moved: Category 1 moved and expanded to
differentiate between vegetation related sustained
outages outside and within the ROW on IROL or Major
WECC transfer path and non IROL lines or Major WECC
transfer paths Category 1 outages were separated into
1A and 1B.
R3.4.2 Moved: Category 2 reporting moved to Additional
Compliance Information section.
R3.4.3 Eliminated: Category 3 reporting for fall-in outside
the right of way was eliminated. Vegetation fall-in’s from
outside the transmission right of way are not a standard
violation and thus not a requirement. The reporting
requirement is currently for informational purposes only.
Added Category 4: Sustained outages from vegetation
and conductors blowing together created a new Category
4 classification. Information located within the Additional
Compliance Information section.
Proposed Standard FAC-003-2 RBS Draft 4
description of the cause of the outage; the category
associated with the Sustained Outage; other pertinent
comments; and any countermeasures taken by the
Transmission Owner.
A Sustained Outage is to be categorized as one of the
following:
o Category 1A — Grow-ins: Sustained Outages
caused by vegetation growing into applicable
transmission lines, that are identified as an element of
an IROL or Major WECC Transfer Path, by vegetation
inside and/or outside of the active transmission line
ROW;
o Category 1B — Grow-ins: Sustained Outages
caused by vegetation growing into applicable
transmission lines, but are not identified as an
element of an IROL or Major WECC Transfer Path, by
vegetation inside and/or outside of the active
transmission line ROW;
o Category 2 — Fall-ins: Sustained Outages caused
by vegetation falling into applicable transmission lines
from within the active transmission line ROW;
3
o Category 4 — Blowing together: Sustained Outages
caused by vegetation and applicable transmission
lines blowing together from within the active
transmission line ROW.
The Regional Entity will report the outage information provided
by Transmission Owners, as per the above, quarterly to
NERC, as well as any actions taken by the Regional Entity as
a result of any of the reported Sustained Outages.
3 Category 3 reporting is eliminated.
No change in reliability.
9
Standard FAC-003-1
caused by vegetation falling into lines
from inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages
caused by vegetation falling into lines
from outside the ROW.
R4. The RRO shall report the outage
information provided to it by Transmission
Owner’s, as required by Requirement 3,
quarterly to NERC, as well as any actions
taken by the RRO as a result of any of the
reported outages.
Comment
Proposed Standard FAC-003-2 RBS Draft 4
R4. Eliminated: RRO is now the Regional Entity. The
Regional Entity is instructed per the periodic data
submittal within the Additional Compliance Information
section to report the outage information provided by
Transmission Owners, as per the above, quarterly to
NERC, as well as any actions taken by the Regional
Entity as a result of any of the reported Sustained
Outages.
No change in reliability.
July 14, 2010
10
Transmission Vegetation Management
Standard FAC-003-2 Technical Reference
Prepared by the
North American Electric Reliability Corporation
Vegetation Management Standard Drafting Team
June 28, 2010
NERC Standard FAC-003-2 Technical Reference
Table of Contents
INTRODUCTION ..................................................................................................................................................................... 3
SPECIAL NOTE: THE APPLICATION OF RESULTS-BASED APPROACH TO FAC-003-2 ...................................... 4
DISCLAIMER ........................................................................................................................................................................... 6
PREFACE .................................................................................................................................................................................. 7
APPLICABILITY OF THE STANDARD............................................................................................................................... 9
ACTIVE TRANSMISSION LINE ROW ................................................................................................................................. 11
REQUIREMENTS R1 AND R2 ............................................................................................................................................. 16
REQUIREMENT R3 ............................................................................................................................................................... 19
ANSI A300 – BEST MANAGEMENT PRACTICES FOR TREE CARE OPERATIONS ............................................................. 24
REQUIREMENT R4 ............................................................................................................................................................... 29
REQUIREMENT R5 ............................................................................................................................................................... 30
REQUIREMENT R6 ............................................................................................................................................................... 32
REQUIREMENT R7 ............................................................................................................................................................... 33
APPENDIX 1: CLEARANCE DISTANCE DERIVATION BY THE GALLET EQUATION ....................................... 35
LIST OF ACRONYMS AND ABBREVIATIONS ............................................................................................................... 41
REFERENCES ........................................................................................................................................................................ 42
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NERC Standard FAC-003-2 Technical Reference
Introduction
This document is intended to provide supplemental information and guidance for complying with
the requirements of Reliability Standard FAC-003-2.
The purpose of the Standard is to improve the reliability of the electric transmission system by
preventing those vegetation related outages that could lead to Cascading.
Compliance with the Standard is mandatory and enforceable.
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NERC Standard FAC-003-2 Technical Reference
Special Note: The Application of Results-Based
Approach to FAC-003-2
In its three-year assessment as the ERO, NERC acknowledged stakeholder comments and
committed to:
i) addressing quality issues to ensure each reliability standard has a clear statement of
purpose, and has outcome-focused requirements that are clear and measurable; and
ii) eliminating requirements that do not have an impact on bulk power system reliability.
In 2010, the Standards Committee approved a recommendation to use Project 2007-07
Vegetation Management as a first proof of concept for developing results-based standards.
The Standard Drafting Team (SDT) employed a defense-in-depth 1 strategy for FAC-003-2,
where each requirement has a role in preventing those vegetation related outages that could lead
to Cascading. This portfolio of requirements was designed to achieve an overall defense-indepth strategy and to comply with the quality objectives identified in the Acceptance Criteria of
a Reliability Standard document.
The SDT developed a portfolio of performance, risk, and competency-based mandatory
reliability requirements to support an effective defense-in-depth strategy. Each Requirement was
developed using one of the following requirement types:
a)
Performance-based - defines a particular reliability objective or outcome to be
achieved. In its simplest form, a results-based requirement has four components:
who, under what conditions (if any), shall perform what action, to achieve what
particular result or outcome?
b) Risk-based - preventive requirements to reduce the risks of failure to acceptable
tolerance levels. A risk-based reliability requirement should be framed as: who,
under what conditions (if any), shall perform what action, to achieve what particular
result or outcome that reduces a stated risk to the reliability of the bulk power
system?
c) Competency-based - defines a minimum set of capabilities an entity needs to have
to demonstrate it is able to perform its designated reliability functions. A
competency-based reliability requirement should be framed as: who, under what
conditions (if any), shall have what capability, to achieve what particular result or
outcome to perform an action to achieve a result or outcome or to reduce a risk to
the reliability of the bulk power system?
The drafting team reviewed and edited version 1 of FAC-003-1 to remove prescriptive
and administrative language in order to distill the technical requirements down to their
1
A defense-in-depth strategy for reliability standards recognizes that each requirement in the NERC standards has a
role in preventing system failures, and that these roles are complementary and reinforcing. These prevention
measures should be arranged in a series of defensive layers or walls. No single defensive layer provides complete
protection from failure by itself. But taken together, with well-designed layers including performance, risk, and
competency-based requirements, a defense-in-depth approach can be very effective in preventing future large scale
power system failures.
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NERC Standard FAC-003-2 Technical Reference
essential reliability content. Text that is explanatory in nature is placed in a special
section of the standard entitled Guideline and Technical Basis to aid in the understanding
of the requirements. Furthermore, Rationale text boxes are inserted alongside each
requirement to communicate the foundation for the requirement.
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NERC Standard FAC-003-2 Technical Reference
Disclaimer
This supporting document is supplemental to the reliability standard FAC-003-2 —
Transmission Vegetation Management and does not contain mandatory requirements subject to
compliance review.
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NERC Standard FAC-003-2 Technical Reference
Preface
The NERC Vegetation Management Standard Drafting Team (VM SDT) acknowledges those
across the industry who contributed to the development of this Standard and companion
Technical Reference document. The Technical Reference document is intended to provide
supplemental explanatory background and guidance related to requirements contained in the
Standard but does not in itself contain requirements subject to compliance review.
The VM SDT believes that a well designed and executed Transmission Vegetation Management
Program (TVMP) will have few problems meeting the requirements of this Standard. While the
Standard requires a TVMP to contain certain elements, it allows the Transmission Owner
flexibility in designing a TVMP to meet local needs provided it also meets the purpose of the
Standard.
While there are many approaches to vegetation management, the VMSDT supports industry best
practices contained in ANSI A300 (Part 7) – Integrated Vegetation Management (IVM) practices
on Utility Rights-of-way, as well as the companion publication Best Management Practices –
Integrated Vegetation Management, as an effective strategy to maintain compliance with this
Standard. ANSI A300 (Part 7), approved by industry consensus in 2006, contains many elements
needed for an effective TVMP as required by this Standard. One key element is the “wire zone
– border zone” concept. Supported by over 50 years of continuous research, wire zone – border
zone is a proven method to manage vegetation on transmission rights-of-ways and is an industry
accepted best practice to help ensure electric system reliability.
The VM SDT believes that Transmission Owners who adopt and effectively implement IVM
principles, particularly the “wire zone – border zone” concept, are far less likely to experience a
vegetation caused outage than those who do not.
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NERC Standard FAC-003-2 Technical Reference
Definition of Terms
Vegetation Inspection** — The systematic examination of vegetation conditions on an Active
Transmission Line Right-of-Way which may be combined with a general line inspection.
The inspection includes the identification of any vegetation that may pose a threat to reliability
prior to the next planned inspection or maintenance work, considering the current location of the
conductor and other possible locations of the conductor due to sag and sway for rated conditions.
This definition allows both maintenance inspections and vegetation inspections to be performed
concurrently.
*To be added to the NERC glossary of terms with final approval of this standard revision
** This is a modification to a defined term in the NERC glossary.
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NERC Standard FAC-003-2 Technical Reference
Applicability of the Standard
4. Applicability
4.1. Functional Entities:
Transmission Owners
4.2. Facilities: Defined below, including but not limited to those that cross lands owned
by federal 1, state, provincial, public, private, or tribal entities:
4.2.1 Overhead transmission lines operated at 200kV or higher.
4.2.2 Overhead transmission lines operated below 200kV having been identified
as included in the definition of an Interconnection Reliability Operating
Limit (IROL) under NERC Standard FAC 014 by the Planning Coordinator.
4.2.3 Overhead transmission lines operated below 200 kV having been identified
as included in the definition of one of the Major WECC Transfer Paths in
the Bulk Electric System.
4.2.4 This Standard does not apply to Facilities identified above (4.2.1 through
4.2.3) located in the fenced area of a switchyard, station or substation.
4.3. Enforcement: The reliability obligations of the applicable entities and facilities are
contained within the technical requirements of this standard.
4.4. Other:
This Standard does not apply to any occurrence, non-occurrence, or other set of
circumstances that are beyond the control of a Transmission Owner subject to this
reliability standard, including acts of God, flood, drought, earthquake, major
storms, fire, hurricane, tornado, landslides, ice storms, vehicle contact with tree,
human activity involving: removal of, installation of, or digging around vegetation,
animals severing trees, lightning, epidemic, strike, war, riot, civil disturbance,
sabotage, vandalism, terrorism, wind shear, or fresh gale (or higher wind speed)
that restricts or prevents performance to comply with this reliability standard’s
requirements. Nothing in this section should be construed to limit the Transmission
Owner’s right to exercise its full legal rights on the Active Transmission Line ROW.
In Order 693, FERC discussed the 200 kV bright-line test of applicability. While FERC did not
change the 200 kV bright-line, the Commission remained concerned that there may be some
transmission lines operating at lesser voltages that could have significant impact on the Bulk
Electric System that should therefore be subject to this standard.
NERC Standard FAC-014 has the stated purpose, “To ensure that System Operating Limits
(SOLs) used in the reliable planning and operation of the Bulk Electric System (BES) are
determined based on an established methodology or methodologies.” FAC-014 requires
Reliability Coordinators, Planning Coordinators, and Transmission Planners to have a
methodology to identify all lines that might comprise an IROL. Thus, these entities would
identify sub-200 kV lines that qualify as part of an IROL and should be subject to FAC-003-2.
1
EPAct 2005 section 1211c: “Access approvals by Federal agencies”.
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NERC Standard FAC-003-2 Technical Reference
Although all three entities may prepare the list of elements, FAC-003-2 presently does not
specify that it is the list from the Planning Coordinator that should be used by Transmission
Owners for FAC-003. However, the Time Horizon needed to plan vegetation management work
does not lend itself to the operating horizon of a Reliability Coordinator. Additionally, the
Planning Coordinator has a wider-area view than the Transmission Planner and could thus
identify any elements of importance to a sub-set of its area that might be missed by a
Transmission Planner.
Transmission Owners, who do not already get the list of circuits included in the definition of an
IROL, can get them from the Planning Coordinator. Specifically R5 of FAC-014 specifies that
“The Reliability Coordinator, Planning Authority (Coordinator) and Transmission Planner
shall each provide its SOLs and IROLs to those entities that have a reliability-related need for
those limits and provide a written request that includes a schedule for delivery of those limits”
Vegetation-related Sustained Outages that occur due to natural disasters are beyond the control
of the Transmission Owner. These events are not classified as vegetation-related Sustained
Outages and are therefore exempt from the Standard. Transmission lines are not designed to
withstand the impacts of natural disasters such as flood, drought, earthquake, major storms, fire,
hurricane, tornado, landslides, ice storms, etc. In the aftermath of catastrophic system damage
from natural disasters the Transmission Owner’s focus is on electric system restoration for public
safety and critical support infrastructure.
Sustained Outages due to human or animal activity are beyond the control of the Transmission
Owner. These outages are not classified as vegetation-related Sustained Outages and are
therefore exempt from the Standard. Examples of these events may include new plantings by
outside parties of tall vegetation under the transmission line planted since the last Vegetation
Inspection, tree contacts with line initiated by vehicles, logging activities, etc.
The foregoing exemptions are addressed in a new subsection, 4.4 Other, of the Applicability
section. Referred to collectively as force majeure events and activities, this section applies to all
requirements in FAC-003-2.
The reliability objective of this NERC Vegetation Management Standard (“Standard”) is to
prevent vegetation-related outages which could lead to Cascading by effective vegetation
maintenance while recognizing that certain outages such as those due to vandalism, human errors
and acts of nature are not preventable. Operating experience clearly indicates that trees that have
grown out of specification could contribute to a cascading grid failure, especially under heavy
electrical loading conditions.
Serious outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations. To
properly reduce and manage this risk, it is necessary to apply the Standard to applicable lines on
any kind of land or easement, whether they are Federal Lands, state or provincial lands, public or
private lands, franchises, easements or lands owned in fee. For the purposes of the Standard and
this Technical Reference document, the term “public lands” includes municipal lands, village
lands, city lands, and land owned by a host of other governmental entities.
The Standard addresses vegetation management along applicable overhead lines that serve to
connect one electric station to another. However, it is not intended to be applied to lines sections
inside the electric station fence or other boundary of an electric station, submarine or
underground lines.
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NERC Standard FAC-003-2 Technical Reference
The Standard is intended to reduce the risk of Cascading involving vegetation. It is not intended
to prevent customer outages from occurring due to tree contact with all transmission lines and
voltages. For example, localized customer service might be disrupted if vegetation were to make
contact with a 69kV transmission line supplying power to a 12kV distribution station. However,
this Standard is not written to address such isolated situations which have little impact on the
overall Bulk Electric System.
Vegetation growth is constant and always present. Unmanaged vegetation poses an increased
outage risk when numerous transmission lines are operating at or near their Rating. This poses a
significant risk of multiple line failures and Cascading. On the other hand, most other outage
causes (such as trees falling into lines, lightning, animals, motor vehicles, etc.) are statistically
intermittent. The probability of occurrence of these events is not dependent on heavy loads.
There is no cause-effect relationship which creates the probability of simultaneous occurrence of
other such events. Therefore these types of events are highly unlikely to cause large-scale grid
failures.
In preparing the original vegetation management standard in 2005, industry stakeholders set the
threshold for applicability of the standard at 200kV. This was because an unexpected loss of
lines operating at above 200kV has a higher probability of initiating a widespread blackout or
cascading outages compared with lines operating at less than 200kV.
The original NERC Standard FAC-003-1 also allowed for application of the standard to
“critical” circuits (critical from the perspective of initiating widespread blackouts or cascading
outages) operating below 200kV. While the percentage of these circuits is relatively low, it
remains a fact that there are sub-200kV circuits whose loss could contribute to a widespread
outage. Given the very limited exposure and unlikelihood of a major event related to these lowervoltage lines, it would be an imprudent use of resources to apply the Standard to all sub-200kV
lines. The drafting team, after evaluating several alternatives, selected the IROL and WECC
Major Transfer Path criteria to determine applicable lines below 200 kV that are subject to this
standard.
Active Transmission Line ROW
The term “Active Transmission Line Right of Way” is defined in the Standard in a footnote
repeated for convenience below:
A strip or corridor of land that is occupied by active transmission facilities. This
corridor does not include the parts of the Right-of-Way that are unused or
intended for other facilities. However, it is not to be less than the width of the
easement itself unless the easement exceeds distances as shown in Table 3 for
various voltage classes.
The term Right of Way (ROW) can be used in reference to many situations. This is partially
because some lines are built on the land that is owned fee simple by the transmission owner,
other lines are built across federal or provincial lands with only limited rights under a permit or
agreement, and many other lines cross lands with only limited easement rights to construct,
operate and maintain the line. Transmission line configurations on ROWs are present in many
combinations of multiple circuits on various tower types. The number of circuits and
configurations change along the length of the ROW due to circuits departing to other locations or
terminating at nearby substations. Figures 1, 2 and 3 on the following pages depict several
typical transmission line configurations on typical rights of way.
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NERC Standard FAC-003-2 Technical Reference
A Transmission Owner may plan for a nominal width along the entire length of a line during
planning using its design specifications for a particular circuit configuration and voltage. The
actual acquired ROW width at the time a circuit is constructed is however impacted in many
cases, by other considerations. Those considerations include other future circuits that may be
built adjacent to the subject line, or property parcels with unusual ‘extra” widths due to special
property owner demands during initial acquisition, or other existing lines adjacent to the subject
line (which may be retired or abandoned at a future date). Refer to Figures 1 and 3 for common
examples of such situations.
This Standard requires the Transmission Owner to prevent sustained outages due to vegetation
“growing into” or “blowing-together” with line conductors if that vegetation is under the line or
growing beside the line (provided the Transmission Owner has the legal right to remove or trim
the vegetation growing beside the line). Transmission Owners are also required to prevent
sustained outages due to fall-ins from trees that, before falling, were standing inside the limits
established in footnote 2 and associated “Table 3” (see below).
However it is recognized that any requirement in this standard to impose violations for sustained
outages due to “fall-ins” must consider the impact of forcing the clearing of ROWs to the legal
edge or to widths wider than they are typically managed. Therefore the standard drafting team
inserted the subject footnote “active transmission line ROW” to provide a distance for a
Transmission Owner to use if they do not already have a codified ROW width for a particular
circuit or voltage”. This approach of defining “active” and “inactive” right of way is intended to
clarify the confusion created by the current standard which simply states that a fall-in from
within the ROW is a violation. This provides the Transmission Owner with a means to define a
right of way width that is applicable to fall-ins, provided it is not less than those limits in “Table
3”.
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NERC Standard FAC-003-2 Technical Reference
69 - 138 kV
37.5 ft.
139 - 230 kV
50 ft.
231 - 345 kV
75 ft.
346 - 500 kV
87.5 ft.
501 - 765 kV
100 ft.
“Table 3 – Minimum Distance from the Centerline of the Circuit to the edge of the active
transmission line ROW”
Figure 1
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NERC Standard FAC-003-2 Technical Reference
Figure 2
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NERC Standard FAC-003-2 Technical Reference
Figure 3
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NERC Standard FAC-003-2 Technical Reference
Requirements R1 and R2
R1. Each Transmission Owner shall manage
vegetation to prevent encroachment that
could result in a Sustained Outage of any
line identified as an element of an
Interconnection Reliability Operating Limit
(IROL) or Major Western Electricity
Coordinating Council (WECC) transfer path
(operating within Rating and Rated
Electrical Operating Conditions). Types of
encroachment include:
Rationale
The MVCD is a calculated minimum
distance stated in feet (meters) to prevent
spark-over between conductors and
vegetation, for various altitudes and
operating voltages. The distances in
Table 2 were derived using a proven
transmission design method.
1. An encroachment into the Minimum Vegetation Clearance Distance (MVCD) as shown in
Table 2, observed in real time, absent a Sustained Outage,
2. An encroachment due to a fall-in from inside the Active Transmission Line ROW that
caused a vegetation-related Sustained Outage,
3. An encroachment due to blowing together of applicable lines and vegetation located inside
the Active Transmission Line ROW that caused a vegetation-related Sustained Outage,
4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage.
R2. Each Transmission Owner shall manage vegetation to prevent encroachment that could result
in a Sustained Outage of applicable lines that are not elements of an Interconnection
Reliability Operating Limit (IROL) or Major Western Electricity Coordinating Council
(WECC) transfer path (operating within Rating and Rated Electrical Operating Conditions).
Types of encroachment include:
1. An encroachment into the Minimum Vegetation Clearance Distance (MVCD) as shown in
Table 2, observed in real time, absent a Sustained Outage,
2. An encroachment due to a fall-in from inside the Active Transmission Line ROW that
caused a vegetation-related Sustained Outage,
3. An encroachment due to blowing together of applicable lines and vegetation located inside
the Active Transmission Line ROW that caused a vegetation-related Sustained Outage,
4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage.
M1. Each Transmission Owner has evidence that it managed vegetation as described in R1.
Examples of acceptable forms of evidence may include attestations, reports containing no
Sustained Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-Time observations of any MVCD encroachments.
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be
reported as one outage regardless of the actual number of outages within a 24-hour
period. If an investigation of a Fault by a qualified person confirms that a vegetation
encroachment within the MVCD occurred, then it shall be considered a Real-time
observation.
M2. Each Transmission Owner has evidence that it managed vegetation as described in R2.
Examples of acceptable forms of evidence may include attestations, reports containing no
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Sustained Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-Time observations of any MVCD encroachments.
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be
reported as one outage regardless of the actual number of outages within a 24-hour
period. If an investigation of a Fault by a qualified person confirms that a vegetation
encroachment within the MVCD occurred, then it shall be considered a Real-time
observation.
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the prevention of vegetation encroachments within a minimum distance of
transmission lines. Content-wise, R1 and R2 are the same requirements; however, they apply to
different Facilities. Both R1 and R2 require each Transmission Owner to prevent vegetation from
encroaching within the Minimum Vegetation Clearance Distance of transmission lines. R1 is
applicable to lines “identified as an element of an Interconnection Reliability Operating Limit
(IROL) or Major Western Electricity Coordinating Council (WECC) transfer path (operating
within Rating and Rated Electrical Operating Conditions) to avoid a Sustained Outage”. R2 applies
to all other applicable lines that are not an element of an IROL or Major WECC Transfer Path.
The separation of applicability (between R1 and R2) recognizes that an encroachment into the
MVCD of an IROL or Major WECC Transfer Path transmission line is a greater risk to the
electric transmission system. Applicable lines that are not an element of an IROL or Major
WECC Transfer Path are required to be clear of vegetation but these lines are comparatively less
operationally significant. As a reflection of this difference in risk impact, the Violation Risk
Factors (VRFs) are assigned as High for R1 and Medium for R2.
These requirements (R1 and R2) state that if vegetation encroaches within the distances in Table
1 in Appendix 1 of this supplemental Transmission Vegetation Management Standard FAC-0032 Technical Reference document, it is in violation of the standard. Table 1 tabulates the distances
necessary to prevent spark-over based on the Gallet equations as described more fully in
Appendix 1 below.
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating
(potentially in violation of other standards), the occurrence of a clearance encroachment may
occur. For example, emergency actions taken by a Transmission Operator or Reliability
Coordinator to protect an Interconnection may cause the transmission line to sag more and come
closer to vegetation, potentially causing an outage. Such vegetation-related outages are not a
violation of these requirements.
Evidence of violation of Requirement R1 and R2 include real-time observation of a vegetation
encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related encroachment
resulting in a Sustained Outage due to a fall-in from inside the Active Transmission Line ROW,
or a vegetation-related encroachment resulting in a Sustained Outage due to blowing together of
applicable lines and vegetation located inside the Active Transmission Line ROW, or a
vegetation-related encroachment resulting in a Sustained Outage due to a grow-in. If an
investigation of a Fault by a qualified person confirms that a vegetation encroachment within the
MVCD occurred, then it shall be considered a Real-time observation.
With this approach, the VSLs were defined such that they directly correlate to the severity of a
failure to keep vegetation away from conductors and to the corresponding performance level of
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the Transmission Owner’s vegetation program’s ability to meet the goal of “preventing a
Sustained Outage that could lead to Cascading.” Thus violation severity increases with a
Transmission Owner’s inability to meet this goal and its potential of leading to a Cascading
event. The additional benefits of such a combination are that it simplifies the standard and clearly
defines performance for compliance. A performance-based requirement of this nature will
promote high quality, cost effective vegetation management programs that will deliver the
overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation, for
example a limb that only partially breaks and intermittently contacts a conductor. Such events
are considered to be a single vegetation-related Sustained Outage under the Standard where the
Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will help prevent transmission outages.
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Requirement R3
Rationale
Provide a basis for evaluation on the intent and
competency of the Transmission Owner in
maintaining vegetation. There may be many
acceptable approaches to maintain clearances.
However, the Transmission Owner should be
able to state what its approach is and how it
conducts work to maintain clearances. See
Figure 1 [in Standard FAC-003-2] for an
illustration of possible conductor locations.
R3. Each Transmission Owner shall document
the procedures, processes, or specifications
it uses to prevent the encroachment of
vegetation into the MVCD. Such
documentation will incorporate the dynamics
of a transmission line conductor’s movement
throughout its Rating and Rated Electrical
Operating Conditions and the interrelationships between vegetation growth
rates, vegetation control methods, and
inspection frequency, for the Transmission Owner’s applicable lines.
M3. The procedures, processes, or specifications provided demonstrate that the
Transmission Owner can prevent encroachment into the MVCD considering the
factors identified in the requirement.
Requirement R3 is a competency based requirement concerned with the procedures, processes,
or specifications, a Transmission Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the
Transmission Owner uses to plan and perform vegetation work to prevent transmission Sustained
Outages and minimize risk to the Transmission System. The approach provides the basis for
evaluating the intent, allocation of appropriate resources and the competency of the Transmission
Owner in managing vegetation. There are many acceptable approaches to manage vegetation
and avoid Sustained Outages. However, the Transmission Owner must be able to state what its
approach is and how it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach a
Transmission Owner chooses to use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the Transmission Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing as a reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figure 5 below.
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Conductor Dynamics
In order for a Transmission Owner to develop a specific maintenance approach, it is important to
understand the dynamics of a line conductor’s movement. This paper will first address the
complexities inherent in observing and predicting conductor movement, particularly for field
personnel. It will then present some examples of maintenance approaches which Transmission
Owners may consider that take into account these complexities, while resulting in practical
approaches for field personnel.
Additionally, it is important the Transmission Owner consider all conductor locations, the
MVCD, and vegetation growth between maintenance activities when developing a maintenance
approach.
Understanding Conductor Position and Movement
The conductor’s position in space at any point in time is continuously changing as a reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading.
As a consequence of these loading variables, the conductor’s position in space is dynamic and
moving. When calculating the range of conductor positions, the Transmission Owner should use
the same design criteria and assumptions that the Transmission Owner uses when establishing
Ratings and SOL, as described in other standards. Typically, the greatest conductor movement
would be at mid-span. As the conductor moves through various positions, a spark-over zone
surrounding the conductor moves with it. The radius of the spark-over zone may be found by
referring to Table 1 (“Minimum Vegetation Clearance Distances”) in the standard. For
illustrations of this zone and conductor movements, Figures 4 through 6 below demonstrate these
concepts. At the time of making a field observation, however, it is very difficult to precisely
know where the conductor is in relation to its wide range of all possible positions. Therefore,
Transmission Owners must adopt maintenance approaches that account for this dynamic
situation.
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Figure 4
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Figure 5
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Cross-Section View of a Single Conductor
At a Given Point Along The Span
Showing Six Possible Conductor Positions Due to Movement
Resulting From Thermal and Mechanical Loading
For Consideration in Developing a Maintenance Approach
Figure 6
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Selecting a Maintenance Approach
In order to maintain adequate separation between vegetation and transmission line conductors,
the Transmission Owner must craft a maintenance strategy that keeps vegetation well away from
the spark-over zone mentioned above. In fact, it is generally necessary to incorporate a variety of
maintenance strategies. For example, one Transmission Owner may utilize a combination of
routine cycles, traditional IVM techniques and long-term planning. Another Transmission Owner
may place a higher reliance on frequent inspections and quick remediation as opposed to a
cyclical approach. This variation of approaches is further warranted when factors, such as
terrain, legal and other constraints, vegetation types, and climates, are considered in developing a
Transmission Owner’s specific approach to satisfying this requirement.
The following is a sample description of one combination of strategies which may be utilized by
a Transmission Owner.
A Transmission Owner’s basic maintenance approach could be to remove all incompatible
vegetation from the right of way if it has the right to do so and has no constraints. In
mountainous terrain, however, this strategy could change to one where the Transmission Owner
manages vegetation based on vegetation-to-conductor clearances, since it might not be necessary
to remove vegetation in a valley that is far below.
If faced with constraints and assuming a line design with sufficient ground clearance, the
Transmission Owner ’s approach could then be to allow vegetation such as fruit trees, but
perhaps only up to a given height at maturity (perhaps 10 feet from the ground). If constraints
cannot be overcome and if design clearances are sufficient, an exception to the Transmission
Owner’s 10-foot guideline might be made. Finally, if the Transmission Owner has chosen to
utilize vegetation-to-conductor clearance distance methods, the Transmission Owner could have
an inspection regimen in place to regularly ensure that any impending clearance problems are
identified early for rectification.
ANSI A300 – Best Management Practices for Tree Care Operations
A description of ANSI A-300, part 7, is offered below to illustrate another maintenance approach
that could be used in developing a comprehensive transmission vegetation management program.
Introduction
Integrated Vegetation Management (IVM) is a best management practice conveyed in the
American National Standard for Tree Care Operations, Part 7 (ANSI 2006) and the International
Society of Arboriculture Best Management Practices: Integrated Vegetation Management
(Miller 2007). IVM is consistent with the requirements in FAC-003-02, and it provides
practitioners with what industry experts consider to be appropriate techniques to apply to electric
right-of-way projects in order to meet or exceed the Standard.
IVM is a system of managing plant communities whereby managers set objectives; identify
compatible and incompatible vegetation; consider action thresholds; and evaluate, select and
implement the most appropriate control method or methods to achieve set objectives. The choice
of control method or methods should be based on the environmental impact and anticipated
effectiveness; along with site characteristics, security, economics, current land use and other
factors.
Planning and Implementation
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Best management practices provide a systematic way of planning and implementing a vegetation
management program. While designed primarily with transmission systems in mind, it is also
applicable to distribution projects. As presented in ANSI A300 part 7 and the ISA best
management practices, IVM consists of 6 elements:
1)
2)
3)
4)
5)
6)
Set Objectives
Evaluate the Site
Define Action Thresholds
Evaluate and Select Control Methods
Implement IVM
Monitor Treatment and Quality Assurance
The setting of objectives, defining action thresholds, and evaluating and selecting control
methods all require decisions. The planning and implementation process is cyclical and
continuous, because vegetation is dynamic and managers must have the flexibility to adjust their
plans. Adjustments may be made at each stage as new information becomes available and
circumstances evolve.
Set Objectives
Objectives should be clearly defined and documented. Examples of objectives can
include promoting safety, preventing sustained outages caused by vegetation growing
into electric facilities, maintaining regulatory compliance, protecting structures and
security, restoring electric service during emergencies, maintaining access and clear lines
of sight, protecting the environment, and facilitating cost effectiveness.
Objectives should be based on site factors, such as workload and vegetation type, in
addition to human, equipment and financial resources. They will vary from utility to
utility and project to project, depending on line voltage and criticality, as well as
topographical, environmental, fiscal and political considerations. However, where it is
appropriate, the overriding focus should be on environmentally-sound, cost effective
control of species that potentially conflict with the electric facility, while promoting
compatible, early successional, sustainable plant communities.
Work Load Evaluations
Work-load evaluations are inventories of vegetation that could have a bearing on
management objectives. Work load assessments can capture a variety of vegetation
characteristics, such as location, height, species, size and condition, hazard status, density
and clearance from conductors. Assessments should be conducted considering voltage,
conductor sag from ambient temperatures and loading, and the potential influence of
wind on line sway.
Evaluate and Select Control Methods
Control methods are the process through which managers achieve objectives. The most
suitable control method best achieves management objectives at a particular site. Many
cases call for a combination of methods. Managers have a variety of controls from which
to choose, including manual, mechanical, herbicide and tree growth regulators,
biological, and cultural options.
Manual Control Methods
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Manual methods employ workers with hand-carried tools, including chainsaws,
handsaws, pruning shears and other devices to control incompatible vegetation. The
advantage of manual techniques is that they are selective and can be used where others
may not be. On the other hand, manual techniques can be inefficient and expensive
compared to other methods.
Mechanical Control Methods
Mechanical controls are done with machines. They are efficient and cost effective,
particularly for clearing dense vegetation during initial establishment, or reclaiming
neglected or overgrown right of way. On the other hand, mechanical control methods can
be non-selective and disturb sensitive sites.
Tree Growth Regulator and Herbicide Control Methods
Tree growth regulators and herbicides can be effective for vegetation management. Tree
growth regulators (TGRs) are designed to reduce growth rates by interfering with natural
plant processes. TGRs can be helpful where removals are prohibited or impractical by
reducing the growth rates of some fast-growing species.
Herbicides control plants by interfering with specific botanical biochemical pathways.
Herbicide use can control individual plants that are prone to re-sprout or sucker after
removal. When trees that re-sprout or sucker are removed without herbicide treatment,
dense thickets develop, impeding access, swelling workloads, increasing costs, blocking
lines-of-site, and deteriorating wildlife habitat. Treating suckering plants allows early
successional, compatible species to dominate the right-of-way and out-compete
incompatible species, ultimately reducing work.
Cultural Control Methods
Cultural methods modify habitat to discourage incompatible vegetation and establish and
manage desirable, early successional plant communities. Cultural methods take
advantage of seed banks of native, compatible species lying dormant on site. In the long
run, cultural control is the most desirable method where it is applicable.
A cultural control known as cover-type conversion provides a competitive advantage to
short-growing, early successional plants, allowing them to thrive and eventually outcompete unwanted tree species for sunlight, essential elements and water. The early
successional plant community is relatively stable, tree-resistant and reduces the amount
of work, including herbicide application, with each successive treatment.
Wire-Border Zone
The wire-border zone technique is a management philosophy that can be applied through
cultural control. W.C. Bramble and W.R. Byrnes developed it in the mid-1980s out of
research begun in 1952 on a transmission right-of-way in the Pennsylvania State Game
Lands 33 Research and Demonstration project (Yahner and Hutnik (2004).
The wire zone is the section of a utility transmission right-of-way directly under the wires
and extending outward about 10 feet on each side. The wire zone is managed to promote
a low-growing plant community dominated by grasses, herbs and small shrubs (under 3
feet in height at maturity). The border zone is the remainder of the right-of-way. It is
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managed to establish small trees and tall shrubs (under 25 feet in height at maturity).
When properly managed, diverse, tree-resistant plant communities develop in wire and
border zones. The communities not only protect the electric facility and reduce long-term
maintenance, but also enhance wildlife habitat, forest ecology and aesthetic values.
Although the wire-border zone is a best practice in many instances, it is not necessarily
universally suitable. For example, standard wire-border zone prescriptions may be
unnecessary where lines are high off the ground, such as across low valleys or canyons,
so the technique can be modified without sacrificing reliability.
One way to accommodate variances in topography is to establish different regions based
on wire height. For example, over canyon bottoms or other areas where conductors are
100 feet or more above the ground, only a few trees are likely to be tall enough to conflict
with the lines. In those cases, trees that potentially interfere with the transmission lines
can be removed selectively on a case-by-case basis.
In areas where the wire is lower, perhaps between 50-100 feet from the ground, a border
zone community can be developed throughout the right-of-way. Note that in many cases,
conductor attachment points are more than 50 feet off the ground, so a border zone
community can be cultivated near structures. Where the line is less than 50 feet off the
ground, managers could apply a full wire-border zone prescription.
An environmental advantage of this type of modification is stream protection. Streams
often course through the valleys and canyons where lines are likely to be elevated.
Leaving timber or border zone communities in canyon bottoms helps shelter this valuable
habitat, enabling managers to achieve environmentally sensitive objectives.
Implement IVM
All laws and regulations governing IVM practices and specifications written by qualified
vegetation managers must be followed. Integrated vegetation management control
methods should be implemented on regular work schedules, which are based on
established objectives and completed assessments. Work should progress systematically,
using control measures determined to be best for varying conditions at specific locations
along a right-of-way. Some considerations used in developing schedules include the
importance and type of line, vegetation clearances, work loads, growth rate of predominant
vegetation, geography, accessibility, and in some cases, time lapsed since the last scheduled
work.
Clearances Following Work
Clearances following work should be sufficient to meet management objectives,
including preventing trees from entering the Minimum Vegetation Clearance Distance,
electric safety risks, service-reliability threats and cost.
Monitor Treatment and Quality Assurance
An effective program includes documented processes to evaluate results. Evaluations
can involve quality assurance while work is underway and after it is completed.
Monitoring for quality assurance should begin early to correct any possible
miscommunication or misunderstanding on the part of crewmembers. Early and
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consistent observation and evaluation also provides an opportunity to modify the plan, if
need be, in time for a successful outcome.
Utility vegetation management programs should have systems and procedures in place
for documenting and verifying that vegetation management work was completed to
specifications. Post-control reviews can be comprehensive or based on a statistically
representative sample. This final review points back to the first step and the planning
process begins again.
Summary of A-300 example
Integrated Vegetation Management offers among others, a systematic way of planning and
implementing a vegetation management program as presented in ANSI A300 Part 7. This
methodology enables a program to comply with the NERC Transmission Vegetation
Management Program standard (FAC-003-2). Managers should select control options to best
promote management objectives.
Vegetation Inspections
As with the ANSI A-300 example, The Transmission Owner’s transmission vegetation
management program (TVMP) establishes the frequency of vegetation inspections based upon
many factors. Such local and environmental factors may include anticipated growth rates of the
local vegetation, length of the growing season for the geographical area, limited Active
Transmission Rights of Way width, rainfall amounts, etc.
Annual Work Plan
Requirement R7 of the Standard addresses the execution of the annual work plan. A
comprehensive approach that exercises the full extent of legal rights is superior to incremental
management in the long term because it reduces overall encroachments, and it ensures that future
planned work and future planned inspection cycles are sufficient at all locations on the Active
Transmission Line Right of Way. Removal is superior to pruning. Removal minimizes the
possibility of conflicts between energized conductors and vegetation. Since this is not always
possible, the Transmission Owner’s approach should be to use its prescribed vegetation
maintenance methods to work towards or achieve the maximum use of the Active Transmission
Line Right of Way.
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Requirement R4
R4. Each Transmission Owner, without any
intentional time delay, shall notify the
control center holding switching
authority for the associated transmission
line when qualified personnel confirm
the existence of a vegetation condition
that is likely to cause a Fault at any
moment.
Rationale
To ensure expeditious communication between
qualified field personnel and proper operating
personnel when a critical situation is
confirmed. Qualified field personnel may
include lineworkers and utility arborists.
M4. Each Transmission Owner that has a vegetation condition likely to cause a Fault at any
moment, as confirmed by qualified personnel, will have evidence that it notified the control
center holding switching authority for the associated transmission line without any intentional
time delay. Examples of evidence may include control center logs, voice recordings, switching
orders, clearance orders and subsequent work orders.
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the
Transmission Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4
involves the notification of potentially threatening vegetation conditions, without any intentional
delay, to the control center holding switching authority for that specific transmission line.
Examples of acceptable unintentional delays may include communication system problems (for
example, cellular service or two-way radio disabled), crews located in remote field locations
with no communication access, delays due to severe weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of a qualified employee who personally identifies such a threat in the field.
Confirmation could also be made by sending out a qualified person to evaluate a situation
reported by a landowner or an unqualified employee.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an assessment
of the possible sag or movement of the conductor while operating between no-load conditions
and its rating.
The Transmission Owner has the responsibility to ensure the proper communication between
field personnel and the control center to allow the control center to take the appropriate action
until the vegetation threat is relieved. Appropriate actions may include a temporary reduction in
the line loading, switching the line out of service, or positioning the system in recognition of the
increasing risk of outage on that circuit. The notification of the threat should be communicated in
terms of minutes or hours as opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some Transmission Owners may have a danger tree identification
program that identifies trees for removal with the potential to fall near the line. These trees
would not require notification to the control center unless they pose an immediate fall-in threat.
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Requirement R5
R5. Each Transmission Owner shall take
corrective action when it is constrained from
performing planned vegetation work, where a
transmission line is put at potential risk due to
the constraint.
M5. Each Transmission Owner has evidence of the
corrective action taken for each constraint where a
transmission line was put at potential risk.
Examples of acceptable forms of evidence may
include initially-planned work orders,
documentation of constraints from landowners,
court orders, inspection records of increased
monitoring, documentation of the de-rating of
lines, revised work orders, invoices, and evidence
that a line was de-energized.
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
Transmission Owner from performing
planned vegetation maintenance work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the Transmission Owner to put interim
measures in place, rather than do nothing.
For example, in the 2003 NE blackout a
Transmission Owner was prevented by a
court order from performing planned work.
However, when the court order expired, the
TO failed to take action to maintain the
vegetation resulting in a sustained outage
that contributed to the cascade.
The corrective action process is not intended
to address situations where a planned work
methodology cannot be performed but an
alternate work methodology can be used.
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
Transmission Owner for the mitigation of Sustained Outage risk when temporarily constrained
from performing vegetation maintenance. The intent of this requirement is to deal with situations
that prevent the Transmission Owner from performing planned vegetation management work
and, as a result, have the potential to put the transmission line at risk. Constraints to performing
vegetation maintenance work as planned could result from legal injunctions filed by property
owners, the discovery of easement stipulations which limit the Transmission Owner’s rights, or
other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
Transmission Owner is not under any immediate time constraint for achieving the management
objective, can easily reschedule work using an alternate approach, and therefore does not need to
take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the Transmission Owner is required to take an interim corrective action to mitigate the potential
risk to the transmission line. A wide range of actions can be taken to address various situations.
General considerations include:
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•
•
•
•
•
Identifying locations where the Transmission Owner is constrained from performing
planned vegetation maintenance work which potentially leaves the transmission line
at risk.
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for each location.
In developing the specific action to mitigate the potential risk to the transmission line
the Transmission Owner could consider location specific measures such as modifying
the inspection and/or maintenance intervals. Where a legal constraint would not allow
any vegetation work, the interim corrective action could include limiting the loading
on the transmission line.
The Transmission Owner should document and track the specific corrective action
taken at each location. This location may be indicated as one span, one tree or a
combination of spans on one property where the constraint is considered to be
temporary.
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Requirement R6
R6. Each Transmission Owner shall perform a
Vegetation Inspection of all applicable
transmission lines at least once per
calendar year.
M6. Each Transmission Owner has evidence that
it conducted Vegetation Inspections at least
once per calendar year for applicable
transmission lines. Examples of acceptable
forms of evidence may include work orders,
invoices, or inspection records.
Rationale
Inspections are used by Transmission Owners
to prevent the encroachment of vegetation into
the MVCD and provide a basis for assessing
risk. This requirement sets a minimum
vegetation inspection frequency of once per
calendar year. Based upon average growth
rates across North America and on common
utility practice, this minimum frequency is
reasonable. Transmission Owners should
consider local and environmental factors that
could warrant more frequent inspections.
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections that fits general industry practice. In addition, the fact that Vegetation
Inspections can be performed in conjunction with general line inspections further facilitates a
Transmission Owner’s ability to meet this requirement. However, the Transmission Owner may
determine that more frequent inspections are needed to maintain reliability levels, dependent
upon such factors as anticipated growth rates of the local vegetation, length of the growing
season for the geographical area, limited Active Transmission ROW width, and rainfall amounts.
Therefore it is expected that some transmission lines may be designated with a higher frequency
of inspections.
The VSL for Requirement R6 has VSL categories ranked by the percentage of the required ROW
inspections completed. To calculate the percentage of inspection completion, the Transmission
Owner may choose units such as: line miles or kilometers, circuit miles or kilometers, pole line
miles, ROW miles, etc.
For example, when a Transmission Owner operates 2,000 miles of 230 kV transmission lines this
Transmission Owner will be responsible for inspecting all 2,000 miles of 230 kV transmission
lines at least once during the calendar year. If one of the included lines was 100 miles long, and
if it was not inspected during the year, then the amount failed to inspect would be 100/2000 =
0.05 or 5%. The “Low VSL” for R6 would apply in this example.
FAC-003-2 Technical Reference
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32
NERC Standard FAC-003-2 Technical Reference
Requirement R7
R7. Each Transmission Owner shall complete
the work in an annual vegetation work plan
to ensure no vegetation encroachments
occur within the MVCD. Modifications to
the work plan in response to changing
conditions or to findings from vegetation
inspections may be made and documented
provided they do not put the transmission
system at risk of a vegetation encroachment.
Examples of reasons for modification to
annual plan may include:
•
•
•
•
•
•
•
•
•
•
Rationale
This requirement sets the expectation that the
work identified in the annual work plan will
be completed as planned. An annual
vegetation work plan allows for work to be
modified for changing conditions, taking into
consideration anticipated growth of
vegetation and all other environmental
factors, provided that the changes do not
violate the encroachment within the MVCD.
Change in expected growth rate/environmental factors
Major storms
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Funding adjustments (increase or decrease)
Emerging technologies
M7. Each Transmission Owner has evidence that it completed its annual vegetation work plan.
Examples of acceptable forms of evidence may include a copy of the completed annual work
plan (including modifications if any), dated work orders, dated invoices, or dated inspection
records.
R7 is a risk-based requirement. The Transmission Owner is required to implement an annual
work plan for vegetation management to accomplish the purpose of this standard. Modifications
to the work plan in response to changing conditions or to findings from vegetation inspections
may be made and documented provided they do not put the transmission system at risk. The
annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a
“line-by-line” detailed description of all work to be performed. It is only intended to require that
the Transmission Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation into
the MVCD.
The ability to modify the work plan allows the Transmission Owner to change priorities or
treatment methodologies during the year as conditions or situations dictate. For example recent
line inspections may identify unanticipated high priority work, weather conditions (drought)
could make herbicide application ineffective during the plan year, or a major storm could require
redirecting local resources away from planned maintenance. This situation may also include
complying with mutual assistance agreements by moving resources off the Transmission
Owner’s system to work on another system. Any of these examples could result in acceptable
FAC-003-2 Technical Reference
June 28, 2010
33
NERC Standard FAC-003-2 Technical Reference
deferrals or additions to the annual work plan. Modifications to the annual work plan must
always ensure the reliability of the electric Transmission system.
In general, the vegetation management maintenance approach should use the full extent of the
Transmission Owner’s easement, fee simple and other legal rights allowed. A comprehensive
approach that exercises the full extent of legal rights on the Active Transmission Line ROW is
superior to incremental management in the long term because it reduces the overall potential for
encroachments, and it ensures that future planned work and future planned inspection cycles are
sufficient.
When developing the annual work plan the Transmission Owner should allow time for
procedural requirements to obtain permits to work on federal, state, provincial, public, tribal
lands. In some cases the lead time for obtaining permits may necessitate preparing work plans
more than a year prior to work start dates. Transmission Owners may also need to consider those
special landowner requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the Transmission
Owner, evidence of successful annual work plan execution could consist of signed-off work
orders, signed contracts, printouts from work management systems, spreadsheets of planned
versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence
may include photographs, and walk-through reports.
FAC-003-2 Technical Reference
June 28, 2010
34
NERC Standard FAC-003-2 Technical Reference
Appendix 1: Clearance Distance Derivation by the
Gallet Equation
The Gallet Equation is a well-known method of computing the required strike distance for proper
insulation coordination, and has the ability to take into account various air gap geometries, as
well as non-standard atmospheric conditions. When the Gallet Equation and conservative
probabilistic methods are combined, i.e. deterministic design, sparkover probabilities of 10-6 or
less are achieved. This approach is well known for its conservatism and was used to design the
first 500 kV and 765 kV lines in North America [1]. Thus, the deterministic design approach
using the Gallet Equation is used for the standard to compute the minimum strike distance
between transmission lines and the vegetation that may be present in or along the transmission
corridor.
Method Explanation (Gallet Equation)
In 1975 G. Gallet published a benchmark paper that provided a method to compute the critical
flashover voltage (CFO) of various air gap geometries [4]. The Gallet Equation uses various
“gap factors” to take into account various air gap geometries. Various gap factor values are
provided in [1]. If the vegetation in a transmission corridor, e.g. a tree, is assumed electrically to
be a large structure then the CFO of such an air gap geometry can be computed for dry or wet
conditions using a well established equation proposed by Gallet [1],[2],[4],
CFOA = k w ⋅ k g ⋅ δ m ⋅
3400
8
1+
D
(1)
where,
kw
is defined as the factor that takes into account wet or dry conditions (dry = 1.0
and wet = 0.96) and phase arrangement (multiply by 1.08 for outside phase), e.g.
outside phase and wet conditions = (0.96)(1.08) = 1.037,
kg
is defined as the gap factor (1.3 for conductor to large structure),
D
is the strike distance (m),
CFOA
is the CFO for the relative air density (kV).
δ
is defined as the relative air density and is approximately equal to (2) where A is
the altitude in km,
δ =e
A
8.6
(2)
=
m 1.25G0 ( G0 − 0.2 )
(3)
CFOs
500 ⋅ D
(4)
G0 =
FAC-003-2 Technical Reference
June 28, 2010
−
35
NERC Standard FAC-003-2 Technical Reference
CFOs = k w ⋅ k g ⋅
3400
8
1+
D
(5)
where CFOS is the CFO for standard atmospheric conditions (kV). Using (1)-(5), the required CFOA can be
computed using an iterative process.
Once the CFOA is known, deterministic methods can be used to determine the required clearance
distance. If we let the maximum switching overvoltage be equal to the withstand voltage of the
air gap (CFOA - 3σ) then the CFOA can be written as (6).
Vm
σ
1− 3
CFOA
CFOA =
(6)
where
Vm is equal to the maximum switching overvoltage, i.e. the value that has a 0.135% chance of being
exceeded,
σ is the standard deviation of the air gap insulation,
CFOA is the critical flashover voltage of the air gap insulation under non-standard atmospheric conditions.
The ratio of σ to the CFOA given in (6) can be assumed to be 0.05 (5%) [1]. Thus, (6) can be
written as (7).
CFOA =
Vm
0.85
(7)
Substituting (7) into (1) we arrive at (8).
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ m ⋅
3400
8
1+
D
(8)
Equation 8 relates the maximum transient overvoltage, Vm, to the air gap distance, D. Using (8)
to compute the required clearance distance for the specified air gap geometry (conductor to large
structure) results in a probability of flashover in the range of 10-6.
TRANSIENT OVERVOLTAGE
In general, the worst case transient overvoltages occurring on a transmission line are caused by
energizing or re-energizing the line with the latter being the extreme case if trapped charge is
present. The intent of FAC-003 is to keep a transmission line that is in service from becoming
de-energized (i.e. tripped out) due to sparkover from the line conductor to nearby vegetation.
Thus, the worst case scenarios that are typically analyzed for insulation coordination purposes
(e.g. line energization and re-energization) can be ignored. For the purposes of FAC-003-2, the
worst case transient overvoltage then becomes the maximum value that can occur with the line
energized. Determining a realistic value of transient overvoltage for this situation is difficult
because the maximum transient overvoltage factors listed in the literature are based on a
FAC-003-2 Technical Reference
June 28, 2010
36
NERC Standard FAC-003-2 Technical Reference
switching operation of the line in question. In other words, these maximum overvoltage values
(e.g. the values listed in [2], [3] and [5]) are based on the assumption that the subject line is being
energized, re-energized or de-energized. These operations, by their very nature, will create the
largest transient overvoltages. Typical values of transient overvoltages of in-service lines, as
such, are not readily available in the literature because the resulting level of overvoltage is
negligible compared with the maximum (e.g. re-energizing a transmission line with trapped
charge). A conservative value for the maximum transient overvoltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 p.u.[2]. This value is a
conservative estimate of the transient overvoltage that is created at the point of application (e.g. a
substation) by switching a capacitor bank without a pre-insertion device (e.g. closing resistors).
At voltage levels where capacitor banks are not very common (e.g. 362 kV), the maximum
transient overvoltage of an “in-service” ac line are created by fault initiation on adjacent ac lines
and shunt reactor bank switching. These transient voltages are usually 1.5 p.u. or less [2]. It is
well known that these theoretical transient overvoltages will not be experienced at locations
remote from the bus at which they were created; however, in order to be conservative, it will be
assumed that all nearby ac lines are subjected to this same level of overvoltage. Thus, a
maximum transient overvoltage factor of 2.0 p.u. for 242 kV and below and 1.4 p.u. for ac
transmission lines 362 kV and above is used to compute the required clearance distances for
vegetation management purposes.
The overvoltage characteristics of dc transmission lines vary somewhat from their ac
counterparts. The referenced empirically derived transient overvoltage factor used to calculate
the minimum clearance distances from dc transmission lines to vegetation for the purpose of
FAC-003-2 will be 1.8 p.u.[3].
EXAMPLE CALCULATION
An example calculation is presented below using the proposed method of computing the
vegetation clearance distances. It is assumed that the line in question has a maximum operating
voltage of 550 kVrms line-to-line. Using a per unit transient overvoltage factor of 1.4, the result
is a peak transient voltage of 629 kVcrest. It is further assumed that the line in question operates
at a maximum altitude of 7000 feet (2.134 km) above sea level.
The required withstand voltage of the air gap must be equal to or greater than 629 kVcrest. Since
the altitude is above sea level, (1) - (5) have to be iterated on to achieve the desired result.
Equation (9) can be used as an initial guess for the clearance distance.
Di =
8
3400 ⋅ k w ⋅ k g
Vm
0.85
(9)
−1
For our case here, Vm is equal to 629 kV, kw = 1.037 and kg = 1.3. Thus,
Di =
8
3400 ⋅ k w ⋅ k g
Vm
0.85
FAC-003-2 Technical Reference
June 28, 2010
=
−1
8
= 1.535m
3400 ⋅ 1.037 ⋅ 1.3
−1
629
0.85
(10)
37
NERC Standard FAC-003-2 Technical Reference
Using (2)-(5) and (8) the withstand voltage of the air gap is next computed. This value will then
be compared to the maximum transient overvoltage.
CFOS = k w ⋅ k g ⋅
−
3400
3400
= 1.037 ⋅ 1.3 ⋅
= 737.7 kV
8
8
1+
1+
D
1.535
A
−
2.134
8.6
8.6
=
δ e=
e =
0.78
GO =
(12)
CFOS
737.7
=
= 0.961
500 ⋅ D (500 ) ⋅ (1.535 )
(13)
m = 1.25 ⋅ GO (GO − 0.2 ) = 1.25 ⋅ 0.961(0.961 − 0.2 ) = 0.915
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ
m
(11)
3400
3400
0.915
⋅
= (0.85 )(1.037 )(1.3 )(0.78 )
8
8
1
1+
+
D
1.535
(14)
= 499.8 kV
(15)
The calculated Vm is less than 629 kV; thus, the clearance distance must be increased. A few
iterations using (2)-(5) and (8) are required until the computed Vm ≥ 629 kV. For this case it was
found that D = 1.978 m (6.49 feet) yielded Vm = 629.3 kV. Using this clearance distance the
following values were computed for the final iteration.
CFOS = k w ⋅ k g ⋅
−
3400
3400
= 1.037 ⋅ 1.3 ⋅
= 908.5 kV
8
8
1+
1+
D
1.978
A
−
2.134
8.6
8.6
=
δ e=
e =
0.78
GO =
(17)
CFOS
908.5
=
= 0.919
500 ⋅ D (500 ) ⋅ (1.978 )
(18)
m = 1.25 ⋅ GO (GO − 0.2 ) = 1.25 ⋅ 0.919(0.919 − 0.2 ) = 0.825
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ m ⋅
(16)
3400
3400
= (0.85 )(1.037 )(1.3 )(0.78 )0.825
8
8
1+
1+
D
1.978
(19)
= 629.3kV
(20)
Therefore, the minimum vegetation clearance distance for a maximum line to line ac operating
voltage of 550 kV at 7000 feet above sea level is 1.978 m (6.49 feet). Table 1 provides
calculated distances for various altitudes and maximum system operating ac voltages.
FAC-003-2 Technical Reference
June 28, 2010
38
NERC Standard FAC-003-2 Technical Reference
TABLE 1 — Minimum Vegetation Clearance Distances (MVCD) 3
For Alternating Current Voltages
( AC )
Nominal
System
Voltage
(kV)
( AC )
Maximum
System
Voltage
(kV)
765
800
500
550
345
362
230
242
161*
169
138*
145
115*
121
88*
100
69*
72
MVCD
feet
(meters)
sea level
8.06ft
(2.46m)
5.06ft
(1.54m)
3.12ft
(0.95m)
2.97ft
(0.91m)
2ft
(0.61m)
1.7ft
(0.52m)
1.41ft
(0.43m)
1.15ft
(0.35m)
0.82ft
(0.25m)
MVCD
feet
(meters)
3,000ft
(914.4m)
MVCD
feet
(meters)
4,000ft
(1219.2m)
MVCD
feet
(meters)
5,000ft
(1524m)
MVCD
feet
(meters)
6,000ft
(1828.8m)
8.89ft
(2.71m)
5.66ft
(1.73m)
3.53ft
(1.08m)
3.36ft
(1.02m)
2.28ft
(0.69m)
1.94ft
(0.59m)
1.61ft
(0.49m)
1.32ft
(0.40m)
0.94ft
(0.29m)
9.17ft
(2.80m)
5.86ft
(1.79m)
3.67ft
(1.12m)
3.49ft
(1.06m)
2.38ft
(0.73m)
2.03ft
(0.62m)
1.68ft
(0.51m)
1.38ft
(0.42m)
0.99ft
(0.30m)
9.45ft
(2.88m)
6.07ft
(1.85m)
3.82ft
(1.16m)
3.63ft
(1.11m)
2.48ft
(0.76m)
2.12ft
(0.65m)
1.75ft
(0.53m)
1.44ft
(0.44m)
1.03ft
(0.31m)
9.73ft
(2.97m)
6.28ft
(1.91m)
3.97ft
(1.21m)
3.78ft
(1.15m)
2.58ft
(0.79m)
2.21ft
(0.67m)
1.83ft
(0.56m)
1.5ft
(0.46m)
1.08ft
(0.33m)
MVCD
feet
(meters)
7,000ft
(2133.6m)
MVCD
feet
(meters)
8,000ft
(2438.4m)
MVCD
feet
(meters)
9,000ft
(2743.2m)
MVCD
feet
(meters)
10,000ft
(3048m)
MVCD
feet
(meters)
11,000ft
(3352.8m)
10.01ft
(3.05m)
6.49ft
(1.98m)
4.12ft
(1.26m)
3.92ft
(1.19m)
2.69ft
(0.82m)
2.3ft
(0.70m)
1.91ft
(0.58m)
1.57ft
(0.48m)
1.13ft
(0.34m)
10.29ft
(3.14m)
6.7ft
(2.04m)
4.27ft
(1.30m)
4.07ft
(1.24m)
2.8ft
(0.85m)
2.4ft
(0.73m)
1.99ft
(0.61m)
1.64ft
(0.50m)
1.18ft
(0.36m)
10.57ft
(3.22m)
6.92ft
(2.11m)
4.43ft
(1.35m)
4.22ft
(1.29m)
2.91ft
(0.89m)
2.49ft
(0.76m)
2.07ft
(0.63m)
1.71ft
(0.52m)
1.23ft
(0.37m)
10.85ft
(3.31m)
7.13ft
(2.17m)
4.58ft
(1.40m)
4.37ft
(1.33m)
3.03ft
(0.92m)
2.59ft
(0.79m)
2.16ft
(0.66m)
1.78ft
(0.54m)
1.28ft
(0.39m)
11.13ft
(3.39m)
7.35ft
(2.24m)
4.74ft
(1.44m)
4.53ft
(1.38m)
3.14ft
(0.96m)
2.7ft
(0.82m)
2.25ft
(0.69m)
1.86ft
(0.57m)
1.34ft
(0.41m)
* Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above).
3
The distances in this Table are the minimums required to prevent Flashover; however prudent vegetation maintenance practices dictate that substantially greater distances
will be achieved at time of vegetation maintenance.
FAC-003-2 Technical Reference
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39
NERC Standard FAC-003-2 Technical Reference
TABLE 1 (CONT.) — Minimum Vegetation Clearance Distances (MVCD)
For Direct Current Voltages
sea level
MVCD feet
(meters)
3,000ft
(914.4m)
Alt.
MVCD feet
(meters)
4,000ft
(1219.2m)
Alt.
MVCD feet
(meters)
5,000ft
(1524m)
Alt.
MVCD feet
(meters)
6,000ft
(1828.8m)
Alt.
MVCD
feet
(meters)
7,000ft
(2133.6m)
Alt.
MVCD
feet
(meters)
(8,000ft
(2438.4m)
Alt.
MVCD
feet
(meters)
9,000ft
(2743.2m)
Alt.
MVCD
feet
(meters)
10,000ft
(3048m)
Alt.
MVCD
feet
(meters)
11,000ft
(3352.8m)
Alt.
±750
13.92ft
(4.24m)
15.07ft
(4.59m)
15.45ft
(4.71m)
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.9ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
±600
10.07ft
(3.07m)
11.04ft
(3.36m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
(13.54ft
4.13m)
±500
7.89ft
(2.40m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
±400
4.78ft
(1.46m)
5.35ft
(1.63m)
5.55ft
(1.69m)
5.75ft
(1.75m)
5.95ft
(1.81m)
6.15ft
(1.87m)
6.36ft
(1.94m)
6.57ft
(2.00m)
6.77ft
(2.06m)
6.98ft
(2.13m)
±250
3.43ft
(1.05m)
4.02ft
(1.23m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5ft
(1.52m)
5.17ft
(1.58m)
( DC )
Nominal Pole
to Ground
Voltage
(kV)
MVCD feet
(meters)
FAC-003-2 Technical Reference
June 28, 2010
40
NERC Standard FAC-003-2 Technical Reference
List of Acronyms and Abbreviations
ANSI
American National Standards Institute
IEEE
Institute of Electrical and Electronics Engineers
IVM
Integrated Vegetation Management
NERC
North American Electric Reliability Corporation
FAC-003-2 Technical Reference
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41
NERC Standard FAC-003-2 Technical Reference
References
Andrew Hileman, Insulation Coordination for Power System, Marcel Dekker, New York, NY
1999
EPRI, EPRI Transmission Line Reference Book 345 kV and Above, Electric Power Research
Council, Palo Alto, Ca. 1975.
IEEE Std. 516-2003 IEEE Guide for Maintenance Methods on Energized Power Lines
G. Gallet, G. Leroy, R. Lacey, I. Kromer, General Expression for Positive Switching Impulse
Strength Valid Up to Extra Long Air Gaps, IEEE Transactions on Power Apparatus and
Systems, Vol. pAS-94, No. 6, Nov./Dec. 1975.
IEEE Std. 1313.2-1999 (R2005) IEEE Guide for the Application of Insulation Coordination.
2007 National Electric Safety Code
EPRI, HVDC Transmission Line Reference Book, EPRI TR-102764 , Project 2472-03, Final
Report, September 1993
ANSI. 2001. American National Standard for Tree Care Operations – Tree, Shrub, and Other
Plant Maintenance – Standard Practices (Pruning). Part 1. American National Standards
Institute, NY
ANSI. 2006. American National Standard for Tree Care Operations – Tree, Shrub, and Other
Plant Maintenance – Standard Practices (Integrated Vegetation Management a. Electric
Utility Rights-of-way). Part 7. American National Standards Institute, NY.
Cieslewicz, S. and R. Novembri. 2004. Utility Vegetation Management Final Report. Federal
Energy Regulatory Commission. Commissioned to support the Federal Investigation of the
August 14, 2003 Northeast Blackout. Federal Energy Regulatory Commission, Washington,
DC. pg. 39.
Kempter, G.P. 2004. Best Management Practices: Utility Pruning of Trees. International
Society of Arboriculture, Champaign, IL
Miller, R.H. 2007. Best Management Practices: Integrated Vegetation Management. Society of
Arboriculture, Champaign, IL.
Yahner, R.H. and R.J. Hutnik. 2004. Integrated Vegetation Management on an electric
transmission right-of-way in Pennsylvania, U.S. Journal of Arboriculture. 30:295-300
Results-based Initiative Ad Hoc Group. Acceptance Criteria of a Reliability Standard.
FAC-003-2 Technical Reference
June 28, 2010
42
Standards Announcement
Initial Ballot Window Open
July 9–19, 2010
Now available at: https://standards.nerc.net/CurrentBallots.aspx
Project 2007-07: Transmission Vegetation Management
An initial ballot window for proposed standard FAC-003-2 — Transmission Vegetation Management is now
open until 8 p.m. Eastern on July 19, 2010. An associated implementation plan has been posted with the
revised standard.
Members of the ballot pool associated with this project will receive a separate e-mail with a link to the nonbinding on the Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs).
On March 18, 2010, FERC issued several orders and notices of proposed rulemakings pertaining to standards
development activities and processes, suggesting a lack of progress in responding to directives from Order
693 as well in the timeliness of standards development in general. At the May 2010 NERC Board meeting,
Gerry Cauley, NERC’s President, also expressed these concerns, indicating that the resolution to these
concerns is one of NERC’s top priorities in the near term. As a result, the Standards Committee has
authorized deviations from the normal standards development process for the Vegetation Management
project, as well as other projects that have been through significant stakeholder review through the
development process, to demonstrate that the NERC enterprise is responsive to FERC directives, and is
making progress in developing new standards.
The Standards Committee approved the following deviations from the standards development process:
·
The proposed changes to the standards will be posted for a shortened comment period;
·
The ballot pool will be formed during the first few weeks of the comment period;
·
The initial ballot will be conducted during the last 10 days of the comment period; and
·
The drafting team may make modifications between the initial and recirculation ballots based on
stakeholder comments to improve the overall quality of the standard.
Instructions
Members of the ballot pool associated with this project may log in and submit their votes from the following
page: https://standards.nerc.net/CurrentBallots.aspx
Next Steps
Voting results will be posted and announced after the ballot window closes.
Project Background
The project is an update to FAC-003-1, which was approved in 2006. The items identified for revision
include the incorporation of FERC Order 693 comments related to applicability, procedural repairs to
conform to the current standards format and development procedure, technical updates and guidance to
address stakeholder suggestions, and the elimination of “fill-in-the-blank” components.
Project page: http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
Special notes about this project:
The NERC Standards Committee endorsed the use of Project 2007-07: Vegetation Management as the
prototype for the proof-of-concept for using the “results-based” criteria for developing a reliability standard.
The overall approach includes considerably more emphasis on the “concepts and assumptions” underlying
the development of requirements and goes beyond the steps most drafting teams use when developing a
standard. Accordingly, the “look and feel” of the vegetation management standard is quite different than
NERC’s existing standards. However, at the core is a set of mandatory and enforceable requirements with
useful guidance supporting these requirements, an approach NERC’s legal counsel has reviewed and finds
acceptable. More information about results-based standards can be found at:
http://www.nerc.com/filez/standards/Project2010-06_Results-based_Reliability_Standards.html
Applicability of Standards in Project
Transmission Owners
Specific facilities (see standard)
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards
development process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Lauren Koller at [email protected]
Standards Announcement
Ballot Pool and Pre-ballot Window (with Comment Period)
Project 2007-07: Vegetation Management
Now available at: http://www.nerc.com/filez/standards/VegetationManagement_Project_2007-7.html
Project 2007-07: Vegetation Management
On March 18, 2010, FERC issued several orders and notices of proposed rulemakings pertaining
to standards development activities and processes, suggesting a lack of progress in responding to
directives from Order 693 as well in the timeliness of standards development in general. At the
May 2010 NERC Board meeting, Gerry Cauley, NERC’s President, also expressed these
concerns, indicating that the resolution to these concerns is one of NERC’s top priorities in the
near term. As a result, the Standards Committee has authorized deviations from the normal
standards development process for the Vegetation Management project, as well as other projects
that have been through significant stakeholder review through the development process, to
demonstrate that the NERC enterprise is responsive to FERC directives, and is making progress
in developing new standards.
The Standards Committee approved the following deviations from the standards development
process:
•
The proposed changes to the standards will be posted for a shortened comment period;
•
The ballot pool will be formed during the first few weeks of the comment period;
•
The initial ballot will be conducted during the last 10 days of the comment period; and
•
The drafting team may make modifications between the initial and recirculation ballots
based on stakeholder comments to improve the overall quality of the standard.
Ballot Pool (through July 7, 2010)
Registered Ballot Body members may join the ballot pool until 8 a.m. Eastern on July 7, 2010
to be eligible to vote in the upcoming ballot at the following page:
https://standards.nerc.net/BallotPool.aspx. Members who join the ballot pool to vote on the
standard will automatically be entered in a separate pool to participate in the non-binding poll of
the associated violation risk factors (VRFs) and violation severity levels (VSLs). (As a
reminder, this new approach for VRFs and VSLs is one of the updates reflected in the recently
FERC-approved Reliability Standards Development Procedure – Version 7.)
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
During the pre-ballot window, members of the ballot pool may communicate with one another
by using their “ballot pool list server.” (Once the balloting begins, ballot pool members are
prohibited from using the ballot pool list servers.) The list server for this ballot pool is: [email protected]
Comment Period (through July 17, 2010)
Please use this electronic form to submit comments. If you experience any difficulties in using
the electronic form, please contact Lauren Koller at 609-524-7047.
The documents for this project — including an off-line, unofficial copy of the questions listed in
the comment form — are posted at the following site:
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
Project Background
The project is an update to FAC-003-1, which was approved in 2006. The items identified for
revision include the incorporation of FERC Order 693 comments related to applicability,
procedural repairs to conform to the current standards format and development procedure,
technical updates and guidance to address stakeholder suggestions, and the elimination of “fillin-the-blank” components. More information is available on the project page:
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
Special notes about this project:
The NERC Standards Committee endorsed the use of Project 2007-07: Vegetation Management
as the prototype for the proof-of-concept for using the “results-based” criteria for developing a
reliability standard. The overall approach includes considerably more emphasis on the “concepts
and assumptions” underlying the development of requirements and goes beyond the steps most
drafting teams use when developing a standard. Accordingly, the “look and feel” of the
vegetation management standard is quite different than NERC’s existing standards. However, at
the core is a set of mandatory and enforceable requirements with useful guidance supporting
these requirements, an approach NERC’s legal counsel has reviewed and finds acceptable. More
information about results-based standards can be found at:
http://www.nerc.com/filez/standards/Project2010-06_Results-based_Reliability_Standards.html
Applicability of Standards in Project
Transmission Owners
Specific facilities (see standard)
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Lauren Koller at [email protected]
-2-
Standards Announcement
Ballot Pool and Pre-ballot Window (with Comment Period)
Project 2007-07: Vegetation Management
Now available at: http://www.nerc.com/filez/standards/VegetationManagement_Project_2007-7.html
Project 2007-07: Vegetation Management
On March 18, 2010, FERC issued several orders and notices of proposed rulemakings pertaining
to standards development activities and processes, suggesting a lack of progress in responding to
directives from Order 693 as well in the timeliness of standards development in general. At the
May 2010 NERC Board meeting, Gerry Cauley, NERC’s President, also expressed these
concerns, indicating that the resolution to these concerns is one of NERC’s top priorities in the
near term. As a result, the Standards Committee has authorized deviations from the normal
standards development process for the Vegetation Management project, as well as other projects
that have been through significant stakeholder review through the development process, to
demonstrate that the NERC enterprise is responsive to FERC directives, and is making progress
in developing new standards.
The Standards Committee approved the following deviations from the standards development
process:
•
The proposed changes to the standards will be posted for a shortened comment period;
•
The ballot pool will be formed during the first few weeks of the comment period;
•
The initial ballot will be conducted during the last 10 days of the comment period; and
•
The drafting team may make modifications between the initial and recirculation ballots
based on stakeholder comments to improve the overall quality of the standard.
Ballot Pool (through July 7, 2010)
Registered Ballot Body members may join the ballot pool until 8 a.m. Eastern on July 7, 2010
to be eligible to vote in the upcoming ballot at the following page:
https://standards.nerc.net/BallotPool.aspx. Members who join the ballot pool to vote on the
standard will automatically be entered in a separate pool to participate in the non-binding poll of
the associated violation risk factors (VRFs) and violation severity levels (VSLs). (As a
reminder, this new approach for VRFs and VSLs is one of the updates reflected in the recently
FERC-approved Reliability Standards Development Procedure – Version 7.)
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
During the pre-ballot window, members of the ballot pool may communicate with one another
by using their “ballot pool list server.” (Once the balloting begins, ballot pool members are
prohibited from using the ballot pool list servers.) The list server for this ballot pool is: [email protected]
Comment Period (through July 17, 2010)
Please use this electronic form to submit comments. If you experience any difficulties in using
the electronic form, please contact Lauren Koller at 609-524-7047.
The documents for this project — including an off-line, unofficial copy of the questions listed in
the comment form — are posted at the following site:
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
Project Background
The project is an update to FAC-003-1, which was approved in 2006. The items identified for
revision include the incorporation of FERC Order 693 comments related to applicability,
procedural repairs to conform to the current standards format and development procedure,
technical updates and guidance to address stakeholder suggestions, and the elimination of “fillin-the-blank” components. More information is available on the project page:
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
Special notes about this project:
The NERC Standards Committee endorsed the use of Project 2007-07: Vegetation Management
as the prototype for the proof-of-concept for using the “results-based” criteria for developing a
reliability standard. The overall approach includes considerably more emphasis on the “concepts
and assumptions” underlying the development of requirements and goes beyond the steps most
drafting teams use when developing a standard. Accordingly, the “look and feel” of the
vegetation management standard is quite different than NERC’s existing standards. However, at
the core is a set of mandatory and enforceable requirements with useful guidance supporting
these requirements, an approach NERC’s legal counsel has reviewed and finds acceptable. More
information about results-based standards can be found at:
http://www.nerc.com/filez/standards/Project2010-06_Results-based_Reliability_Standards.html
Applicability of Standards in Project
Transmission Owners
Specific facilities (see standard)
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Lauren Koller at [email protected]
-2-
NERC Standards
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2007-07 Vegetation Management FAC-003-2_in
Password
Ballot Period: 7/9/2010 - 7/19/2010
Ballot Type: Initial
Log in
Total # Votes: 262
Register
Total Ballot Pool: 304
Quorum: 86.18 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
65.93 %
Vote:
Ballot Results: The standard will proceed to recirculation ballot.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
90
9
74
22
54
35
0
7
6
7
304
#
Votes
1
0.4
1
1
1
1
0
0.4
0.6
0.5
6.9
#
Votes
Fraction
42
2
33
9
27
17
0
2
6
5
143
Negative
Fraction
0.575
0.2
0.569
0.6
0.675
0.63
0
0.2
0.6
0.5
4.549
Abstain
No
# Votes Vote
31
2
25
6
13
10
0
2
0
0
89
0.425
0.2
0.431
0.4
0.325
0.37
0
0.2
0
0
2.351
4
4
9
4
5
2
0
2
0
0
30
13
1
7
3
9
6
0
1
0
2
42
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Baltimore Gas & Electric Company
Member
Rodney Phillips
Kirit S. Shah
Paul B. Johnson
Jason Shaver
Robert D Smith
John Bussman
Scott Kinney
John J. Moraski
https://standards.nerc.net/BallotResults.aspx?BallotGUID=25093261-29d4-4e54-92a9-cd6fd28c7b7f[7/20/2010 9:25:15 AM]
Ballot
Comments
Negative
Negative
Affirmative
Affirmative
Negative
View
View
View
View
Abstain
Negative
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
BC Transmission Corporation
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
CenterPoint Energy
Central Maine Power Company
City of Vero Beach
City Utilities of Springfield, Missouri
Cleco Power LLC
Commonwealth Edison Co.
Consolidated Edison Co. of New York
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
E.ON U.S. LLC
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Gainesville Regional Utilities
GDS Associates, Inc.
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lake Worth Utilities
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Long Island Power Authority
Manitoba Hydro
Metropolitan Water District of Southern
California
MidAmerican Energy Co.
National Grid
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Gordon Rawlings
Joseph S. Stonecipher
Eric Egge
Donald S. Watkins
Paul Rocha
Brian Conroy
Randall McCamish
Jeff Knottek
Danny McDaniel
Daniel Brotzman
Christopher L de Graffenried
Robert W. Roddy
Hertzel Shamash
James Tucker
John K Loftis
Douglas E. Hils
Larry Monday
George S. Carruba
Ralph Frederick Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Luther E. Fair
Claudiu Cadar
Harold Taylor, II
Gordon Pietsch
Ajay Garg
Bernard Pelletier
Ted E Hobson
Michael Gammon
Stan T. Rzad
Walt Gill
Larry E Watt
John W Delucca
Doug Bantam
Robert Ganley
Michelle Rheault
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
View
View
View
View
View
View
View
View
View
View
View
View
View
View
Affirmative
Affirmative
Ernest Hahn
Terry Harbour
Saurabh Saksena
Richard L. Koch
Arnold J. Schuff
Henry G. Masti
David H. Boguslawski
John Canavan
Robert Mattey
Marvin E VanBebber
Douglas G Peterchuck
Michael T. Quinn
Brad Chase
Lawrence R. Larson
Chifong L. Thomas
Mark Sampson
Ronald Schloendorn
John C. Collins
Frank F. Afranji
Richard J Kafka
Larry D. Avery
Brenda L Truhe
Sammy Roberts
Laurie Williams
Kenneth D. Brown
Chad Bowman
Tim Kelley
Robert Kondziolka
Terry L. Blackwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=25093261-29d4-4e54-92a9-cd6fd28c7b7f[7/20/2010 9:25:15 AM]
Affirmative
Negative
Affirmative
Negative
View
View
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
View
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
SCE&G
Seattle City Light
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tennessee Valley Authority
Tri-State G & T Association Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
BC Transmission Corporation
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Ameren Services
American Electric Power
Arizona Public Service Co.
Atlantic City Electric Company
BC Hydro and Power Authority
Blue Ridge Power Agency
Bonneville Power Administration
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Leesburg
Cleco Utility Group
ComEd
Consolidated Edison Co. of New York
Constellation Energy
Consumers Energy
Consumers Power Inc.
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Power Corporation
Gainesville Regional Utilities
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
Manitoba Hydro
Henry Delk, Jr.
Pawel Krupa
Richard McLeon
Dana Cabbell
Horace Stephen Williamson
William G. Hutchison
James L. Jones
Gary W Cox
Noman Lee Williams
Larry Akens
Keith V. Carman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Jason L. Murray
Faramarz Amjadi
Chuck B Manning
Kim Warren
Jason L Marshall
Alden Briggs
Gregory Campoli
Tom Bowe
Charles H Yeung
Richard J. Mandes
Bob Reeping
Mark Peters
Raj Rana
Thomas R. Glock
James V. Petrella
Pat G. Harrington
Duane S. Dahlquist
Rebecca Berdahl
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Phil Janik
Bryan Y Harper
Bruce Krawczyk
Peter T Yost
Carolyn Ingersoll
David A. Lapinski
Roman Gillen
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F Gildea
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Kevin Querry
Joe McKinney
Lee Schuster
Kenneth Simmons
Anthony L Wilson
R Scott S. Barfield-McGinnis
Sam Kokkinen
Gwen S Frazier
Michael D. Penstone
Charles Locke
Gregory David Woessner
Mace Hunter
Bruce Merrill
Kenneth Silver
Charles A. Freibert
Greg C Parent
https://standards.nerc.net/BallotResults.aspx?BallotGUID=25093261-29d4-4e54-92a9-cd6fd28c7b7f[7/20/2010 9:25:15 AM]
Affirmative
Abstain
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Abstain
Abstain
Negative
Abstain
Abstain
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Negative
Abstain
Negative
Negative
Negative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
MEAG Power
MidAmerican Energy Co.
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
OTP Wholesale Marketing
PacifiCorp
PECO Energy an Exelon Co.
Platte River Power Authority
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Public Utility District No. 2 of Grant County
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
South Carolina Electric & Gas Co.
Southern California Edison Co.
Springfield Utility Board
Tampa Electric Co.
Turlock Irrigation District
Umatilla Electric Cooperative
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power - Ohio
American Public Power Association
City of Clewiston
City of New Smyrna Beach Utilities
Commission
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Madison Gas and Electric Co.
Modesto Irrigation District
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Wisconsin Energy Corp.
AEP Service Corp.
Amerenue
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Chelan County Public Utility District #1
City of Grand Island
City of Tallahassee
City Water, Light & Power of Springfield
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
Steven Grego
Thomas C. Mielnik
Don Horsley
Steven M. Jackson
John Bos
Marilyn Brown
Michael Schiavone
William SeDoris
David T. Anderson
David Burke
Ballard Keith Mutters
Bradley Tollerson
John Apperson
Vincent J. Catania
Terry L Baker
Robert Reuter
Jeffrey Mueller
Kenneth R. Johnson
Greg Lange
James Leigh-Kendall
Ken Dizes
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
Hubert C. Young
David Schiada
Jeff Nelson
Ronald L Donahey
Casey Hashimoto
Steve Eldrige
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Allen Mosher
Kevin McCarthy
Timothy Beyrle
David Frank Ronk
Rick Syring
Daniel Herring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Bob C. Thomas
Joseph G. DePoorter
Spencer Tacke
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
Mike Ramirez
Hao Li
Steven R Wallace
Steve McElhaney
Anthony Jankowski
Brock Ondayko
Sam Dwyer
Edward F. Groce
Clement Ma
Francis J. Halpin
John Yale
Jeff Mead
Alan Gale
Karl E. Kohlrus
Wilket (Jack) Ng
James B Lewis
Bob Essex
https://standards.nerc.net/BallotResults.aspx?BallotGUID=25093261-29d4-4e54-92a9-cd6fd28c7b7f[7/20/2010 9:25:15 AM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Abstain
Affirmative
Negative
Negative
Affirmative
Abstain
Negative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Negative
Affirmative
Abstain
Negative
Abstain
Abstain
Affirmative
Negative
View
View
View
View
View
View
View
View
View
View
Negative
Negative
Affirmative
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Negative
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Negative
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NERC Standards
5
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Dominion Resources, Inc.
Duke Energy
East Kentucky Power Coop.
Entergy Corporation
Exelon Nuclear
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Power LLC
Reedy Creek Energy Services
Sacramento Municipal Utility District
Salt River Project
Seattle City Light
Seminole Electric Cooperative, Inc.
South California Edison Company
South Carolina Electric & Gas Co.
South Mississippi Electric Power Association
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association Inc.
U.S. Army Corps of Engineers Northwestern
Division
U.S. Bureau of Reclamation
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Bonneville Power Administration
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Eugene Water & Electric Board
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
New York Power Authority
Northern Indiana Public Service Co.
OTP Wholesale Marketing
PacifiCorp
Mike Garton
Robert Smith
Stephen Ricker
Stanley M Jaskot
Michael Korchynsky
Kenneth Dresner
David Schumann
Cynthia E Sulzer
Donald Gilbert
Scott Heidtbrink
Mike Blough
Dennis Florom
Charlie Martin
Mark Aikens
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Christopher Schneider
Gerald Mannarino
Michael K Wilkerson
Mahmood Z. Safi
Stacie Hebert
Richard J. Padilla
Sandra L. Shaffer
Gary L Tingley
Tim Hattaway
Mark A. Heimbach
Wayne Lewis
David Murray
Bernie Budnik
Bethany Wright
Glen Reeves
Michael J. Haynes
Brenda K. Atkins
Ahmad Sanati
Richard Jones
Jerry W Johnson
Scott M. Helyer
George T. Ballew
Barry Ingold
Negative
Martin Bauer P.E.
Leonard Rentmeester
Liam Noailles
Edward P. Cox
Brenda S. Anderson
Matthew D Cripps
Nickesha P Carrol
Brenda Powell
Louis S Slade
Walter Yeager
Terri F Benoit
Daniel Mark Bedbury
Pulin Shah
Mark S Travaglianti
Thomas E Washburn
Silvia P Mitchell
Donna Stephenson
Thomas Saitta
Paul Shipps
Eric Ruskamp
Daryn Barker
Daniel Prowse
Thomas Papadopoulos
Joseph O'Brien
Bruce Glorvigen
Gregory D Maxfield
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David Gordon
Karl Bryan
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NERC Standards
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Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
RRI Energy
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
JDRJC Associates
Pacific Northwest Generating Cooperative
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Public Service Commission of South Carolina
Utah Public Service Commission
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool Regional Entity
Western Electricity Coordinating Council
James Eckelkamp
James D. Hebson
Hugh A. Owen
Trent Carlson
Mike Hummel
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Matt H Bullard
Marjorie S. Parsons
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
John Stonebarger
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David F. Lemmons
Negative
James A Maenner
Abstain
Roger C Zaklukiewicz
Negative
Jim D. Cyrulewski
Abstain
Margaret Ryan
Affirmative
Peggy Abbadini
Brian Evans-Mongeon
Negative
Terry Volkmann
Affirmative
William Mitchell Chamberlain Affirmative
Donald E. Nelson
Affirmative
Diane J. Barney
Affirmative
Jerome Murray
Philip Riley
Ric Campbell
Dan R. Schoenecker
Alan Adamson
Guy V. Zito
Jacquie Smith
Carter B Edge
Stacy Dochoda
Louise McCarren
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
A New Jersey Nonprofit Corporation
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Standards Announcement
Initial Ballot Results
Now available at: https://standards.nerc.net/Ballots.aspx
Project 2007-07: Transmission Vegetation Management
The initial ballot for proposed standard FAC-003-2 — Transmission Vegetation Management ended on
July 19, 2010.
Ballot Results
Voting statistics are listed below, and the Ballot Results Web page provides a link to the detailed results:
Quorum:
Approval:
86.18 %
65.93 %
Since at least one negative ballot included a comment, and the affirmative votes did not meet the
threshold for approval, these results are not final. Another comment and ballot period will be conducted.
Violation Risk Factor (VRF) and Violation Severity Level (VSL) Non-binding Poll Results
Only 6% of the non-binding polls for VRFs and VSLs were returned, rendering the results inconclusive.
By comparison, the Underfrequency Load Shedding, Protection System Maintenance and Testing,
Backup Facilities, and Transmission Loading Relief standards all had greater than 80% of the nonbinding polls for VRFs and VSLs returned with an opinion.
Next Steps
The drafting team must draft and post responses to comments received through the public comment
period and the initial ballot. The response to comments and proposed revisions will be posted for a 30day comment period, and a “successive ballot” will be conducted during the last ten days of that 30-day
comment period. A non-binding poll of the proposed VRFs and VSLs will also be conducted during the
last ten days of the 30-day comment period.
Project Background
The project is an update to FAC-003-1, which was approved in 2006. The items identified for revision
include the incorporation of FERC Order 693 comments related to applicability, procedural repairs to
conform to the current standards format and development procedure, technical updates and guidance to
address stakeholder suggestions, and the elimination of “fill-in-the-blank” components.
More information is available on the project page: http://www.nerc.com/filez/standards/VegetationManagement_Project_2007-7.html
The NERC Standards Committee endorsed the use of Project 2007-07: Vegetation Management as the
prototype for the proof-of-concept for using the “results-based” criteria for developing a reliability
standard. The overall approach includes considerably more emphasis on the “concepts and assumptions”
underlying the development of requirements and goes beyond the steps most drafting teams use when
developing a standard. Accordingly, the “look and feel” of the vegetation management standard is quite
different than NERC’s existing standards. However, at the core is a set of mandatory and enforceable
requirements with useful guidance supporting these requirements, an approach NERC’s legal counsel has
reviewed and finds acceptable. More information about results-based standards can be found at:
http://www.nerc.com/filez/standards/Project2010-06_Results-based_Reliability_Standards.html
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards
development process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
Ballot Criteria
Approval requires both a (1) quorum, which is established by at least 75% of the members of the ballot
pool for submitting either an affirmative vote, a negative vote, or an abstention, and (2) A two-thirds
majority of the weighted segment votes cast must be affirmative; the number of votes cast is the sum of
affirmative and negative votes, excluding abstentions and nonresponses. If there are no negative votes
with reasons from the first ballot, the results of the first ballot shall stand. If, however, one or more
members submit negative votes with reasons, a second ballot shall be conducted.
For more information or assistance,
please contact Lauren Koller at [email protected]
Individual or group. (44 Responses)
Name (28 Responses)
Organization (28 Responses)
Group Name (16 Responses)
Lead Contact (16 Responses)
Question 1 (43 Responses)
Question 1 Comments (44 Responses)
Question 2 (41 Responses)
Question 2 Comments (44 Responses)
Question 3 (42 Responses)
Question 3 Comments (44 Responses)
Question 4 (43 Responses)
Question 4 Comments (44 Responses)
Question 5 (42 Responses)
Question 5 Comments (44 Responses)
Question 6 (40 Responses)
Question 6 Comments (44 Responses)
Question 7 (38 Responses)
Question 7 Comments (44 Responses)
Question 8 (43 Responses)
Question 8 Comments (44 Responses)
Individual
David Burke
Orange and Rockland Utilities, Inc.
Yes
There should be a statement in Table 3 that is consistent with footnote
number 2 stating that the minimum width of the Active Transmission Line
ROW is either the full width of the easement or, if the easement is wider
than the distances in Table 3, the minimum distances must not be less
than the distances shown in the Table.
Yes
Yes
Yes
Yes
Draft 4 version of R1/R2
Orange and Rockland Utilities, Inc prefers the Draft 4 version. The wording
in the VSLs should be modified for both Requirements to include the
phrase 'manage vegetation.' The phrase 'manage vegetation' requires a
utility to take specific action to prevent encroachments/outages.
VSLs proposed by the VM SDT
The wording in the VM STD VSLs should be modified to include whether or
not the TO managed any vegetation on that particular line. A more severe
VSL should be assigned to any encroachment or sustained outage that was
caused as a result of a TO not performing any vegetation management
activities on that line. For example, if vegetation management activities
were completed on 80% or 90% of the line and additional work was in
progress on the remainder of the line but an encroachement or sustained
outage occurred on the spans that were scheduled to be done as part of
the annual plan, the TO should be held accountable for this but at a lower
severity level.
Yes
In R5, the SDT should better define the phrase 'where a transmission line
is put at potential risk due to the constraint.' This is rather vague and
could lead to inconsistent practices between utilities. Orange and Rockland
Utilities, Inc. defines all undesirable species on the full width of the ROW
as 'potential risks to the transmission line' regardless of height or location
at the time of vegetation management. Interim corrective action should
only be required when the potential risk is approaching the imminent
threat classification.
Group
Western Area Power Administration
Brandy A. Dunn
Yes
Suggest using a total right-of-way width in Table 3 rather than a distance
measured from centerline.
Yes
Yes
However, the last sentence added to the measure is imprecise and
introduces undesirable subjectivity and confusion to the process for
determining a compliance violation.
Yes
No
As the list of “examples of reasons for modification†is not all
inclusive, it is unnecessary and could result in confusion regarding
compliance when a scenario other than one listed requires a change.
Further, documentation of changes to the annual plan adds unnecessary
administrative burden which is inconsistent with a performance based
standards approach.
Draft 4 version of R1/R2
The current language of Draft 4 is the most flexible and offers industry the
best opportunity for executing a cost effective and efficient program.
VSLs proposed by the VM SDT
Unlike a “grow-inâ€, a “fall-in†or “blow-in†has never
caused or contributed to a cascading outage. Further, the “zero
tolerance†approach of this standard remains impractical and
unreasonable. The gradated indicators of program performance associated
with a “fall-inâ€, “blow-in†and “grow-in†offer some
measure of reasonableness to the requirement.
No
Group
Northeast Power Coordinating Council
Guy Zito
No
There should be a statement in Table 3 that is consistent with footnote
number 2 stating that the minimum width of the Active Transmission Line
ROW is either the full width of the easement or, if the easement is wider
than the distances in Table 3, the minimum distances must not be less
than the distances shown in the Table. The use of a minimum distance
from the centerline of the circuit or structure is an incorrect measure to
use for a set clearance distance of the active transmission right-of-way.
The description does not take into account vertical versus horizontal
design configuration. Consideration should be given for the type of
construction as different construction types (H-Frame, Lattice towers,
Monopole delta or vertical construction) will require different widths of a
cleared right-of-way to provide the necessary openings for these circuits. A
minimum distance for 345-kV is now set at 150 feet based on the
minimum distances from centerline. This may be correct for certain HFrame and Lattice Tower configurations but it is excessive for monopole
situations. A single pole configuration with vertically aligned conductors
does not need this full 150 foot width. It is strongly recommended that a
minimum distance from conductor be used in place of a set distance from
centerline. As long as there is at least 30 - 40 feet of clearance in the
right-of-way from the outermost conductors (adjusted to account for
maximum sway at mid-span for longer spans), then this is the distance
that should be used to develop the right-of-way widths. For example, a
monopole structure with vertically aligned conductors would result in a
cleared active right-of-way width of only 80 feet (40 feet from conductor
to edge of cleared active right-of-way) using the minimum distances from
the conductors. There is no need to extend this distance another 35 feet
(on each side) in order to obtain the full 150 foot width. This requirement
is excessive and must be adjusted to account for line construction
variations. Instead of using the term "Centerline" as referenced on Table
3, the use of "outer phase" or "phase closest to tree line" would be more
appropriate. There is published literature using the term “cleared
width†to indicate the distance from the outer phase to the tree line.
This distance should be used in the Active ROW definition. The word
easement is also used in the definition. Is there a reason the Active ROW
only includes easements, not fee ownership, license or some other right to
occupy and manage the ROW? Would Active ROW include “danger tree
rights†on land? These questions need to be addressed in the standard
(in text) and technical reference document (in graphics).
Yes
No
A clarification for M1 is needed regarding whether entities will have to
attest to the fact that there has never been an encroachment in the MVCD.
Yes
Yes
Alternate version of R1/R2
Alternate Version E would allow a Transmission Owner to use an approach
consistent with the current version of FAC-003 by defining a minimum
clearance distance and a vegetation management clearance distance. This
approach has met the objectives of FAC-003 since 2006. Use of version E
would change the standard from a prescriptive approach to a Transmission
Owner defined approach. In addition, Alternate Version E is preferred as it
allows for variations based on differences in conductor heights, topography
and other situations where a set height is not necessarily required in all
instances and allows for the utility to determine the maximum heights of
vegetation without performing detailed calculations of what the maximum
heights must be along the various distances within each conductor span. If
the utility is tasked with managing the vegetation to ensure no
encroachments into the MVCD then it should be up to the individual utility
how best to determine its management strategies that incorporate the
determination of maximum vegetation heights in each section on its
system.
VSLs proposed by the VM SDT
The wording in the VM STD VSLs should be modified to include whether or
not the TO managed any vegetation on that particular line. A more severe
VSL should be assigned to any encroachment or sustained outage that was
caused as a result of a TO not performing any vegetation management
activities on that line. For example, if vegetation management activities
were completed on 80% or 90% of the line and additional work was in
progress on the remainder of the line, but an encroachment or sustained
outage occurred on the spans that were scheduled to be done as part of
the annual plan, the TO should be held accountable for this but at a lower
severity level.
Yes
NPCC wants to thank the SDT for the effort that has gone into developing
this proposed revision to FAC-003. Overall the new version is consistent
with FERC Order 693 and will be a straightforward, workable, and
auditable standard. One item requiring clarification and change is the
Active ROW definition. The recent addition of a centerline distance to edge
of Active ROW is not acceptable. In many areas design standards allow a
smaller ROW width with no compromise to “cleared width†or tree
related reliability of the line. The SDT needs to address this issue. In R5,
the phrase 'where a transmission line is put at potential risk due to the
constraint' should be better defined. This is vague and could lead to
inconsistent practices between utilities. All undesirable species on the full
width of the ROW are defined as 'potential risks to the transmission line'
regardless of height or location at the time of vegetation management.
Interim corrective action should only be required when the potential risk is
approaching the imminent threat classification.
Individual
Weston Davis
Central Maine Power Company, Iberdrola USA
No
Table 3 distances may not be appropriate, for example table 3 should
reflect a clearance zone based on construction type, topography, species,
or growth rates. Table 3 could give the impression that the listed distances
are the maximum, therefore suggest table 3 be removed or revised. The
Active Transmisson Line Right-of-Way defination uses the word easement,
which most likely would include danger trees in situations where danger
removals are included in the the easement language. This would expand
the scope of FAC 003 2 beyond the cleared right-of-way width.
No comment suggested.
No
Recommend SDT create two measures one measure if a tree violated the
MVCD and no outage occurred and second measure and severity level if an
outage occurred
Yes
Yes
Alternate version of R1/R2
VSLs proposed by the VM SDT
Agrees with SDT that violation risk factors must be ranked in accordance
with impact on the bulk delivery system.
No
Individual
Kasia Mihalchuk
Manitoba Hydro
Yes
Please add metric equivalents in the standard. While it makes some
aspects easier around pointing to what we need to keep "clear" to meet
NERC rules - it does limit some of our flexibility to design lines and ROWs
to your own standards. Also, the minimum only applies when you have
easement larger than the minimums in table 3, and I would assume that
does not relieve you of the responsibility to maintain ROWs appropriately if
the design of your lines requires a wider ROW.
Yes
Yes
Yes
Yes
Draft 4 version of R1/R2
I would suggest adding verbage to the draft 4 version to explicitly include
the sag and sway of the conductor to the concept of "operating within
rating and electrical operating condition“
VSLs proposed by the VM SDT
No
Individual
Jonathan Appelbaum
The United Illuminating Company
No
The definition has been altered. The last sentence "However, it is not to be
less than the width of the easement itself unless the easement exceeds
distances as shown in Table 3 for various voltage classes..." was added.
The concept of the easement is confusing and not included in the
Supplemental Reference. Table 3 of the standard is titled "Minimum
Distance from the Centerline of the Circuit to the edge of the active
transmission line ROW", no mention of easements. It is suggested that the
definition state "strip or corridor of land that is occupied by active
transmission facilities. This corridor does not include the parts of the Rightof-Way that are unused or intended for other facilities. At a minimum the
width is to be the distances as shown in Table 3 for various voltage
classes." The proper location for the definition is in the Glossary.
Yes
Yes
Yes
No
R1 and R2 are requirements that no encroachment occurs. R7, as
proposed, requires a VMP to be completed to ensure no encroachment
occurs. The Supplemental Reference for R7 does not describe the
requirement of the annual vegetation work plan to ensure no vegetation
encroachments occur within the MVCD. The Reference states the
requirement is established to diminish the risk of encroachment; which is
very different from ensuring no encroachment. In the Reference for R7 the
word “ensure†is only used to describe that flexibility in the VMP is
allowed to ensure the reliability of the Transmission System. M7 is
measuring work plan completion not the prevention of encroachment.
United Illuminating suggests that R7 be changed to: Each Transmission
Owner shall complete the work in an annual vegetation work plan to
manage the prevention of vegetation encroachments occur within the
MVCD. In this way, a violation of R1/R2 does not necessarily mean R7 is
violated. The entity does not avoid a penalty for an encroachment because
a violation of R1/R2 occurs for actual encroachment. If an encroachment
occurs the compliance enforcement authority can review the entities
vegetation management plan to determine if it is compliance with R7/M7.
Draft 4 version of R1/R2
UI prefers the draft language because we believe the intent of R1/R2 is to
capture the actual occurrence of a vegetation related interruption or
encroachment of vegetaion into the MVCD based on actual conditions.
VSLs proposed by NERC staff
United Illuminating agrees with NERC Staff that the Requirement is to
prevent encroachment of any kind. Differentiating between fall-in and
grow-in is of no consequence to the intent of the requirement.
Yes
R4: In R4 the phrase: without any intentional time delay, is a concern.
There is a time line between identification and reporting of an imminent
hazard that represents the minimal time required to complete this
Requirement. Any situation where the time between observation and
reporting is greater than this minimal time line indicates a time delay
occurred. It will be left to the compliance enforcement authority to
determine if this delay was intentional or not. It is not proper for the test
to be based on Intentional versus Non-Intentional. Using other synonyms
such as reasonable, expeditious, prompt, immediate or without hesitation
all introduce a qualitative not a quantitative attribute to the measurement.
The Supplemental Reference for R4 indicates that the imminent threat
requirement is measured in minutes or hours; again no guidance for
enforcement. R4 would be improved with an explicit time requirement of 6
hours between observation and report. This is measurable and clear. R4
should be: Each Transmission Owner shall notify the control center holding
switching authority for the associated transmission line no more than 6
hours of a qualified personnel confirm the existence of a vegetation
condition that is likely to cause a Fault at any moment. Other
commenter’s will argue that 6 hours is arbitrary or unduly prescriptive.
I believe it is in line with the Supplemental Reference and adds clarity to
the enforcement process. M4 becomes Each Transmission Owner that has
a vegetation condition likely to cause a Fault at any moment, as confirmed
by qualified personnel, will have evidence that it notified the control center
holding switching authority for the associated transmission line within 6
hours of observation. The Transmission Owner can use the inspection as
evidence of the time of observation. Effective Dates: The effective dates in
the implementation Plan is in a different form then UI was expecting.
Effective Date 1 UI has no comment. Effective date number 2 implies that
if the BOT approves the standard and FERC takes no action (neither
approves, remands or withholds approval of the standard) then the
standard will become effective in one year. This seems to create the
possibility of an effective standard without enforceability. Effective Date
number 3 implies that regardless of any action by FERC the standard will
become effective at least one year following BOT approval. Again this
creates an effective standard without enforceability. Also the use of “at
least one year†does not add any clarity to when the Standard would
be effective any way.
Individual
Patrick Simons
Idaho Power Company
No
The way I interpret this, the new definition of active transmission line right
of way takes away our ability to clear potential fall ins if they are outside
of the active transmission line ROW>
Yes
Yes
Yes
Yes
Alternate version of R1/R2
I think this gives us more flexibility to maintain our clearances.
VSLs proposed by NERC staff
Yes
I would like to see something more from NERC to clear the way for utilities
to do vegetation management on federal lands that will allow timely
vegetation management without delays from these federal entities.
Individual
Sam Stonerock
Southern California Edison Company
Yes
SCE appreciates the SDT’s efforts to replace the defined term with a
set of minimum distances. However, the proposed new Table 3 appears to
assume a horizontal configuration of transmission lines. Thus, it would
appear that those lines configured vertically (for example, two circuits on
opposite sides of a tower), the “active right of way†required would
be at least twice as large as that for horizontal lines. SCE respectfully
recommends a footnote be added to Table 3 that allows the TO to
recalculate the active right of way for lines in a vertical configuration,
based on a horizontal line configuration.
Yes
SCE generally agrees with the information contained in Part 5 –
Background. However, we question the value of placing a rationale within
the body of the standard. SCE respectfully recommends that the revised
“Background†information be added to the beginning of the
“Guidelines and Technical Basis,†which also includes explanations
for various standard segments.
Yes
SCE generally agrees with the revisions to M1 and M2, however we would
suggest the last sentence of the second paragraphs in both M1 and M2 be
modified to read: M1- Multiple Sustained Outages on an individual line, if
caused by the same vegetation, will be reported as one outage regardless
of the actual number of outages within a 24-hour period. If an
investigation of a Fault, by a qualified person, confirms that a vegetation
encroachment, as described in R1 items 2-4 (above), occurred within the
MVCD occurred, then it shall be considered a Real-time observation. M2Multiple Sustained Outages on an individual line, if caused by the same
vegetation, will be reported as one outage regardless of the actual number
of outages within a 24-hour period. If an investigation of a Fault, by a
qualified person, confirms that a vegetation encroachment, as described in
R2 items 2-4 (above), occurred within the MVCD occurred, then it shall be
considered a Real-time observation.
No
SCE prefers the Draft 3 version of R3 which read: “Each Transmission
Owner shall have a documented transmission vegetation management
program that describes how it conducts work on its Active Transmission
Line ROWs to avoid Sustained Outages due to vegetation, considering all
possible locations the conductor may occupy assuming operation within
Rating and Rated Electrical Operating Conditions.†However, if the SDT
believes it is prudent to revise R3 in response to certain commenters, SCE
would respectfully recommend R3 be revised to read: “Each
Transmission Owner shall document the procedures, processes, or
specifications it uses to prevent the encroachment of vegetation into the
MVCD. Such documentation will account for the movement of transmission
line conductors under their Rating and Rated Electrical Operating
Conditions; and the inter-relationships between vegetation growth rates,
vegetation control methods, and inspection frequency, for the
Transmission Owner’s applicable lines.â€
Yes
SCE agrees with the revisions to R7, but notes the some minor edits to the
text are still needed.
Alternate version of R1/R2
SCE prefers the operational flexibility provided by the alternate version of
R1/R2. We also note that dating back to development of FAC-003-1 and
related comment periods, Transmission Owners have repeatedly stated
that a “one-size-fits-all†TVMP is not viable or reasonable.
VSLs proposed by the VM SDT
SCE agrees with the SDT's rationale and proposals for VSL Criteria.
Yes
SCE questions the need for including the “Guidelines and Technical
Basis†section within the body of the standard and is also curious as to
the criteria used in developing new Table 3. SCE finds this Draft (4) to be
the best work product thus far, and commends the SDT for its efforts and
continued dedication to crafting a best-in-class standard.
Individual
Marty Berland
Progress Energy
No
In Applicability Section 4.4, “active transmission line ROW†is not
capitalized indicating it is not a defined term, but Footnote 2 is effectively
a definition for active transmission line ROW. However, in the first
paragraph of Section 5 Background, Active Transmission Line Right-of-Way
is capitalized indicating it’s a defined term. It would seem cleaner to
make “Active Transmission Line Right of Way†a formal NERC
definition. Alternatively and at a minimum, Footnote 2 should be revised to
say “An active transmission line ROW is a strip or corridor…†and
also in Section 5 Background, “Active Transmission Line Right of
Way†should be changed to no longer be capitalized.
Yes
Yes
Yes
Yes
Yes
1) On p. 3 of the redline, the table of Effective Dates is struck out, but the
key (listed as 1, 2, 3 below the table: “1. First calendar day…â€)
remains but now the numbers 1, 2, and 3 no longer refer to the table of
Effective Dates as the table has been struck. 2) The first paragraph under
“Exceptions†could be reworded to be clearer. As currently
proposed, it states lines below 200kV become subject to the standard 12
months after the lines are designated as being subject to the standard,
which is somewhat circular. We propose instead: “A line operated
below 200kV becomes subject to this standard 12 months after the date
the Planning Coordinator or WECC initially designates the line as an
element of an IROL or as a Major WECC transfer path.†3) Applicability
Section 4.2.4 says the standard does not apply to Facilities located in the
fenced area of a switchyard. However, p. 8 in Section 5 Background says
the standard does not apply to underground or submarine lines or line
sections inside a station boundary. Two things should be addressed to
make these consistent: “Facilities†is a NERC-defined term that
includes more than just lines, and includes lines, generators,
compensators, transformers, etc. Also, is the “station boundaryâ€
always defined by the fenced area? Any potential conflict due to this
inconsistency should be resolved. 4) In the redline of Draft 4, in R5 and
M5, the word “interim†is struck through. However, the Rationale
box says “….the intent is for the Transmission Owner to put interim
measures in place…†The use of “interim†should be consistent
between R5, M5 and the Rationale box. 5) R6 requires the TO to perform
Vegetation Inspections “at least once per calendar yearâ€. There
could potentially be future interpretation requests that question whether
“once per calendar year†means performance sometime during each
year (i.e. 2010, 2011, etc.), or whether no more than 365 calendar days
can elapse between inspections. The first interpretation could allow up to
almost 2 years to elapse between inspections even when doing it “once
per calendar yearâ€. This should be clarified.
Individual
John Bee
Exelon
No
The term “Centerline of the Circuit†in Table 3 is not defined. Until it
is defined, there is no way to know if the standard is technically reasonable
or whether existing circuits would be in violation of the standard and
unable to operate. In addition, it is unclear what types of construction and
span lengths were used to develop the distances for active right-of-way
widths in Table 3. Furthermore, it is not clear whether Table 3 contains
requirements against which compliance will be measured or best practice
guidelines. Footnote 2, in the background section, compounds this
ambiguity. In short, the lack of a definition for “Centerlineâ€
combined with Footnote 2 and Table 3 make this draft unclear and
unenforceable. Exelon does not necessarily have easement widths for all
transmission lines that equal those defined in Table 3 of this draft; This
may require the acquisition of additional easements, if even possible.
Yes
Yes
Yes
Yes
Draft 4 version of R1/R2
VSLs proposed by the VM SDT
No
Individual
Hugh Conley
Alleghney Power
No
Allegheny Power strongly disagrees with the numbers or widths stated
within Table 3. These numbers seem arbitrary and have no accompanying
reasonable explanation as to their origin, basis, or other criteria noting the
rationale for inclusion in this standard. This inclusion effectively prohibits a
TO from establishing corridor widths less than the widths (which may be
easily possible by utilizing various tower or structures heights or
configurations) stated in Table 3 without placing the TO in extreme
jeopardy of non-compliance issues from a falling off-corridor tree, during
minor storm conditions as an example. Furthermore, this Table insinuates
the TO has no ability to successfully manage vegetation WITH NO
RESULTING OUTAGES or encroachments within the MVCD from off-corridor
trees where corridors are less that the widths stated in Table 3. Allegheny
Power suggests that the definition of the “Active Transmission line
Right Of Way†be “the transmission line ROW corridor that is
actively maintained as part of the entity's vegetation management plan.".
Yes
Yes
Yes
Yes
Alternate version of R1/R2
Allegheny Power prefers the alternate version.
VSLs proposed by the VM SDT
No
Individual
Edward Davis
Entergy Services
No
This is very unclear, and creates much uncertainty as to how certain
potential outage situations should be reported. Clarification language
should be added within the Standard to help define and guide the TO's
actions when an outage occurs from a location at a point that is less than
the documented ROW boundaries (Easements) but greater than the ROW
distances represented in Table 3. It is unclear which distance should guide
our reporting actions……..ROW Document Width, Table 3 ROW Widths,
or the lesser of the two……. See scenarios / examples below for
consideration to aid with clarification points: Example 1: If our
documented ROW width for a 500kV line is 100' from centerline (200' total
ROW width) and we have a fall in from 90' from centerline, do we report
this as a Category 2 Outage due to the fact that it fell from within our ROW
limits, or is it non-reportable due to the fact that it is located at a greater
distance than 87.5' from the centerline of the ROW as listed in Table 3 in
the Standard? Example 2: How does maintenance and outage reporting
correlate with the example defined as follows…….You have a 230 kV
line situated on one side of a 150' wide ROW that was initially cleared to a
width that would accommodate 2 separate parallel transmission lines and
structures. The second set of lines/structures have not yet been
constructed, and the current Transmission line is situated on one side of
the 150' ROW, and is being maintained to the edge of the actual ROW on
the side of the ROW that it was constructed on (maintained to a distance
of 50' from centerline that puts it at the legal edge of the ROW), but it has
been typically maintained to a distance of approximately 60' from
centerline to the inside portion/other side of the ROW (the side of the ROW
that has never been cleared), but a tree falls into the line from approx 58'
from centerline (2' within the 60' distance typically being maintained on
that line)…….would this be considered a Category 2 outage since it was
approx 2' within the average width being maintained on that side of the
ROW or would it not be reported due to the fact that it was located at a
distance greater than 50' as indicated in Table 3??
Yes
Yes
We agree, IF the determination is made by a Qualified Person to have
been caused by vegetation breaking the MVCD (if not breaking MVCD in
real time when observed) based on close observation/inspection and hard
evidence that a Flashover occurred, and that there is no evidence that the
issues spotted on the tree were caused by environmental or biological
symptoms or stressors of the tree in question. Hard evidence has to be
present to classify the item as a vegetation outage if the tree is not within
MVCD when the real time observation is made…..an assumption cannot
be made that vegetation was the cause of an outage if the tree is situated
at a distance that is greater than MVCD when observed unless there is
hard evidence supporting the flashover as determined by a qualified
person.
Yes
Yes
Draft 4 version of R1/R2
Draft 4 is acceptable, but if alternate language is chosen, it should be
similar to option E, keeping the determination simple and with as few
variables for interpretation as necessary.
VSLs proposed by the VM SDT
This gives the option to activate and follow the Imminent Threat Process if
a breach of the MVCD is located and reported for isolated events absent a
sustained outage. It gives the TO the opportunity to mitigate the issue
when it is identified and corected prior to experiencing an outage..
Yes
ITEMS of concern listed below: ITEM 1: Page 13 of the Standard Draft 4
under Add'l Compliance Information - Periodic Data Submittal……Clarify
if Immediate Reporting is expected for outages in Outage Categories 1A,
1B, 2, or 4……..or if Quarterly Reporting is all that is expected. It does
not specifically say that IMMEDIATE Reporting is Required for any outage
type. It is assumed that IMMEDIATE reporting is required for some
outages, but is unclear. ITEM 2: Agree that text boxes being used for
additional clarity is a benefit if used in a correct and clear manner, but it
needs to be specifically stated in the document that the text boxes are to
be used for reference only, we will not be required to specifically follow the
language in the rationale, and that and each utility should specify their
own exact process for addressing each Requirement. ITEM 3: Language
should be added to the Guideline and Technical Basis Section to clarify or
re-state that this section that this section is for assisting entities in
understanding how to comply with the standard but does not contain
mandatory actions/activities. ITEM 4: Please clarify defining factors that
constitute "wind shear or fresh gale" as referenced in Section 4.4 Other.
This is a very unclear interpretation and will most likely be interpreted
differently by all involved if not specified.
Individual
Jon Kapitz
Xcel Energy
No
We believe Active Transmission ROW should be a defined term, not buried
in a “footnote†of the “Other†section of a Standard. It still
begs the question – what is an “active transmission facility�
Regarding the substance, overall we believe that the Active Transmission
ROW should not include the new reference to Table 3. This newly added
sentence in footnote 2, referencing Table 3, is confusing to interpret. If
retained, please rephrase to make it clearer that a Transmission Owner
never has to increase the size of its easement/land right to satisfy this
table. As drafted, our team had various interpretations and it is unclear
whether the intent is that a Transmission Owner has to increase its
easement or acquire land to meet this requirement, or conversely if the
easement is well beyond the values in Table 3, the Transmission Owner
has to maintain that the entire easement or only the values in Table 3.
“Active Transmission Right of Way†is still used in the first
paragraph of the Background section. In total, we suggest that the
definition of Activate Transmission ROW return to the version used in the
prior draft and be placed in the definition section.
No
Xcel Energy urges the retention of the word "reasonable" as a modifier to
"control" in Introduction, Section 4.4. The concept that a Transmission
Owner should exercise reasonable control is sensible, and is of some aid in
countering claims that any incident could be prevented. For example, in
Colorado, the transmission of electricity has been judicially found to be
subject to the highest degree of care. Without the inclusion of the word
"reasonable," Xcel Energy could possibly be faced with a claim that for the
exceptions set forth in Introduction, Section 4.4, to apply, the
circumstances would have to be "beyond the control (using the highest
degree of care) of Xcel Energy." Retention of "reasonable" helps counter
such claims. Since this section appears to lean toward legal language, the
use of the term “reasonable†is better suited for the goal of this
section.
No comments/no position
No
R3 requires the Transmission Owner to have a documented process that
shall contain certain items. Please bulletize these items for clarity.
Additionally, the measure for this requirement indicates that the process
document elements ‘prevent’ encroachment. It is presumed that
the elements identified in the requirement are what need to be addressed
in order to minimize the likelihood of encroachment. Essentially, M3 should
be reworded to state “The procedures, processes, or specifications
provided incorporate the elements identified in R3 (dynamics of a
transmission line conductor’s…)
No
What exactly does complete an annual work plan mean? It infers that an
annual work plan must be developed/documented and executed. If this is
the case, then clearly state as such. In general, R6 & R7 go against the
grain of the results based standard concept. R1 already established that
the Transmission Owner cannot have encroachment. R3 requires annual
inspection (essentially establishing the plan). Why replicate in R6 & R7, it
does not seem to serve any useful purpose.
Draft 4 version of R1/R2
Any of the alternate versions would amplify or create issues between land
owners and Transmission Owners and are contrary to concepts of
Integrated Vegetation Management, in particular, best management
practices.
VSLs proposed by the VM SDT
Yes
R1 & R2 states that “types of encroachments include:†– is the
way this is worded intended to imply there can be other types of
encroachments that are not listed? If not, then rephrase the leading
sentence to be definitive and indicate that the types are the only
categories to be considered. We suggest that the wording from the prior
draft, i.e., “ . . . limited toâ€. MCVD should be a defined term in the
glossary, not in a “Rationale†box. R1 “1†should Real-time
be capitalized to reflect the glossary definition? The term is used as
“real timeâ€, “Real time†and “Real Time†throughout
the standard. This seems to be just a drafting issue, but the same term
should be used consistently. Need to establish somewhere that the entity
defines what constitutes a “qualified†person. Further, some
portions of the standard use the term “qualified person†(e.g., see
M1) and others reference “qualified field personnel†(e.g., see the
Rational Box near M3). It seems that all references should be to
“qualified field personnel.†R1 & R2 are duplicative. It appears the
only reason for the separation is so that different VRFs can be assigned.
Why not just have 1 requirement and indicate that the VRF is High for one
set of lines and Med for others? In general, the “Rationale†boxes
force the requirement language into a difficult to read format. R5/M5 –
the measures identified do not constitute “corrective actionsâ€, they
merely identify documentation that work was attempted. Corrective
actions should be “actionsâ€, such as establish an increased
monitoring plan, re-rating of the line, removal from service, etc. R6 –
Xcel Energy still believes the requirement in R6 that mandates an annual
inspection is too onerous and is at odds with the results-based approach of
these revisions. Xcel Energy urges the retention of the provision in the
existing standard that allows the Transmission Owner to set the frequency
of inspection. In some areas of the country, annual inspections may not be
adequate. Yet in other areas, a longer inspection frequency may be
perfectly reasonable and practical. Our point is that inspection frequency
should not be treated as if it were “one size fits allâ€. If treated this
way, we feel this could pose a risk to reliability and is not likely to be costeffective. The Transmission Owner should be allowed some flexibility.
However, if the drafting team disagrees and determines that an annual
inspection is to be mandated, Xcel Energy believes that an exception to
the annual inspection is appropriate when a non-subjective advanced
technology such as LIDAR is utilized to achieve actual clearance distances.
This places the Transmission Owner in a situation where it can rationally
determine that the objectively measured distances result in a situation
where an inspection need not be performed within the next year. It is
suggested that R6 be revised to read as follows: Each Transmission Owner
shall perform a Vegetation Inspection of all applicable transmission lines at
least once per calendar year, unless the Transmission Owner, based on a
non-subjective advanced technology, such as LIDAR, determines that a
longer inspection period is appropriate. The Effective Dates section is
confusing – exactly when would this standard be in effect? It lists 3
approvals…do all three have to be met or just one? The reference to
Major WECC transfer paths in the requirements introduces a weak
element. The WECC major path designation and elements that comprise
those paths should be controlled through a robust process and easily
available to WECC members. Currently, there are some concerns around
that process in general. NERC’s concerns regarding reporting
vegetation related outages within 48 hours should be addressed or
clarified in the Compliance section. (i.e., incorporate or indicate that this
supersedes that recommendation). Ref: Public Notice - NERC Compliance
Process #2008 – 001
Individual
Gordon Rawlings
BC Hydro
No
The footnote definition is ok but Table 3 is poorly developed. The voltage
classes should be better segregated (e.g. nominal voltage 69kV, 138kV,
230kV, 287kV, 345kV, 500kV, 765kV) along with distances in feet and
metres as Canadian utilities are metric. Also the table should include
recommended right of way widths for single circuits. The assumption made
in the footnote is that the legal easement is larger than in Table 3.
However, as currently defined, some of the distances in Table 3 exceed
statutory rights of way at our utility and exceed engineering standards as
defined by the Canadian Standards Association – Overhead Systems
(CAN/CSA C22.3 No. 1-6). Also, clearances will very much depend on line
design (e.g. structure architecture such as flat, Post T, H-frame, steel
lattice, and other variables such as ruling span length, conductor type
used, etc.) To some degree this will vary quite a bit between utilities. As
such Table 3 as currently presented is not workable.
Yes
Yes but there should be more commentary around exceptions. You should
get away from certain descriptive terms and be more empirical when you
can to avoid ambiguity. For example “Fresh Gale†on the Beaufort
Scale is not common as there are several variants to this scale and on
some scales is defined as “Galeâ€. So do you mean winds of 39-46
mph (62-74 kmh) or greater wind speed? If so, why not state that?
No
Overall, the definition of these measures is improved over draft 3.
However, the standard should better define who a “qualified
person†is and who has the authority to make attestations. R1 and R2
could be better defined relative to the standard definitions in section 4.2 as
to what voltage levels in R2 are part of the standard and what is excluded.
That is: R1 is any circuit that is an element of an IROL or WECC transfer
path regardless of the transmission voltage. R2 is any circuit >200kV
which is not an element of an IROL or WECC transfer path. Lower voltage
circuits that do not fit the R1 definition are not part of this standard.
Yes
As a competency requirement, R3 seems to be missing any requirement
for a utility to define who is qualified to develop these plans, which is a
departure from FAC-003-1 R1.3. I think that the utility should in their
standards define who is qualified to develop their transmission vegetation
management program
Yes
The requirement as currently worded, seems to assume but does not
explicitly state that a utility must prepare and document an annual
vegetation work plan and document in some manner any modifications to
that work plan as they occur. The work plan change documentation should
include any risks of work deferral and mitigation plans to address those
risks if there are any.
Draft 4 version of R1/R2
The alternatives above are too prescriptive. A utility should set a preferred
maintenance distance (i.e. clearance 1 in FAC-003-1) as routine
expectation and outline mitigation strategies as required in areas where
clearance 1 distances cannot be met to ensure that MVCD distances are
not encroached upon. Given the various line design standards, it is the
utility that must define those clearances and margins of error based on
engineering standards and the types of vegetation and growth rates
present in their operating area.
VSLs proposed by the VM SDT
The NERC staff recommendation is too restrictive and does not seem
realistic in an operational sense. We do not agree that the standard should
apply to outages from vegetation falling into the conductor from within the
active transmission right of way. This normally would not occur except
during storm events that would be excluded from this standard. It is
operationally difficult to know precisely where the edge of the right of way
is in all situations and under all conditions. Further, in clearing some
sections to this degree, the utility could end up destabilizing what is
currently a stable, windfirm edge and pose higher security risks to the
transmission system from destabilizing the vegetation through excessive
clearing. So this gets down to semantics of how a utility might define their
active right of way corridor relative to the legal statutory right of way
edge. The risk of fall into outages needs to be managed but as currently
defined this is too absolute a requirement. Fall-into outage risks need to
be mitigated but they have not been a key element of any cascading
failure and are hard to prevent. Even if a right of way were cleared
sufficiently wide to avoid a fall-into outage, there is always a risk of
branches being blown into the conductors from sailing during higher winds
(e.g. Douglas-fir branches have excellent airborne gliding abilities). The
greatest risk is from grow-into outages or from conductors and vegetation
being blown into one another within the active right of way. Therefore, we
prefer the VSLs set by the VM standard development team.
Yes
R4 – There will likely be issues of definition over what constitutes an
“intentional delay†in notification. The time for reasonable reporting
needs to be quantified. The standard references Tables 2 and 3 but there
is no Table 1 in the document. This is confusing and should be
renumbered. This is likely a carry over from an earlier draft where a Table
1 has been renamed or dropped. As noted earlier in Q1, table 3 is poorly
developed and should be revisited. How does one objectively measure
compliance to MVCD distances? Use of LiDAR technology, laser
rangefinders, etc. should be used and evidence of potential violations
should be empirical and not based solely on subjective observations, even
if they are performed by “qualified personnelâ€. The technical
document should include a glossary of all the acronyms used throughout
the document as it has some excessive jargon and does not always read
smoothly, especially compared to FAC-003-1. The use of explanation
boxes is helpful.
Group
Bonneville Power Administration
Denise Koehn
Yes
This distance is reasonable in the table, but due to widely varying designs
of structures it does not give a relationship of the outside wire to edge of
ROW. It should be noted as outside wire, phase or conductor to edge of
ROW. In addition, the effective date should allow transmission owners time
to achieve this distance, perhaps one cycle.
Yes
Yes
Yes
Yes
Alternate version of R1/R2
VSLs proposed by the VM SDT
Yes
The basis of managing vegetation to MVCD in Table 2 (essentially
withstand distances) will likely prove problematic. BPA believes NERC
should develop an additional table that calls out minimum "buffers" based
on attributes such as line voltage, line rating etc. This table should be a
companion to Table 2. It is NERC's responsibility to regulate and we
believe that they should do so. In this case, the loss of flexibility for the
owners is not necessarily a bad thing.
Group
Arizona Public Service Company
Jana Van Ness, Director Regulatory Compliance
No
These clearances could exceed the permitted ROW’s on federal lands
and the utility has no legal right to clear beyond those rights. In some
cases the permitted ROW can exceed those distance and federal agencies
could not allow you to clear beyond those clearances in this version.
Yes
No
Do not agree with real-time observation. Utility can use technology to
determine all rated conditions if a tree related outage occurred.
No
Still lacks detailed information. SDT needs to specify the documentation it
is left up to interpretation by the utility.
Yes
Neither version is acceptable ANSI-A300 part 7 should be included here.
Having set distances will give federal agencies the ability to minimize a
utilities TVMP.
VSLs proposed by NERC staff
Requires a higher degree of accountability as it should be.
Yes
Qualifications needs to be put back in the standard. There needs to be a
clearance 1 requirement.
Group
Western Electricity Coordinating Council
Steve Rueckert
Yes
Yes
however the statement of acceptable forms of evidence implies that a
dated attestation alone could provide evidence of compliance. An
attestation alone would not represent sufficient evidence to support a
conclusion of compliance with encroachment limits only of the absence of
an outage.
Yes
Yes
annual vegetation management plans must have some flexibility. If the TO
has the authority to create the plan they should have the authority to
modify the plan. The key point is that changes, particularly delays to
planned work would have to be approved. Do not believe “decreases in
funding†should be listed as a valid reason for modification of work plan
related to a reliability standard. From an enforcement viewpoint, there is
ambiguity or perceived ambiguity in “provided they do not put the
transmission system at risk of a vegetation encroachment.†Provided
the potential that there may never be a self-report addressing this
violation.
Draft 4 version of R1/R2
Draft 4 should be sufficient. If industry believes MVCD is not adequate
then the tables for MVCD should be modified to account for sag and sway.
No
Individual
Bill Rees
BGE Forestry Management
Yes
No
Suggest including in “4.4. Other†a phrase referencing government
interference, such as “Federal, State or other regulatory interference,
including legal or other legislative actions, that prevents performance to
comply with this reliability standard.â€
No
M1 & M2 bullet: “Real-time observation of any MVCD
encroachments.†implies that real-time observation of vegetation
encroachment ensures reliable operation the Bulk Electric System. The
reliability standard objective states; “To improve the reliability of the
electric Transmission system by preventing those vegetation related
outages that could lead to Cascading.†However, real time observation
of current operating conditions provides no assurance that vegetation will
not lead to outages. BGE recommends removing the language. If an
inspector finds vegetation encroaching into the MVCD during a visual
inspection he / she should immediately initiate an Immediate Threat
Notification. Therefore, this measure has no value.
Yes
Yes
Alternate version of R1/R2
BGE believes R1/R2 should contain language that ensures that vegetation
is manage taking into account sag and sway throughout the conductors
operating range as the alternate language above outlines. The six options
proposed allows the Transmission Owner the flexability needed to manage
the active ROW a varity of ways and at the same time ensures the reliable
operation the Bulk Electric System with respect to vegetation.
VSLs proposed by the VM SDT
Yes
4.2.4 States that the Standard is not applicable to “…to Facilities ….
located inside the fenced area of a switchyard, station or substationâ€.
This implies that anything within the fenced area of a switchyard,
substation or power plant does not fall within the jurisdiction of FAC-0032. Some fenced in areas could be very large and susceptible to vegetation
encroachments issues. Suggest reference to “inside the fence†be
removed. Disagree with R6. – Inspection Frequency. Very prescriptive.
Please consider allowing TO’s to select an annual frequency that best
fits their requirements, such as calendar year, every growing season,
every non-growing season, etc. BGE currently defines their inspection
frequency as annually during the non-growing season, October 1 to May 1.
BGE believes inspecting during the dormant season is a best practice due
to the ability of the inspector to identify vegetation defects, especially off
the ROW, which could be hidden during the growing season due to foliage,
canopy cover, etc. Also, if a utility elects to leverage an advance
technology, such as LiDAR, it provides the most effective results when
LiDAR is utilize during the growing season, therefore allowing the results of
the advance technology to enhance the fall to spring inspection cycle.
Table 1 – Time Horizons, Violation Risk Factors, and Violation Severity
Levels The VSL’s for R7 all include “the Transmission Owner failed
to complete…..% of its annual work plan (including modifications if
any)â€. This is not clear to BGE. R7. allows plans to be modified due to
changing conditions, for example ROW maintenance could be deferred to
the following year due to mutual assistance agreements if the deferment
does not violate the encroachment within the MVCD. The VSL implies this
is a violation since the “modification†deferred a certain percentage
of the planned worked to the following year, therefore 100% of the
planned worked wasn’t completed. If the modification was excluded,
than 100% of the planned work would have been completed.
Individual
Michael R. Lombardi
Northeast Utilities
No
The use of a minimum distance from the centerline of the circuit or
structure is an incorrect measure to use for a set clearance distance of the
active transmission right-of-way. Consideration should be given for the
type of construction as different construction types (H-Frame, Lattice
towers, Monopole delta or vertical construction) will require different
widths of a cleared right-of-way to provide the necessary openings for
these circuits. A minimum distance for 345-kV is now set at 150 feet based
on the minimum distances from centerline. This may be correct for certain
H-Frame and Lattice Tower configurations but it is excessive for monopole
situations. A single pole configuration with vertically aligned conductors
does not need this full 150 foot width. It is strongly recommended that a
minimum distance from conductor be used in place of a set distance from
centerline. As long as there is at least 30 - 40 feet of clearance in the
right-of-way from the outermost conductors (adjusted to account for
maximum sway at mid-span for longer spans), then this is the distance
that should be used to develop the right-of-way widths. For example, a
monopole structure with vertically aligned conductors would result in a
cleared active right-of-way width of only 80 feet (40 feet from conductor
to edge of cleared active right-of-way) using the minimum distances from
the conductors. There is no need to extend this distance another 35 feet
(on each side) in order to obtain the full 150 foot width. This requirement
is excessive and must be adjusted to account for line construction
variations. Instead of using the term "Centerline" as referenced on Table
3, the use of "outer phase" or "phase closest to tree line" would be more
appropriate.
Yes
Yes
Yes
Yes
Alternate version of R1/R2
Option E above is preferred as it allows for variations based on differences
in conductor heights, topography and other situations where a set height is
not necessarily required in all instances and allows for the utility to
determine the maximum heights of vegetation without performing detailed
calculations of what the maximum heights must be along the various
distances within each conductor span. If the utility is tasked with
managing the vegetation to ensure no encroachments into the MVCD then
it should be up to the individual utility how best to determine its
management strategies that incorporate the determination of maximum
vegetation heights in each section on its system.
VSLs proposed by the VM SDT
No
Group
Tampa Electric Company
Luke Diruzza
No
We have concern with the “Minimum Distances†as listed in Table 3.
What analytical methodology, criteria and rationale was utilized to
determine each recommended distance? In addition, we have concerns
regarding the change to a pre-determined distance. This seems to be a
major shift from the vegetation to conductor methodology employed
previously and throughout this standard? NERC/FERC must recognize that
while protecting and securing grid reliability, each utility must also balance
the environmental, political, customer and economic issues and impacts
which will occur with the implementation of the Table 3 clearances. We
question whether this is the most responsible action to take given the
current state of the economy as well as the environmental and political
sensitivity impacts which will result. Tampa Electric questions whether
Table 3 will improve System reliability. Since the inception of standard
FAC-003-1 Tampa Electric has not had a Category 1 or Category 2 outage
on our 230kV Transmission System. We don’t believe that the changes
proposed to table 3 will improve overall service reliability. It is Tampa
Electric’s opinion that each utility should define the width of its own
Active Transmission line ROW. However, if such a table is to be utilized,
Tampa Electric recommends the following changes or adjustments to Table
3. 1. Expand the table to account for the various types of Transmission
construction; i.e. vertical versus horizontal conductor configurations. 2.
Use a distance from the outermost conductor, not the centerline. This will
account for construction type and better achieve a consistent clearance
from conductors. 3. We recommend reducing the distances in Table 3 by
12.5 feet for each voltage category. 4. Specify whether the voltage is
based upon the design or operating voltage. 5. Reformat the voltage
ranges to 100kV - 200kV, 200kV – 300kV, 300kV – 400kV, etc. as an
example; this would create a more appropriate range of voltages and
clearance distances. The reformatted voltage ranges eliminate confusion.
For example, under the current proposal it is unclear in which category a
nominal 230kV line should be since sometimes such a line can operate at
up to 232kV during low-load conditions.
Yes
These changes add improved clarity and defintion to this section.
Yes
These changes allow for qualified review of field findings.
Yes
This better clarifies section R3
Yes
These changes add greater clarity, as well as real world examples, to this
standard.
Draft 4 version of R1/R2
Quite frankly, the alternatives listed above, or for that matter any other
vegetation managment options, should be establised by the utility. The
goals in R1 & R2 are very clear. The alternatives listed above will create a
double or triple standard of vegetation clearance for each different type of
Transmission construction.
VSLs proposed by the VM SDT
Tampa Electric agrees with the SDT statement … “For example, not
all encroachments lead to Sustained Outages.†As such, we agree, a
lower level of VSL is appropriate. Tampa Electric also agrees with this
statement “ Moreover, there is an operational differentiation between a
fall-in, blow-together or grow-in event. “ Recommend the team
examine the analytical rational for the following statements so as to better
explain and clarify this issue to NERC. “A fall-in has never been known
to cause a cascading outage. Therefore the team feels that a Lower VSL is
appropriate. A blowing-together-caused fault is somewhat more egregious
than a fall-in, as it has the potential for re-occurring and is therefore
assigned a Higher VSL.â€
No
No additional comments
Group
Corporate Compliance
Silvia Parada Mitchell
No
Although there is support for making Active Transmission Line Right of
Way a clearly defined term, and the foundation for compliance with FAC003-2, the distances in the table are arbitrary and are not supported by
any scientific or engineering analysis. It is possible that such a table could
be interpreted to define the minimum width of future lines. Different
construction configurations require different ROW widths.
Yes
No
The measure is adding to the requirement. The measure should define how
a requirement is met and not interpret or add to the requirement,
otherwise this will add to confusion, instead of clarity, which should be the
goal of any revised reliability Standard. Also, the measure implies that a
fault investigation must be done. As written, momentary outages are
included, and a fault investigation should not be required for momentary
outage. It also places the same weight of violation on a momentary outage
as it does a Sustained outage, which appears on its face not to appropriate
nor necessary to meet the goal of FAC-003-2. In addition, an outage
investigation is not a finite process that produces identical homogenous
results every time. Of particular concern is the possibility that should a
Transmission Owner have one or more momentary outages and not find
the cause, then later have another outage (Sustained or Momentary), such
a finding appears to lead to a multiple violation. This is inconsistent with
focusing requirements on reliability risks to the bulk electric system.
Yes
Yes
Draft 4 version of R1/R2
The alternative is a fill in the blanks requirement.
VSLs proposed by NERC staff
Again the drafting team is trying to control the terms of a requirement by
using the compliance elements. FPL agrees there is a direct link between
vegetation growing in to conductors from below has a direct correlation to
cascading events and fall-in and blow-in outages are no more incidental
than a cross arm failure to a cascading event. These components should
be handled in the requirements and not in the compliance element.
Yes
R5 as written is vague. It leads to confusion in interpretation. FPL
recommends the following wording. R5. The Transmission Owner shall
certify each corridor or line section that it meets the standards it set forth
under R3 until the next planned management cycle when it is completed.
If a location in known to not meet the criteria defined under R3, a
mitigation plan must be in place to prevent a violation of R1 or R2. R1 and
R2 are too inclusive. They equate vegetation growing in to conductors
from below the same as vegetation falling or blowing into the conductors
from within the Active ROW. There is no evidence that a cascading event
has ever been caused by the latter two events. This standard should
concentrate on vegetation growing from below the conductor. Suggested
wording of R1 and R2 is as follows. R1. Each Transmission Owner shall
manage vegetation to prevent encroachment into the Minimum Vegetation
Clearance Distance (MVCD) as shown in Table 2 from within the active
ROW on of any line identified as an element of an Interconnection
Reliability Operating Limit (IROL) or Major Western Electricity Coordinating
Council (WECC) transfer path (operating within Rating and Rated Electrical
Operating Conditions). Encroachments are determined by: 1. An
encroachment, observed in real time, 4. An encroachment due to a growin from below the conductor in the active ROW that caused a Fault. R1.
Each Transmission Owner shall manage vegetation to prevent
encroachment into the Minimum Vegetation Clearance Distance (MVCD) as
shown in Table 2 from within the active ROW on of any line that is not an
element of an Interconnection Reliability Operating Limit (IROL) or Major
Western Electricity Coordinating Council (WECC) transfer path (operating
within Rating and Rated Electrical Operating Conditions). Encroachments
are determined by: 1. An encroachment, observed in real time, 4. An
encroachment due to a grow-in from below the conductor in the active
ROW that caused a Fault.
Individual
Bryan Taylor
Idaho Power
Yes
I support the description for the active right of way. However, I believe
there needs to be a provision that addresses identifying potential hazards
outside the active right of ways that may pose a risk to the transmission
lines.
Yes
This will allow the utilities to address conditions that are within their
control.
Yes
Yes
Yes
Alternate version of R1/R2
Alternative R1/R2 allows the utility to maintain adequate clearances with
their preferred approach.
VSLs proposed by NERC staff
Seems like there should be a lesser severity level for violations for R3-R7.
Yes
I'd like to see language or NERC support to encourage federal agencies to
expedite vegetation management maintenance requests and minimize the
barriers to perform work on federal lands.
Individual
Anne Beard
PNM
No
ROW easements vary according to land ownership therefore, potentially
subjecting the utility to be liable for land outside of easement/ROW.
Yes
No
Needs a definition of Real Time Observations
Yes
Yes
Alternate version of R1/R2
VSLs proposed by the VM SDT
The expectation is for perfection or zero encroachments at all times. It
would be cost prohibitive to maintain the system under those rules. PNM
recommends the VM SDT VSL’s.
No
Individual
James Sharpe
South Carolina and Gas
Yes
Yes
Yes
Yes
Yes
VSLs proposed by the VM SDT
No
Group
Southern Company Transmission
JT Wood
No
Depending on the intent this may create a problem. We are concerned the
addition of Table 3 could be interpreted to mean something completely
different than what we believe to be its intention. Please consider alternate
wording to Footnote 2: A strip or corridor of land that is occupied by active
transmission facilities. This corridor does not include the parts of the Rightof-Way that are unused or intended for other facilities. However, the active
transmission line ROW cleared width it is not to be less than the width of
the easement itself unless the easement exceeds distances as shown in
Table 3 for various voltage classes. If the SDT determines keeping Table 3
is the appropriate course of action, we recommend clarifying its intent
better; either in a footnote or in the title. Adding a footnote stating the
Table is not applicable if the distance from the center line of the conductor
to the right-of-way edge is less than the appropriate distance indicated in
the table. Another option might be to add a statement to the title such as,
“If the distance from the centerline of the circuit to the edge of the
easement is less than the values in Table 3, that distance is considered
active ROWâ€.
Yes
Yes
Yes
While voting yes we are concerned about the interpretation of the
expanded verbiage, how much documentation will be enough.
No
The first sentence of the Requirement 7 Rationale conflicts with the second
sentence. The R7 Rationale should be reworded as follows: "This
requirement sets the expectation that the work identified in the annual
work plan should be completed as planned. However, an annual vegetation
work plan must allow for work to be modified in response to changing
conditions. These modifications must take into consideration the
anticipated growth of vegetation and all other environmental factors,
provided that the changes do not cause a vegetation encroachment within
the MVCD."
Draft 4 version of R1/R2
We feel the alternative language is too confusing. Does a utility choose one
option from the list and expect it to cover all situations, or can the utility
pick one option from the list and apply that option to one span, and then
another option for the next span. The proposed alternate verbiage makes
no distinction as to when options can or cannot be utilized. The language
in Draft 4 seems to cover the various scenarios a utility will face in its
vegetation management program while giving the utility the flexibility
necessary to address these situations in an appropriate manner.
VSLs proposed by the VM SDT
We support the SDT version of the VSLs. The version proposed by staff
does not recognize the objective of FAC-003-2 which clearly states, “To
improve the reliability of the electric Transmission system by preventing
those outages that could lead to Cascading.†If a fall-in occurs in an
afternoon thunder storm and investigation reveals the tree was on the
right-of-way by one or two feet, staffs VSLs would treat this outage with
the same severity as an outage where a fully loaded line in a heat wave
sagged into unmaintained brush growing directly beneath the conductor.
The first case would rarely, if ever, lead to cascading. The second case
could easily lead to cascading. Staff’s VSLs seem to indicate a desire to
“gold plate’ the system to insure 100% reliability, which will never
be achieved absent of unlimited resources and with total disregard to cost.
Yes
The NERC Glossary of Terms provides a definition for Flashover. The
Rationale boxes for R1 and R2 use the term “spark-overâ€. This is
inconsistent with other references in the Standard. Note that the term
Flashover is used in footnote No.4. Please resolve the inconsistency
between these terms. We are concerned FAC-003-2 is being developed
under a zero tolerance philosophy, while other NERC standards do not
adopt a zero tolerance philosophy. Industry performance under FAC-003-1
indicates the standard is working and that industry is responding to ensure
reliability of the electric Transmission system. We would like to thank the
SDT for the work they have put into developing the proposed draft.
Individual
Greg Rowland
Duke Energy
Yes
However, due to different design attributes of transmission lines, it may be
better to change the distance in Table 3 from a centerline distance to a
“Minimum Full Active Transmission Line ROW Width Distanceâ€.
Yes
No
The last sentence of this modification could be misinterpreted by a
compliance representative to imply that all Faults must be investigated to
eliminate or confirm vegetation as the cause of the fault. There are several
sources (e.g. lightning, wind-blown debris) of Faults and several
appropriate operational responses, some of which may not include field
investigations, depending on the circumstances surrounding each Fault.
Thus, the current wording is gray and should be modified to aid
industry’s understanding and thus to ensure compliance. The
interpretation we suggest may not be obvious, but our experience with
previous interpretations of certain facets of FAC-003-01 would indicate the
need to better define the expectation. A potential modification to the last
sentence of M1/M2 could be: If a later confirmation of a Fault by a
qualified person shows that a vegetation encroachment within the MVCD
has occurred, this shall be considered the equivalent of a Real-time
observation.
Yes
Yes
Draft 4 version of R1/R2
VSLs proposed by the VM SDT
No
Individual
Andrew Z.Pusztai
American Transmission Company
Yes
Yes
Yes
Yes
Yes
Draft 4 version of R1/R2
ATC feels that Draft 4 Version of R1/R2 is the preferred version. The
Alternate version is too prescriptive and has little flexability.
VSLs proposed by the VM SDT
ATC believes the VSLs proposed by the VM SDT best supports the
NERC’s VSL Criteria. The NERC Staff VSLs do not allow for Lower or
Moderate VSLs which recognizes significant value as nearly meeting the
intent of the requirement. Furthermore, it does not allow for encroachment
where absent a sustained outage. Every encroachment in real time would
not go directly to a “High†VSL where performance has limited
value.
Yes
1.) Rationale boxes associated with R1, R2 and R3 within the standard
include reference Tables and Figures in the “Guidelines and Technical
Basis†without specifying where they are located. ATC recommends
inserting this information as applicable. 2.) ATC raises a previous draft
concern on including Rationale Boxes plus Guidelines and Technical Basis
as part of the NERC Reliability Standard. ATC recommends that the SDT
either remove these sections or make them separate from the formal
standard to eliminate any risk that these may be construed as
requirements. An alternative method is to very clearly identify which parts
of the standard are subject to compliance and considered mandatory and
which are not considered requirements and are only for guidance in
meeting the requirements. 3.) ATC believes the Measurements are well
written and provide guidance on acceptable compliance evidence related to
the requirement. 4.) Measurement M2 related to R2 states that outages
related to encroachments have records confirming no Real-Time
observations of any MVCD encroachments. ATC feels this would be hard to
prove as a negative. It could require one to show every single patrol or
inspection has documentation stating no real time encroachments were
observed. 5.) Editorial Comment on Draft SDT VSLs for R2: To clarify the
statements made for the Moderate, High and Severe VSLs. please add the
verbiage, “into the MVCD†after “The TO had an
encroachment…….â€
Group
Hydro One
Sasa Maljukan
No
A DC table for Table 3 similar to the MVCD table should be added. There
should be a statement in Table 3 that is consistent with footnote number 2
stating that the minimum width of the Active Transmission Line ROW is
either the full width of the easement or, if the easement is wider than the
distances in Table 3, the minimum distances must not be less than the
distances shown in the Table. The use of a minimum distance from the
centerline of the circuit or structure is an incorrect measure to use for a
set clearance distance of the active transmission right-of-way. The
description does not take into account vertical versus horizontal design
configuration. Consideration should be given for the type of construction as
different construction types (H-Frame, Lat-tice towers, Monopole delta or
vertical construction) will require different widths of a cleared right-of-way
to provide the necessary openings for these circuits. A minimum distance
for 345-kV is now set at 150 feet based on the minimum distances from
centerline. This may be correct for certain H-Frame and Lattice Tower
configurations but it is excessive for monopole situations. A single pole
configuration with vertically aligned conductors does not need this full 150
foot width. It is strongly recommended that a minimum distance from
conductor be used in place of a set distance from centerline. As long as
there is at least 30 - 40 feet of clearance in the right-of-way from the
outermost conductors (adjusted to account for maximum sway at midspan for longer spans), then this is the distance that should be used to
develop the right-of-way widths. For example, a monopole structure with
vertically aligned conductors would result in a cleared active right-of-way
width of only 80 feet (40 feet from conductor to edge of cleared active
right-of-way) using the minimum distances from the conductors. There is
no need to extend this distance another 35 feet (on each side) in order to
obtain the full 150 foot width. This requirement is excessive and must be
adjusted to account for line construction variations. Instead of using the
term "Centerline" as referenced on Table 3, the use of "outer phase" or
"phase closest to tree line" would be more appropriate. There is published
literature using the term “cleared width†to indicate the distance
from the outer phase to the tree line. This distance should be used in the
Active ROW definition. The word easement is also used in the definition. Is
there a reason the Active ROW only includes easements, not fee
ownership, license or some other right to occupy and manage the ROW?
Would Active ROW include “danger tree rights†on land? These
questions need to be addressed in the standard (in text) and technical
reference document (in graphics).
Yes
No
A clarification for M1 is needed regarding whether entities will have to
attest to the fact that there has never been an encroachment in the MVCD.
Yes
Yes
Alternate version of R1/R2
Alternate Version E would allow a Transmission Owner to use an approach
consistent with the current version of FAC-003 by defining a minimum
clearance distance and a vegetation management clearance distance. This
approach has met the objectives of FAC-003 since 2006. Use of version E
would change the standard from a prescriptive approach to a Transmission
Owner defined approach. In addition, Alternate Version E is preferred as it
allows for variations based on differences in conductor heights, topography
and other situations where a set height is not necessarily required in all
instances and allows for the utility to determine the maximum heights of
vegetation without performing detailed calculations of what the maximum
heights must be along the various distances within each conductor span. If
the utility is tasked with managing the vegetation to ensure no
encroachments into the MVCD then it should be up to the individual utility
how best to determine its management strategies that incorporate the
determination of maximum vegetation heights in each section on its
system.
VSLs proposed by the VM SDT
The wording in the VM STD VSLs should be modified to include whether or
not the TO managed any vegetation on that particular line. A more severe
VSL should be assigned to any encroachment or sustained outage that was
caused as a result of a TO not performing any vegetation management
activities on that line. For example, if vegetation management activities
were completed on 80% or 90% of the line and additional work was in
progress on the remainder of the line, but an encroachment or sustained
outage occurred on the spans that were scheduled to be done as part of
the annual plan, the TO should be held accountable for this but at a lower
severity level.
Yes
Hydro One wants to thank the SDT for the effort that has gone into
developing this proposed revision to FAC-003. Overall the new version is
consistent with FERC Order 693 and will be a straightforward, workable,
and auditable standard. One item requiring clarification and change is the
Active ROW definition. The recent addition of a centerline distance to edge
of Active ROW is not acceptable. In many areas design standards allow a
smaller ROW width with no compromise to “cleared width†or tree
related reliability of the line. The SDT needs to address this issue. In R5,
the phrase 'where a transmission line is put at potential risk due to the
constraint' should be better defined. This is vague and could lead to
inconsistent practices between utilities. All undesirable species on the full
width of the ROW are defined as 'potential risks to the transmission line'
regardless of height or location at the time of vegetation management.
Interim corrective action should only be required when the potential risk is
approaching the imminent threat classification.
Individual
Terry Harbour
MidAmerican Energy
Yes
Yes
No
Examples should be moved to the rationale boxes to avoid confusion on
what is required and what is an example. All rationale boxes should have a
disclaimer to the effect saying "For guidance only, not for enforcement".
No
MidAmerican supports the additional detail the R3 should end after the first
sentence. The additional detail should be moved to the rationale box as
additional guidance.
No
MidAmerican supports the additional detail. However R7 should end after
the first sentence. All additional material should be moved to the rationale
box.
Draft 4 version of R1/R2
VSLs proposed by the VM SDT
Yes
Any references to "observed in real time" should be removed. Vegetation
contacts must be verified and references to real time are inappropriate.
This causes difficulties in proving a negative in real time.
Group
Pepco Holdings, Inc - Affiliates
Richard Kafka
Yes
Yes
Yes
Yes
Yes
Draft 4 version of R1/R2
Neither set is correct. The SDT proposed VSLs do not identify
encroachment into the MVCD of a line not in an IROL or Major WECC
transfer path, and the NERC Staff proposed VSLs do not do not identify
encroachment into the MVCD of a line that is in an IROL or Major WECC
transfer path
No
Group
MRO’s NERC Standards Review Subcommittee (nsrs)
Joseph DePoorter
Yes
The NSRS agrees in whole to the question but has the SDT taken into
consideration the difference in ROW may be different in Urban and Rural
settings?
Yes
The NSRS believes that the new definition provides greater clarity with
respect what does not constitute a compliance violation versus the
previous version.
Yes
No
The NSRS does not believe that the new specificity that has been added to
R3 will improve the reliability of the BES. It is our opinion that the
requirement would have been clearer if it had ended after the first
sentence. The additional language after the first sentence does not
improve clarity. The whole (as written) requirement may be interpreted as
a requirement for “each span†of Transmission line that the
Requirement will be applied to. In measures for other requirements the
SDT has done a very good job of stating and clarifying (in their opinion)
what acceptable forms of evidence are. M3 would benefit from this type of
clarification.
Yes
The NSRS has issue with the word “may†(and its components along
with the associated bulleted points) and recommends that it is removed
and placed in the rational box.
Draft 4 version of R1/R2
It is the NSRS’s opinion that that the requirement as currently written
in version 4 is consistent with the intent of a standard; i.e. stating what is
required as opposed to stating how to achieve what is required.
VSLs proposed by the VM SDT
Yes
1.) The NSRS notices that a previous draft concern on including Rationale
Boxes plus Guidelines and Technical Basis as part of the NERC Reliability
Standard. The NSRS recommends that the SDT either remove these
sections or make them separate from the formal standard to eliminate any
risk that these may be construed as requirements. An alternative method
is to very clearly identify which parts of the standard are subject to
compliance and considered mandatory and which are not considered
requirements and are only for guidance in meeting the requirements. Such
as; State within in the text that this information “Is not subject to
enforcementâ€. 2.) The NSRS believes the Measurements are well
written and provide guidance on acceptable compliance evidence related to
the requirement. 3.) Measurement M2 related to R2 states that outages
related to encroachments have records confirming no Real-Time
observations of any MVCD encroachments. The NSRS feels this would be
hard to prove as a negative. It could require one to show every single
patrol or inspection has documentation stating no real time encroachments
were observed. 4.) Editorial Comment on Draft SDT VSLs for R2: To clarify
the statements made for the Moderate, High and Severe VSLs. please add
the verbiage, “into the MVCD†after “The TO had an
encroachment…….â€
Individual
Claudiu Cadar
GDS Associates
Yes
- ROW abbreviation comes prior to the full term (marked footnote prior to
the full term as stated in 5. Background). Please make correction
accordingly.
Yes
No
- Need to specify who qualifies as “qualified personnel†to observe
the vegetation condition.
No
- We suggest to eliminate / change the word “dynamics†because
can create confusion with regards to the extent of documentation that has
to be prepared. - Requirement should clearly state the criteria as in the
maximum design (rating) or maximum operating conditions
Alternate version of R1/R2
- E) seem more appropriate. The alternate R1/R2 standard requirements
shall reduce the number of possibilities and simplify the criteria towards
the design / operating conditions and additional standards ought to be
considered in concert with current standard.
Criteria will be probably best represented by a mix of the two VSLs as
follows: - Keep the Lower and Moderate VSLs from SDT with both absent
Sustained Outage. Add the fall-in as specific encroachment to the Lower
VSL and grow-in as specific encroachment to the Moderate VSL - Keep the
High / Severe VSLs from NERC
Yes
- Effective Dates. Clarify effective dates in paragraphs 2 and 3. This should
only be applicable to Canada as Standard are not mandatory and
enforceable in the US unless further approved by FERC. - Exceptions.
Regional Differences must be approved just like NERC Standards, further
explanation is required of these exceptions to garner a better
understanding of the intent - Background. The paragraph exemplifying as
a localized customer service may get disrupted if vegetation will make
contact with a 69kV line is not appropriate for the standard while it is
given that this applies to the BES 200kV and above. - Requirement R2.
The paragraph “[…] Sustained Outage of applicable lines that are not
elements […]†should state the voltage threshold of 200kV and above
- Requirement R4. Who qualifies as “qualified personnel†to observe
the vegetation condition? Need clarification. - Requirement R5. Rationale.
Corrective action guidance should be provided within the Requirement. Set
the examples for the Guidelines section. - Guidelines and Technical Basis.
oRequirement R1 and R2. The example meant to prove the point of
“line conductor intentionally or inadvertently operated beyond its
rating†is contradicting the guideline. The emergency actions should
not violate any standards and should not cause an outage. If such thing
happens, the vegetation related outages should be in violation of the
requirements. oRequirement R3. How is every possible combination of
wind speed, loading and conductor properties going to be addressed?
Should a national standard be referenced as a minimum requirement?
More guidance should be provided. oRequirement R5. Wouldn't a violation
have occurred with the encroachment of the vegetation per R2? The
potential to put the transmission system at risk is not well defined and
could be interpreted as encroachment into the area defined by the
appropriate table(s). Need clarification. oRequirement R7. Regarding the
statement “It is only intended to require that the Transmission Owner
provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents
encroachment of vegetation into the MVCD†if no identifier is utilized
how will compliance be gauged? By encroachment? By outage? Need
clarification. oRequirement R7. Regarding the evidence of annual work
plan execution, when would the change in plan need to be documented?
Has this moved away from requiring the documentation of plan change at
the time of occurrence? Need clarification.
Individual
Joe Knight
Great River Energy
Yes
Yes
GRE believes that the new definition provides greater clarity with respect
what does not constitute a compliance violation versus the previous
version.
Yes
GRE agrees with the revisions made to this standard since the last posting
and requests clarification on what constitutes a qualified person.
No
GRE does not believe that the new specificity that has been added to R3
will improve the reliability of the BES. It is our opinion that the
requirement would have been clearer if it had ended after the first
sentence. The additional language after the first sentence does not
improve clarity. In measures for other requirements the SDT has done a
very good job of stating and clarifying (in their opinion) what acceptable
forms of evidence are. M3 would benefit from this type of clarification.
Yes
Draft 4 version of R1/R2
VSLs proposed by the VM SDT
GRE prefers the Drafting Team’s VSLs over the VSLs written by the
NERC staff. The VSLs that were written by the SDT appear to be clearer
and less subjective as opposed to the VSLs that were written by NERC
staff. The VSLs written by the NERC staff came across as being less clear
and more subjective.
Individual
Kirit Shah
Ameren
No
Does this mean wider ROW easements will need to be acquired to be
compliant or will this apply to ROW’s for new circuits going forward?
Yes
Yes
Yes
No
Funding Adjustments (increase or decrease) – need more description to
imply only when planned vegetation work is “over and aboveâ€.
Draft 4 version of R1/R2
VSLs proposed by the VM SDT
Yes
Funding Adjustments (increase or decrease) – need more description to
imply only when planned vegetation work is “over and aboveâ€.
Individual
Earl V. Burnside
PPL Electric Utilities
No
Centerline (CL) distances shown in Table 3 are shown as Minimal distances
from CL. If utility is not able to define its ultimate ROW, due to CL
agreement or other circumstances, these minimal distances may not be
applicable and as such could result in non-compliance as written.
Yes
No
As written M1 requires evaluation of condition by “qualified personâ€
but no definition of qualified person given. Should be more direct and point
to physical evidence of vegetation encroachment into MVCD, i.e. burned
vegetation.
No
As written, R3 now requires documentation of conductor dynamics as
related to ratings and rated operational conditions. Not clear how this
information is to be presented and documented and how vegetation
conditions that exist are to be documented to provide evidence that
management processes and procedures are adequate to prevent
encroachment into MCVD.
Yes
Alternate version of R1/R2
Alternate C provides assurances that growth rates, maintenance cycle, and
max-sag are taken into consideration.
VSLs proposed by the VM SDT
No
Individual
Jianmei Chai
Consumers Energy Company
No
Table 3 does not adequately address ROW width requirements based on
the type of construction used for structures, especially for the two lower
voltage classes, 69-138kV and 139-230 kV. Lines constructed on H-Frame
structures have a much wider footprint across the ROW than do single pole
construction and most steel tower construction types. The minimum ROW
width listed in Table 3 for a 138 kV line constructed on a wooden H-Frame
may put the outside conductor within MVCD under windy conditions due to
wind displacement of conductors and trees. Consumers Energy
recommends that Table 3 be modified to describe the minimum distance in
the table is the vertical plane of the outside conductor to the edge of the
active transmission ROW and therefore independent of the width of the
structure construction type.
Yes
No
None of the three examples of acceptable forms of evidence provided in
the revision prove that a Transmission Owner actively managed vegetation
to prevent encroachment into the MVCD. The Measure should require proof
of active ROW clearing activity per the transmission vegetation
management plan, such as invoicing or crew field reports or vegetation
inspection data from the annual vegetation inspection.
No
This really is another attempt at avoiding defining a minimum clearance
specification and is not practical. As written, this would require each
Transmission Owner to define and document the procedures, processes or
specification by individual span for every line owned or operated by the
Transmission Owner. Each span varies in length and profile and a single
line may have several different conductor types with different load ratings.
Line loadings will vary along the line based on substation taps, etc. The
dynamics described in the language could only be done on an individual
span basis to be reasonably accurate. This is not practical from a planning
standpoint or from a standpoint of implementing clearing work in the field.
Yes
Alternate version of R1/R2
Prefer Alternative A
VSLs proposed by NERC staff
No
Group
Tri-State Generation & Transmission
Linwood Blacksmith
Yes
Table 3 should be referenced as a guideline only.
Yes
Yes
Yes
Yes
Draft 4 version of R1/R2
VSLs proposed by the VM SDT
No
Individual
Michael Pakeltis
CenterPoint Energy
No
There is no rationale provided for the “minimum distances†stated
in Table 3, and they far exceed the ROW widths that CenterPoint Energy
owns (typical total 100’ ROW width for 2-ckt 345kV line) for its current
345kV system, and as such, are open for misapplication and
misinterpretation as an intended minimum standard for making a fall-in
determination for R1 and R2 outside the legal limits of the utility. Table 3
should be deleted. If kept, there should be sufficient rationale included
within the Guidelines and Technical Basis to explain how it was derived
and how it is to be used within the Standard. CenterPoint Energy agrees
with the removal of “active transmission line ROW†as a defined
term; however, the footnote should be deleted as well since it attempts to
create a definition which is not accurate, necessary or useful. Throughout
the Standard, the phrase “active transmission line ROW†should be
replaced with “transmission line ROW†to eliminate the qualifying
term “activeâ€. In making a fall-in determination for R1 and R2, the
limit should be “within the full extent of the Transmission Owner’s
transmission ROW as defined by easement, fee simple, or other legal
rights†as discussed in the Guidelines and Technical Basis regarding the
vegetation management maintenance approach. This places the
determination of the width of the ROW for determination of fall-in
violations clearly on the Transmission Owner and the within the limits of its
legal rights to control the vegetation that has fallen into the line under R1
and R2.
Yes
No preference.
No
CenterPoint Energy does not believe a performance based requirement
should require evidence of processes and procedures to demonstrate
compliance. However, if the majority of industry commenters agree with
the SDT’s approach, CenterPoint Energy has several concerns.
Assuming R1.1 and R2.1 regarding observations of encroachments are not
deleted from the Standard, then only the first paragraph regarding forms
of evidence is helpful and necessary. The second paragraph is not relevant
or necessary. The special qualification of Sustained Outage should be
contained in R1 and R2, not M1 and M2. Also, the reference to a
“Fault†in M1 and M2 instead of a “Sustained Outageâ€
changes the scope of what is specified in R1 and R2 which is not
reasonable. A “Fault†can be associated with a Momentary Outage
or a Sustained Outage. The scope of R1 and R2 is specific to Sustained
Outages.
No
See response to Q3 above. However, assuming R3 is not revised to
exclude processes and procedures, we have no preference to the wording
between the two drafts.
No
See response to Q3 above. However, assuming R7 is not revised to
exclude processes and procedures, the new wording is preferred since it is
more specific. Additionally, a new ambiguous phrase is introduced,
“provided they do not put the transmission system at risk of a
vegetation encroachmentâ€, which we recommend to be changed to
more specific wording, “provided they do not allow encroachment of
vegetation into the MVCDâ€.
Draft 4 version of R1/R2
CenterPoint Energy does not believe a performance based requirement
should be this prescriptive. However, if the majority of industry
commenters agree with the SDT’s approach, CenterPoint Energy has
several concerns. The terminology, “operating within Rating and Rated
Electrical Operating Conditions†is sufficiently definitive. There is no
need to be more prescriptive. Alternate R1/R2 (E) is already similar to the
Draft 4 wording. Of the two alternative, we recommend keeping the Draft
4 wording as is; however, we recommend moving the applicability of
transmission line ratings to the Applicability section of the Standard as
“4.5 Other: The Standard does not apply to any occurrence, nonoccurrence, or other set of circumstances that are beyond the Rating and
Rated Electrical Operating Conditions of the Facilities defined in 4.2.â€
These conditions should be applicable to all elements and requirements of
the Standard just as the force majeure statement does.
Neither. However, we recommend that High or Severe violations be based
only on Sustained Outages experienced and the reliability importance of
the transmission line. Any process or procedure based requirement, if kept
within the Standard, should have a Lower or Moderate designation based
on the utilities intent or capability to comply with the Requirement.
Yes
1. CenterPoint Energy believes the proposed FAC-003-2 is not a
performance-based standard, despite being labeled as such, because it
remains too focused on processes and procedures. CenterPoint Energy fails
to see much difference in the approach from the current Standard.
CenterPoint Energy believes a performance based requirement would
provide performance criteria that an entity would be measured against. An
example of a performance based requirement would be the following: R1.
“Each Transmission Owner shall manage vegetation to prevent
encroachment that results in no more than one (1) Sustained Outage per
XXX circuit miles of applicable lines within any twelve (12) month
period.†M1. Each Transmission Owner has evidence that it had in no
more than one (1) Sustained Outage per XXX circuit miles of applicable
lines within any twelve (12) month period. Examples of acceptable forms
of evidence may include dated reports of vegetation-related Sustained
Outages or dated attestations as to no vegetation-related Sustained
Outages have occurred. However, if the majority of industry commenters
agree with the SDT’s approach, CenterPoint Energy has the following
additional concerns: 2. The phrases “active transmission line ROWâ€
and “Active Transmission Line ROW†are no longer considered
defined terms and should be deleted from the Standard along with
footnote 2, the Compliance Section for Periodic Data Submittal as well as
the Guidelines and Technical Basis. As found throughout the Standard, the
phrase should be replaced with the common terms utilized in the
Guidelines and Technical Basis section, “Transmission Owner’s
transmission ROW as defined by easement, fee simple, or other legal
rightsâ€. 3. In the Background section fall-ins are characterized as
“statistically intermittent†and “these types of events are highly
unlikely to cause large-scale grid failuresâ€. We agree and therefore
recommend that fall-ins be excluded from the Requirements R1, R2, and
Periodic Data Submittal of outages. 4. R4 should be deleted. R4 is related
to processes and procedures and should be combined into R3. The result
of not following the notification process or procedure is that a Sustained
Outage may occur that would be captured by M1 and M2. The process and
procedure would be measured by M3. 5. R5 and M5 contain the ambiguous
phrase, “where a transmission line is put at risk due to the
constraintâ€. This phrase should be replaced with the more specific
terminology in R1 and R2 as, “where a transmission line cannot
perform within its Rating and Rated Electrical Operating Conditions due to
the constraint†or as in R3 as “where a transmission line will be
subjected to an encroachment into the MVCD due to the constraintâ€. 6.
For R6, the detailed rationale and studies used for the determination of the
required one year inspection cycle should be included in the Guidelines and
Technical Basis. The explanation provided in the Rationale that it is
“based upon average growth rates across North America and on
common utility practice†are unfounded and arbitrary without a specific
reference to a North American study. 7. R7 contains the ambiguous
phrase, “provided they do not put the transmission system at risk of a
vegetation encroachmentâ€. This phrase should be replaced with the
more specific terminology in the Rationale for R7 and Requirement R3 as
“provided they do not allow encroachment of vegetation into the
MVCD.†8. Just as the force majeure statement was moved to the
Applicability section of the Standard, the exception for applicability beyond
the Rating and Rated Electrical Operating Conditions should be included in
the Applicability section as well. Currently, it is only included in R1, R2,
and R3. It should be made clear that the other Requirements and
Measurements ARE NOT applicable in situations beyond the Rating and
Rated Electrical Operating Conditions. This is already discussed in the
Guidelines and Technical Basis but not evident within the Standard. 9. The
Periodic Data Submittal should be clarified to as to the specific conditions
under which Sustained Outages are reported. The Applicability section
includes the force majeure; however, other exclusions are not so evident.
We recommend the wording be changed to include all applicable exclusions
for added clarity. We recommend the following wording: “The
Transmission Owner will submit a quarterly report to its Regional Entity, or
Regional Entity’s designee, identifying the Sustained Outages caused
by vegetation, as defined in the categories below, of transmission lines
operating within Rating and Rated Operating Conditions as determined by
the Transmission Owner, exclusive of the force majeure conditions in
Section 4.4, that include, as a minimum, the following.†Also, the
within the Categories listed, the phrases “active transmission line
ROW†should be deleted and replaced with “Transmission
Owner’s transmission ROW as defined by easement, fee simple, or
other legal rightsâ€. This places the determination of the width of the
ROW for determination of fall-in violations clearly on the Transmission
Owner and the within the limits of its legal rights to control the vegetation
that has fallen into the line under R1 and R2 causing the submittal of a
reportable sustained outage. 10. The Guidelines and Technical Basis and
the Technical Reference with the Gallet Equation should be combined into
one document as a supplement to the Standard to avoid duplication in
wording and misinterpretation of context. 11. We agree that the Rationale
test boxes should be deleted from the Standard and applicable explanatory
text be included within the Guidelines and Technical Basis. 12. The
Guidelines and Technical Basis should include the background and basis for
4.2.4 that excludes the Standard from applying to fenced substations. 13.
The Guidelines and Technical Basis should contain more specific examples
of violations of the Requirements and highlight specific exceptions related
to vegetation related outages, especially fall-ins and force majeure
exclusions. 14. The language in R6 refers to inspecting “transmission
lines†and Table 1 for R6 refers to inspecting “ROWâ€. Both areas
should use consistent terminology. 15. In the Guidelines and Technical
Basis section for R6, the reference to the VSL calculation units and the
example units should be consistent—the example should use “circuit
milesâ€, not just “milesâ€. 16. In general, the proposed FAC-003-2
has gone FAR beyond what was contemplated by the Commission in FERC
Order 693 and equates to a total re-writing of the Standard for no
apparent reason. The Commission's determination dealt with the following
areas: (1) applicability; (2) inspection cycles; and (3) minimum clearances
on National Forest Service lands. For instance in Paragraph 729, the
Commission states, “As proposed in the NOPR, the Commission
approves Reliability Standard FAC-003-1 with no proposed modification on
the issue of clearances. The Commission reaffirms its interpretation that
FAC-003-1 requires sufficient clearances to prevent outages due to
vegetation management practices under all applicable conditions….â€
Rewriting the minimum clearances introduced a new set of confusing
definitions, and further burdens the Transmission Owners with new
documentation requirements with little if any benefit when compared to
the Clearance 2 concept in the existing Standard. A preferred approach
should be to incorporate the following few items into the existing Standard
FAC-003-1: (1) the RC versus the RRO; (2) the designation of a specific
inspection frequency; (3) the Gallet equation; and (4) the applicability to
National Forest Service lands.
Individual
E Hahn
MWDSC
Yes
Requirement R4.uses the phrase "notify the control center holding
switching authority for the associated transmission line" when a vegetation
condition is confirmed which is likely to cause a Fault. Switching
jurisdiction may be assigned to a manned substation located closer to a
line rather than a remote 24/7 manned control center. However, the
switching substation will notify its control center. The control center may
need to notify and coordinate with its Balancing Authority or neighboring
control centers. Suggest changing the phrase as follows: "notify the
appropriate control center(s)for the associated transmission line"
Group
FirstEnergy
Sam Ciccone
No
We do not support replacement of the term Active Transmission Line Right
of Way with Footnote #2. Since the term "active transmission line ROW" is
used in the requirements, compliance section, and VSLs, and since the
drafting team has a very definite view of what this term means, the term
should be a definition included in the NERC Glossary. Also, since ROW is
defined in the NERC Glossary, it further supports the reasons this term
should also be defined. Therefore, we suggest the team revert back to the
Draft 3 proposed NERC Glossary term. Lastly, we do not support the
addition of Table 3. We believe this adds unnecessary prescriptiveness to
the requirements. It is also not clear if this Table was intended to be
mandatory because the only reference in the table is in Footnote #2. If the
SDT feels this table is a useful tool that should be included in the standard,
then we suggest adding it to the Guidelines section as optional
information. Also, reference to this Table 3 in the Active Transmission Line
ROW definition should be removed.
Yes
While we agree with the changes proposed, we would recommend that the
list contained in the "Other" section should be revised to include judicial
actions such as injunctions. While this is not a natural occurring situation,
it is certainly one that will prevent an entity from removing vegetation
when needed or desired.
Yes
Although we agree with the language of M1 and M2 for the proposed R1
and R2 in the standard being balloted, we support the alternate versions of
R1 and R2 (see comments in Question 6) and wish to see M1 and M2
developed for the alternate R1 and R2.
Yes
Yes
Alternate version of R1/R2
Although we agree with the alternate version of R1/R2, we have the
following comments: 1. We assume that R1 and R2 will be written similar
to the current proposal with regard to IROL (High VRF) and non-IROL
(Medium VRF) transmission lines, respectively. This should be clear after
changes have been made to the standard before the final ballot. 2.
Although the SDT states that it "suggests similar language as found in the
posted draft for measures M1/M2 may be appropriate with this alternate
R1/R2", we are not clear how these measures will be written and would
like to see a draft of the measures so we can review and comment. 3. The
alternate requirements appear to be "planning" in nature instead of "realtime"; we assume the intention of the SDT was the latter. Therefore the
requirements should be revised with language that is "real-time" in nature.
VSLs proposed by the VM SDT
FE supports the VSL proposed by the SDT. We believe these have been
developed in accordance with the FERC approved VSL guidelines and
represent the appropriate violation levels for situations of varying
probabilities. History has proven the grow-ins are the biggest cause of
vegetation contact issues, and fall-ins and blowing together vegetation are
very hard to predict and control and should be at lower violation levels.
Although we believe that an encroachment into the MVCD that causes no
system disturbance should not be penalized if an entity takes immediate
action to restore the minimum clearance, the assignment of a Lower VSL is
appropriate. We believe that the NERC staff opinion that this situation
warrants a High VSL does not demonstrate thorough rationalization
because it fails to consider the consequences that would place a severe
monetary penalty on an entity for a situation that did not cause a fault,
outage, or cascade of the BES. Furthermore, it is clear from the bullet
points under R1 and R2 of the proposed standard language that the SDT
intended that an encroachment with a sustained outage is different than
and encroachment without a sustained outage otherwise they would not
have specified the bulleted situations in detail. Had the SDT intended for
there to be only two violation severity levels they would have only
specified two bullet items: an encroachment with a sustained outage and
an encroachment without a sustained outage. The requirements are the
only tools the drafting team has to specify its intent in this area and the
approach they used is reasonable to provide these levels of differentiation.
Yes
FE has the following additional comments: 1. In the SDT consideration of
comments from Draft 3, it was indicated that "The subcommittee will ask
that NERC's legal department write a statement for addition to each
standard to clarify which parts/elements of the standard are mandatory
and enforceable and which are provided only as information". We would
appreciate this statement be placed into the standard before the final
ballot so stakeholders have an opportunity to review and comment on the
wording. 2. We cannot comment on the Technical Reference Document
since the latest draft was not posted for review. Does NERC intend to post
this at a later time? If so, we ask that NERC give the industry enough time
to adequately review the document so that we can provide quality
feedback. 3. In the Guidelines and Technical Basis Section, in the first
paragraph of Requirement R5, second sentence, the word "temporarily"
should be removed since it was removed from the requirement.
Group
Kansas City Power & Light
Michael Gammon
No
This needs to be a defined term since the Standard uses that as a basis for
use with Table 3. Using this term as a footnote does not allow the industry
to weigh in on its definition. Footnotes should not be used as a means of
definition or clarification. Footnotes are for references to other sources of
statements or documents that support a particular thought.
No
The theme of the “Other†section are the conditions for excluding
applicable transmission facilities under certain conditions. Recommend the
Drafting Team consider renaming this section to “Exclusionsâ€. In
addition, the term, “Active Transmission Line Right-of-Way†is
capitalized in the “Background†section. If it is determined this term
should not be a definition, then this should be lower case.
No
In response to the informal comment period, the SDT is clear that it
believes the use of encroachment as a basis for determining the
effectiveness and compliance of a vegetation management program. The
purpose of this Standard is to identify the criteria for effective monitoring
of vegetation in transmission right-of-way and to take appropriate actions
when that monitoring identifies the need to “clear†vegetation to
prevent potential transmission facility outages resulting from contact with
vegetation. These proposed Measures as written do not give credit to the
Transmission Owners for effectively monitoring their systems and taking
appropriate actions in regard to vegetation clearing. Why does it make
sense to punish and penalize a Transmission Owner for discovering an
encroachment when they take the appropriate actions to remedy the
condition before any facility outage occurs that results in compromising
the reliability of the Bulk Electric System? These Measures and Standard
should recognize the good practices of effective response to a vegetation
condition and penalize ineffective response. Highly recommend the SDT
consider including appropriate language to recognize effective remedial
actions by Transmission Owners and by doing so, recognize effective
efforts instead of punishing them. In addition, proving encroachments
have not occurred will pose audit challenges in determining that
encroachments have not occurred for the Auditors as well as Registered
Entities. If no encroachments occur, then there is nothing to report or
record. This is a weak platform to stand compliance on. Facility
interruption events caused by vegetation contacts is definitively
measurable and recordable. Recommend the SDT reconsider the concept
of compliance with FAC-003 on the basis of sustained outages.
No
It is unclear that this requirement may utilize the industry practice of
“ruling span†methods to determine the vegetation clearances for a
transmission facility. “Ruling span†methods are used to determine
the construction design for transmission facilities and includes maintaining
safe clearance distances. This requirement could be interpreted as being
applied to every individual span to determine vegetation clearances for a
transmission facility which would not be practical.
No
This requirement is in direct conflict with the “exclusions†as
described in section 4.4. Section 4.4 makes it clear that effects of
“major storms†on a vegetation programs efforts will be allowed as
an exclusion toward compliance with these requirements, yet, R7 does not
allow any encroachment due to modifications to a vegetation plans efforts
due the “Major Storms†(second bullet) or “Weather
conditions/Accessibility†(bullet 6). Please explain what is intended here
that is different than what was intended in section 4.4. In addition, this
presents some audit difficulties regarding the notion of detecting a
“modified work planâ€. Once a work plan is altered and new
objectives are laid out, that becomes the plan and the plans that were
replaced may be discarded since they would be of no value. Further, what
difference does it make to track or monitor any changes to a work plan
provided effective vegetation management is maintained? Recommend the
SDT consider removing the language regarding “work plan
flexibility†as this may suggest and impose an unnecessary compliance
burden on Registered Entities and Auditors.
Alternate version of R1/R2
Prefer Alternative E from the list above. Please clarify the meaning of sway
in Alternative E. Is that wind blowout?
VSLs proposed by the VM SDT
Although the Drafting Team is favored here, it makes little sense in the
NERC Staff VSL to have an encroachment with no sustained outage as a
HIGH VSL. No compromise of the real-time reliability of the bulk electric
system occurred. How could that be a HIGH? If it is determined to use the
VSLs proposed by NERC Staff, it is recommended to change the HIGH VSL
to LOWER.
Yes
1. Part R4.3, “Enforcement, under Section 4, “Applicabilityâ€, is
confusing as to why it is needed. What is the intended purpose of this
part? It is clear that each Requirement, Measure, VRF and VSL when
adopted by the NERC BOT and FERC become mandatory and enforceable
on the declared effective date(s). There is no need for Part R4.3 to
reinforce the compliance enforcement dictated by the established NERC
Rules of Procedure. 2. Requirement R4: The requirement is clear to notify
the appropriate control center regarding conditions that might cause a
fault on a transmission facility. The requirement should be clear, this for
the Transmission Owners applicable lines and recommend the SDT modify
the language in R4 to that end. In addition, there is no action other than
notification in regards to this operating condition. Highly recommend the
SDT consider adding language to take “immediate actions†to
remedy the vegetation condition and remove the threat. 3. Requirements
R5 & R7 are not clear in that they are for the Transmission Owners
applicable lines. This has been a common theme throughout this Standard
and by the omission of this language, it is not clear that the intended
scope of the requirements do not go beyond the applicable lines.
Group
NERC Staff
Mallory Huggins
Yes
No
NERC staff does not support the language in the Other Section. Staff
believes that the force majeure provision is unnecessary and calls into
question whether NERC and the regions have enforcement discretion to
take such things into account in applying other standards that do not
include this type of provision.
No
With respect to both M1 and M2, NERC staff finds the “acceptable
forms of evidence†incomplete. To assess compliance, the auditors
would also need to see the processes and procedures identified under
Requirement R3 and the annual work plan under Requirement R7 to see
how the entity planned to prevent sustained outages and what the entity
had done to implement that plan. Finally, what is the purpose of the
following sentence?: “If an investigation of a Fault by a qualified person
confirms that a vegetation encroachment within the MVCD occurred, then
it shall be considered a Real-time observation.†Recommend adding
each report of a real-time observation of encroachment into the MVCD to
the periodic data submittal.
No
The removal of programmatic details from R3 renders the auditing task
much more difficult. How does one assess the quality of the program
except through the results required in R1 and R2? Since maintaining
specific cut-to clearances is not required, there is much greater
subjectivity in application that greatly complicates the auditor job. If the
team does not want to limit the available approaches, it could provide
flexibility by offering an array of deterministic formulas or approaches for
maintaining vegetation. This might include maintaining vegetation to
remain within a certain height from the ground given maximum sag
distances. Additionally, this requirement does not seem to require the
entity to actually follow its policies and procedures (unlike, for instance,
R7). What is a violation here? Not having the documented procedure(s) OR
whether the documented procedure(s) actually demonstrate that the entity
can prevent encroachment? NERC staff is also concerned with some of the
language in M3. Consider the following modification: “The Transmission
Owner will have procedures, processes, or specifications as identified in
Requirement R3, records showing work done to support its annual work
plan identified in Requirement R7, and its quarterly vegetation reports, to
demonstrate that it can prevent encroachment into the MVCD.†Finally,
with respect to the Rationale associated with R3, how would NERC enforce
poor intent or a poor indication of competency (especially if the entity was
performing well)? Recommend: Provide a basis for evaluating whether the
Transmission Owner’s procedures, processes, or specifications used to
maintaining vegetation are achieving that goal. There may be many
acceptable approaches to controlling vegetation so that it does not
encroach into the MVCD. And one small copyedit:
“interrelationships†should not have a hyphen.
No
This is the first instance in which an annual work plan is discussed. It
would appear necessary to first develop an annual work plan component of
the overall vegetation management program. There should also be some
performance review or expectation that the annual plan as implemented
achieved the intended program objectives, or that modifications would be
necessary. Does R7 require both that a Transmission Owner has an annual
vegetation work plan AND that it completes the work plan? Detail is
required as to what is expected in the work plan, as there is currently no
basis to judge whether the work plan is adequate or not adequate. And
what does a modification entail? Does this mean reduction of performance,
delay in performance, or complete postponement of performance? NERC
staff is also concerned with the list of examples one might use to modify
an annual plan. Several of these items should not pose any greater risk to
vegetation contact and render the requirement virtually unenforceable. It
provides a wide array of reasons to postpone vegetation management and
may make it a very low priority for an entity: -“Rescheduling work
between growing seasonsâ€: This could be an honest change (if there
are unexpected seasonal changes) or it could reflect bad initial planning. If
there will be occasion for auditors and investigators to distinguish, there
should be guidance on differentiating. -“Crew or contractor
availabilityâ€: This could be an honest change (if there is an unexpected
labor dispute or if crews are needed to help a neighboring utility during an
unexpected emergency) or it could reflect bad initial planning. If there will
be occasion for auditors and investigators to distinguish, there should be
guidance on differentiating. Alternatively, it could be removed from the list
as it is within the exclusive control of the Transmission Owner. “Identified unanticipated high priority workâ€: This could be an
honest change or it could reflect bad initial planning. If there will be
occasion for auditors and investigators to distinguish, there should be
guidance on differentiating. It is also vague and would necessitate a
judgment call for enforcement. -“Permitting delaysâ€: Annual plans
should account for anticipated permitting schedules and maybe even add a
factor for uncertainty. It is a planning issue for the entity and should not
be an acceptable excuse for not conducting vegetation management. “Land ownership changedâ€: If a landowner has the ability to affect
the reliability of the bulk power system, the landowner should be subject
to the reliability standards. A registered entity should be responsible for
the land in its ROW, especially if it has turned control of the land, and the
ability to affect reliability of the BPS, over to another entity or person for
financial gain. -“Funding adjustmentsâ€: NERC staff is not convinced
that this is a legitimate reason for adjusting an annual vegetation work
plan. Economic considerations should not be a reason to delay or modify
vegetation management. -“Emerging technologiesâ€: It is unclear
what this example is intended to accomplish. In general, these examples
should be bounded in some way to ensure that a modification due to one
of their occurrences does not impart a greater risk of vegetation contact.
Draft 4 version of R1/R2
NERC staff supports the Draft 4 version. The six options listed in the
alternative version of R1/R2 do not seem manageable from a utility
perspective. But while staff prefers the existing language, it continues to
emphasize that fall-ins from outside the ROW can impact the line and need
to be taken into consideration.
VSLs proposed by NERC staff
NERC staff supports the VSLs proposed by NERC staff. The SDT’s VSLs
are too low, and they do not seem to differentiate between various levels
of compliance. Still, staff is concerned that the difference between an
encroachment that leads to an outage and one that does not is based on
nothing but luck.
Yes
EFFECTIVE DATES -The first item should be re-written to “First
calendar day of the first calendar quarter one year after the date of the
order approving the standard from applicable regulatory authorities where
such explicit approval is required.†-The second item is not needed and
should be removed. -The third item is okay but the phrase “where
explicit regulatory approval is not required†should be removed.
EXCEPTIONS -Identifying a critical line and then waiting 12 months to
perform vegetation management is counter to the risk avoidance strategy
that the standard is attempting to accomplish. In effect, this standard
permits an entity to identify a major WECC path or an IROL just prior to
peak season and then not complete any vegetation management activities
until just before the next season 12 months later. This is wholly
inappropriate. -Using the phrase “an element of an IROL†seems
confusing because “Element†is a term defined in the glossary.
Further, IROL is an identified limit, not a physical component. This should
be reworded to say “a facility that is identified to be part of an interface
or path impacting an IROL.†This is also seen in R1 and R2 and needs
to be adjusted there as well. -For newly acquired assets, the 12 month
window may be appropriate, but there needs to be a much nearer term
inspection undertaken to identify “risky†vegetation. DEFINITION The modified definition assumes the ROW is maintained, which may not be
the case (for instance, if a newly acquired asset has not yet been acted
upon). An entity could interpret the new definition to indicate that the new
owner cannot be performing an initial vegetation inspection if the ROW has
not yet been maintained. The phrase “maintained transmission lineâ€
should be changed to “applicable transmission line.†-The inclusion
of the phrase “which may be combined with a general line
inspection†is unnecessary and should be removed. In fact, the current
definition does not restrict combining the inspection with other field visits,
while in the proposed definition that vegetation inspection can only be
combined with a general line inspection. OBJECTIVES (SECTION 3) -NERC
staff is concerned that the purpose states “that could lead to
Cascading.†This qualifier limits the purpose of the standard, which
should be to prevent vegetation-related outages. The more outages there
are, the less the overall system reliability; it does not necessarily have to
lead to Cascading to be significant and represent a reasonable risk to the
BES. -The term “maintain†might be better than “improve.â€
APPLICABILITY (SECTION 4) 4.1 Functional Entities -Noticeably absent
from the standard is coverage for transmission facilities that connect
generators to the interconnected bulk power system. As such, the team
should add Generator Owners to the applicability and include such
language that was proposed by the ad hoc team: transmission facilities
that connect generators to the bulk power system that exceed two spans
from the fence-line of the generating plant; coupled with the previous
discussion, this provides complete coverage for all transmission facilities
and switchyards and substations. This is what is needed to ensure no gaps
in vegetation management coverage. 4.2 Facilities -The identification of
critical facilities herein does not recognize the overarching criteria that are
being developed in support of the PRC-023 order, and in some respects, in
response to Order 693 directives to define the criteria for “critical
facilities.†The FAC-003-2 SDT should work in conjunction with the
PRC-023 team, which is establishing a set of criteria for identifying critical
facilities such that the outcome across all NERC standards is consistent. “Transmission line†should be capitalized as a NERC-defined term. 4.2.4: This exclusion seems strange. It would appear that there are no
expectations for vegetation management in switchyards, which is
unacceptable. We should be able to develop language that requires that a
Transmission Owner or Generator Owner maintain vegetation within
fenced areas of the switchyard, station, or substation to the same
clearances as one does for the ROWs, without necessarily obligating them
to an annual cycle of inspection or management. REQUIREMENT R4 “Qualified personnel" should be defined. In the Rationale, some
examples are listed, but who else counts as “qualified field
personnel� -“At any moment†is an unnecessary qualifier and
should be removed (same for M4). -With respect to the phrase
“intentional time delay,†intent is a tricky thing to prove. Most
standards set clear timelines which kick in regardless of intent, because it
diminishes reliability to base a standard on intent. The SDT should
consider doing so here. REQUIREMENT R5 -NERC staff is confused by the
overall purpose of this requirement. It appears to be a defense to a
possible violation for failure to perform some planned vegetation work, but
it flips it around and makes it a requirement. A better approach would be
to just deal with this in addressing the mitigating/aggravating factors
under a violation of R1 and R2. -The team should be more specific with
respect to expectations for “corrective action.†There needs to be an
expectation that the corrective action needs to maintain an equivalent
level of performance consistent with the intent of the vegetation
management program. This could include, for example re-rating lines to
reduce max sag until the condition is rectified, enhanced inspection cycles
to monitor conditions, etc. It would be useful to define a metric for the
success of corrective actions. -The team should be clearer on what
constitutes a “constraint.†Is it only legal constraints? One
interpretation could be resource constraints, which would certainly not be
appropriate in this context. The phrase “due to constraints†is also
used in the Rationale section. In this context, “constraint†appears
to mean congestion on a transmission line. This seems very different from
being “constrained from performing planned vegetation work.†In
fact, the existence of congestion on a line does not necessarily create risk.
We would not want entities to make the economic determination that they
will put off required vegetation work because it would cost too much in
energy sales profits. REQUIREMENT R6 -It would appear necessary to
require the use of the inspection information to guide or modify program
development as is identified in the Rationale box accompanying the
requirement. This is referred to in R7 but is not identified as an
expectation from R6. -What are "all applicable transmission lines"? Are
those lines covered by both R1 and R2? Clarify this. -“Once per
calendar year" requires more guidance. Would two inspections on
12/31/2010 and 1/1/2011 satisfy this requirement? Shouldn't there be a
requirement to space these inspections out? Recommend: once per
calendar year with no more than 15 months between inspections. -The last
sentence of R6’s Rationale states that “Transmission Owners should
consider local and environmental factors that could warrant more frequent
inspection.†But the way the requirement is written, there is no basis
for requiring anything more frequent than once per calendar year. If the
intent is to have stricter timelines for different registered entities, then the
standard would need to be revised. COMPLIANCE Additional Compliance
Information/Categories of Sustained Outages -Category 3 (Fall-ins from
outside the ROW) should be reinstated. Even if it is not required by the
standards, Category 3 reporting should be kept. -There is currently a
public bulletin to encourage Transmission Owners to report Category 1 and
2 outages within 48 hours. The SDT should consider adding this as a
requirement and including it in the new standard as such. VSLs -The VSL
for R3 should be shifted to an approach that simply counts the missing
elements: lower = missing one element; moderate = missing two
elements; high= missing three elements; severe = not having documents.
-The VSL for R4 uses the phrase “vegetation threat,†which needs
to either be conformed to the text of the drafting team or defined. This
VSL also uses the phrase “intentional delay†A truly intentional
delay should be labeled as severe, not just high. (And as already stated,
intent is a very tricky thing to prove.) -For the VSL for R5, there may be
ways to differentiate violations based on whether the entity identified
appropriate corrective actions (versus missing obvious alternatives),
attempted corrective actions but failed, considered alternative corrective
action, etc. -For the VSL for R6, the SDT should differentiate between the
criticality of different lines. At the very least, a failure to inspect R1 lines
should be a more severe violation than a failure to inspect R2 lines. -The
VSL for R7 should perhaps be differentiated based on whether the
incomplete work related to critical versus non-critical or less critical lines
(i.e., R1 lines vs. R2 lines). GUIDELINES AND TECHNICAL BASIS R1/R2 “If an investigation of a fault by a qualified person confirms that a
vegetation encroachment within the MVCD occurred, then it shall be
considered a Real-time observationâ€: This is an important statement
and should be included as part of the requirement itself. R3 -With respect
to the phrase “an adequate transmission vegetation management
program,†the standard talks about factors to consider, but the
requirement does not include any provisions on which to base a
determination of adequacy. NERC staff believes it should. -The guideline
states, “This approach provides the basis for evaluating the intent,
allocation of appropriate resources and the competency of the
Transmission Owner in managing vegetation,†but nothing in the
requirements actually provide explicitly for such evaluations. R4 “Cellular service or two-way radio disabled†should not be
considered an acceptable unintentional delay. This seems to be within the
entity’s control: there may be a difference between whether the cell
service problems are due to network problems as opposed to the entity
failing to charge the phone or pay the bill. -“Remote field locationsâ€
should not be considered an acceptable unintentional delay. This is not
entirely beyond the registered entity's control. There may be a difference
between a work site that is isolated from radio or cellular networks versus
the fact that the employee simply left the radio in the truck. “Vegetation-related conditions that warrant a response†should be
defined in the standard. -It is not clear to NERC staff that a lineman or an
arborist is capable of completing “an assessment of the possible sag or
movement of the conductor†out in the field in real time. However, if
this is the expectation, it should be written into the requirements. -The
fourth paragraph states that the “Transmission Owner has the
responsibility to ensure the proper communication…†Earlier in this
section, however, it says that the condition of the communication system
is not considered to be intentional delay. This inconsistency needs to be
addressed. This sentence should also include a requirement for correcting
the vegetation encroachment. -The phrase “minutes or hours†is
used in the final sentence of the fourth paragraph of this sentence. This
detail should be written more clearly and written into the standards. Is 24
hours still hours? What about 48 hours? R6 -With respect to the following
sentence, beginning with “Therefore it is expected,†NERC staff is
concerned that nothing in the requirement actually makes this expectation
enforceable. It would be best to require each TO that experiences a
vegetation related sustained outage to investigate the outage and make
revisions to its TVMP if the investigation shows that the growth rates of
vegetation under the TO’s control do not match those anticipated in
the TVMP. R7 -The second paragraph states that “recent line
inspections may identify unanticipated high priority work.†But the fifth
bullet in R7 does not indicate that the higher priority work was identified in
a recent line inspection. R7 should be revised to make that caveat clear. The second paragraph references “Modifications to the annual work
plan.†Presumably, these modifications would not excuse compliance
with R1, R2, and R6. That should be made clearer in the requirements.
TABLE 3 -None of the requirements actually reference this table. That
should be modified.
Group
Dominion
Louis Slade
No
The distances proposed in Table 3 – Minimum Distance from the
Centerline of the Circuit to the edge of the active transmission line ROW
may not be consistent with the centerline distances cleared and
maintained by the TO. For example, a TO maintaining 75’ from
centerline for a 500kV circuit would be required to clear and maintain an
additional 12.5’ to meet the proposed standard’s requirement. We
suggest either allowing individual TOs to maintain active ROW widths
consistent with their normal clearing/maintenance practices, going back to
Draft 3’s definition of Active Transmission Line Right-of-Way, or
changing the footnote in Draft 4 to read: A strip or corridor of land that is
occupied by active transmission facilities. This corridor does not include
the parts of the Right-of-Way that are unused or intended for other
facilities. However, the portion of the ROW that has been cleared must at
least meet design clearance requirements such as National Electric Safety
Code or other design criteria, for the reliable operation of active facilities.
Yes
Yes
Yes
Although we agree with the intent of the proposed language, we feel the
requirement should be revised to read: Each Transmission Owner shall
document the procedures, processes, or specifications it uses to prevent
the encroachment of vegetation into the MVCD. Such procedures,
processes, or specifications shall consider the dynamics of a transmission
line conductor’s movement throughout its Rating and Rated Electrical
Operating Conditions and the inter-relationships between vegetation
growth rates, vegetation control methods, and inspection frequency, for
the Transmission Owner’s applicable lines.
Yes
Draft 4 version of R1/R2
The alternate language proposed above suggests that methodologies
typically incorporated into processes, procedures, or specifications (as
required by R3) should also be included into performance-based
requirements R1 and R2. The incorporation of this language into R1 and
R2 would change these requirements from performance-based
requirements to hybrid performance/competency-based requirements. The
intent of R1 and R2 is to define a failure to prevent encroachment into the
MVCD. Ensuring that a TO’s processes, procedures, or specifications
demonstrate adequate means of protecting conductors falls under R3,
which incorporates transmission conductor and vegetation dynamics and
interrelationships. Therefore, methodologies employed to manage the floor
of active transmission ROW should be incorporated into the documentation
required by R3 and proof that vegetation was managed in accordance with
processes, procedures, or specifications to prevent encroachment into the
MVCD will be demonstrated by compliance with R1 and R2.
VSLs proposed by NERC staff
As all parts of R1/R2 seem to contribute equally to the intent of the
requirement – shall manage vegetation to prevent encroachment that
could result in a Sustained Outage - NERC’s proposed VSLs best
address noncompliance with the requirements.
Yes
In R4 and M4, the phrase "without any intentional time delay" has been
added. We recommend removing this language from the requirement as it
is not possible to measure intent.
Individual
George Czerniewski
Consolidated Edison Company of New York Inc
Yes
The same verbiage in footnote number 2 should appear below Table 3 to
avoid any confusion.
Yes
Yes
Yes
Yes
Draft 4 version of R1/R2
Consolidated Edison Company of New York, Inc prefers the Draft 4 version.
The wording in the VSLs should be modified for both Requirements to
include the phrase 'manage vegetation'. The phrase 'manage vegetation'
requires a utility to take specific action to prevent encroachments/outages.
VSLs proposed by the VM SDT
The wording in the VM STD VSLs should be modified to include whether or
not the TO managed any vegetation on that particular line. A more severe
VSL should be assigned to any encroachment or sustained outage that was
caused as a result of a TO not performing any vegetation management
activities on that line. For example, if vegetation management activities
were completed on 80% or 90% of the line and additional work was in
progress on the remainder of the line but an encroachement or sustained
outage occurred on the spans that were scheduled to be done as part of
the annual plan, the TO should be held accountable for this but at a lower
severity level.
Yes
In R5, the SDT should better define the phrase 'where a transmission line
is put at potential risk due to the constraint.' This is rather vague and
could lead to inconsistent practices between utilities. Con Edison defines all
undesirable species on the full width of the ROW as 'potential risks to the
transmission line' regardless of height or location at the time of vegetation
management. Interim corrective action should only be required when the
potential risk is approaching the imminent threat classification.
Consideration of Comments on Initial Ballot — Project 2007-07 Vegetation Management FAC-003-2
Date of Initial Ballot: 7/9/2010 - 7/19/2010
Summary Consideration: In general, there were no common themes and as such each comment was responded to individually.
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment serious
consideration in this process. If you feel there has been an error or omission, you can contact the Vice President and Director of Standards, Gerry
1
Adamski, at 609-452-8060 or at [email protected]. In addition, there is a NERC Reliability Standards Appeals Process.
Voter
Kirit S. Shah
Entity
Ameren Services
Segment
Vote
Comment
1
Negative
(1) Need clarification on Footnote number 2 and Table 3 : Does this mean wider ROW
easements will need to be acquired to be compliant or will this apply to ROW’s for new
circuits going forward? (2)R7 - Funding Adjustments (increase or decrease) - need more
description to imply only when planned vegetation work is “over and above”. (3) R5 - What
constitutes a “potential risk”? Breaking the MVCD or getting close to it? (4) R7 - No work
plan can ensure that NO vegetation encroachments will occur; can language be added
similar to “to ensure that no vegetation encroachments ‘from vegetation within the active
right of way’ occur within the MVCD”?
Response:
(1) No, the SDT has re-established the concept of an Active Transmission Line ROW by changing the definition of Right of Way with the same
principles which was almost universally accepted by industry. After thorough analysis of potential modifications to Table 3 and other
alternatives, the team found no specific, prescriptive, or formulaic language which can be applied across the US, Canada and Mexico, thus the
team reverted to the Active Transmission Line ROW, removed Footnote 2 and Table 3.
(2) The SDT limits the reasons for plan adjustment by whether the changes place the system at risk of a violation of the MVCD as defined in R1 and
R2.
(3) The SDT recognizes that defining any risk is subjective. Removing the term does not change the fact that each TO must determine the risk and
respond accordingly.
(4) The SDT has incorporated your suggestions.
Danny
McDaniel
Cleco Power LLC
1
Negative
Bryan Y
Harper
Cleco Utility Group
3
Negative
1
1. Encroachment into the MVCD should require the owner to take immediate corrective
action to mitigate the threat. But such an encroachment should not be reportable as a
violation. Owners may be hesitant to report if they known it is a violation. Recommend the
SDT consider modifying the measures for R1 and R2 to be applicable only in the interruption
of transmission facility or allow the reporting but don't make it a violation of compliance. R4
states "Each Transmission Owner, without any intentional time delay, shall notify the control
center holding switching authority for the associated transmission line when qualified
The appeals process is in the Reliability Standards Development Procedure: http://www.nerc.com/files/RSDP_V6_1_12Mar07.pdf.
Voter
Matthew D
Cripps
Entity
Cleco Power LLC
Segment
Vote
Comment
6
Negative
personnel confirm the existence of a vegetation condition that is likely to cause a Fault at
any moment" 2. In R4, the use of "intentional" is a vague term. As other standards
prescribe, set a time at which the control center should be notified. R5 states: "Each
Transmission Owner shall take corrective action when it is constrained from performing
planned vegetation work, where a transmission line is put at potential risk due to the
constraint." 3. In R5, the use of "potential risk" is a vague term. R5 should read as follows:
Each Transmission Owner shall take corrective action when it is constrained from
performing planned vegetation work. R7 states: "Each Transmission Owner shall complete
the work in an annual vegetation work plan to ensure no vegetation encroachments occur
within the MVCD ...." 4. The first sentence should not include the phrase "to ensure no
vegetation encroachments occur within the MVCD" since the requirement is to do the work
in the work plan. The added phrase adds ambiguity, e.g., if there is an encroachment, is R7
violated since it does not meet the "ensure" phrase? Would this cause a double jeopardy
situation with R1 and R2?
Response:
1. The SDT discussed this issue at length. However, NERC and FERC interpret vegetation growing into MAID as too great a risk to allow. While MAID
is replaced with the MVCD the risk is still there.
2. The SDT debated a set time limit. The team could not find a time that would fit all situations. Intentional would apply if a TO withheld notification
after having confirmed that risk conditions exist.
3. The SDT removed the vague language.
4. There are opportunities for double jeopardy between R1/R2 and R7 without this language. The occurrence of double jeopardy has not been born
out.
Saurabh
Saksena
National Grid
1
Negative
Michael
Schiavone
Niagara Mohawk
(National Grid
Company)
3
Negative
1. The recent addition of a centerline distance to edge of Active ROW is not acceptable to
National Grid. In many areas we use design standards that allow a much lesser ROW width
with no compromise to “cleared width” or tree related reliability of the line. Instead of using
the term “Centerline” as referenced on Table 3, the use of “outer phase” or “phase closest
to tree line” would be more appropriate. 2. National Grid also has issues with the term
"easements" in the definition and seek clarification on several questions - is there a reason
the Active ROW only includes easements, not fee ownership, license or some other right to
occupy and manage the ROW? Would Active ROW include “danger tree rights” on land?
Response: 1&2. The SDT thanks you for your comments. Based on your comment and others, the , the SDT has re-established the concept of an
Active Transmission Line ROW by changing the definition of Right of Way with the same principles which was almost universally accepted by
industry. After thorough analysis of potential modifications to Table 3 and other alternatives, the team found no specific, prescriptive, or formulaic
language which can be applied across the US, Canada and Mexico, thus the team reverted to the Active Transmission Line ROW, removed Footnote
2 and Table 3.
Claudiu
GDS Associates, Inc.
1
Negative
All comments have been included in the NERC comment form.
2
Voter
Entity
Segment
Vote
Comment
Cadar
Response: Please refer to the SDT responses on the comment form.
Michael
Gammon
Kansas City Power &
Light Co.
1
Negative
Scott
Heidtbrink
Kansas City Power &
Light Co.
5
Negative
Although the proposed FAC-003 standard has many improvements and advancements that
are desirable over the existing FAC-003 standard, the handling and treatment of
encroachments as proposed without consideration of recognizing an organizations efforts in
responding to an encroachment situation makes this proposal less desirable and is a major
concern regarding the risk that the associated penalties and assessments place on
organizations.
Response: The SDT thanks you for your comments. Zero tolerance for vegetation caused outages is a stated goal of FERC and NERC as it relates to
this standard. Quote from NERC:
Vegetation Management — While four transmission outages due to vegetation occurred in a single afternoon five years ago, preliminary data suggests that only six such
outages occurred in the first six months of 2008 – none of which caused customers to lose power. Transmission line outages due to vegetation contact are still a cause for
concern, however, and this remains a top priority for NERC. Through its standards and compliance enforcement, NERC now has a zero-tolerance policy in place, where the
goal is to correct issues that may arise long before any customers are affected.
This policy is part of FAC-003-1 and in concept did not change with the proposed version. The SDT recognizes this concern and has developed
gradation taking into account line criticality in VRF’s and type of outage not contained in the current version FAC-003-1. Finally, It is also important
to note that each and every incident or potential violation is investigated and addressed based on the specific circumstances surrounding the
particular event. These investigations should necessarily take into consideration and recognize the utility's individual efforts in responding to an
encroachment situation.
Thomas R.
Glock
Arizona Public Service
Co.
3
Negative
APS supports retention of FAC-003-1 as currently effective, as it is working well for the
industry. APS does not support a change to this standard for the following reasons: o The
minimum clearances must be sufficient to avoid any sustained vegetation-related outages
for all applicable conditions. ? . ? Clearance 1 should remain in the standard as it ensures
clear direction to the utility on how the system is to be maintained, and provides assistance
to the Transmission Owners in dealings with federal land agencies on vegetation
management issues. Elimination of the discretion in clearance 1 will significantly degrade
this support. ? ANSI-A300 should remain in the standard. Though simply a footnote in the
currently effective version, ANSI-A300 should be a requirement in the standard. Relevant
Registered Entities should be held to following ANSI A-300 standards and BMP’s for best
management practices. o APS does not agree with the removal of ‘fill in the blank’
components where the Transmission Owner determines the requirement with no limits or
direction. Examples include and “personnel requirements” in version 1. The SDT removed
this requirement from the current version. ? Personnel qualifications should be remain a
requirement. The standard should recognize certification programs through the
International Society of Arboriculture that certify a minimum level of competence to manage
3
Voter
Entity
Segment
Vote
Comment
a vegetation management program which required ongoing training and education to keep
up with the latest technologies on UVM. ? There are other standards that require
qualifications and training. ? The revised standard dilutes accountability for maintaining the
full width of utilities easement. The active ROW should be wide enough to prevent outages
caused by grow-in and blow-in events. ? The changes to R1, allowing a real-time
observations to evidence encroachments, does not take into account all rated conditions
and the time the recording was made. Real-time observations will not account for changing
conditions and increase in load. Available technologies, such as LIDAR, can simulate allrated conditions, contour and tree height to remove these potential trees hazards before an
outage occurs. ? The utilities should be required to inspect all the lines annually. ? The
standard should include a footnote that provides that a utility will not be held accountable
for not completing its annual work plan if federal or state agencies fail to approve annual
work plans within 90 days of submittal, or that takes into account the time it takes the
utility to get approval.
Response: Thank you for your comments.
•
The SDT is changing the Standard in response to the SAR. The success of the existing standard will be preserved and enhanced with this
revision.
•
If vegetation is maintained as required in this draft of the standard in requirements R1 and R2, then no vegetation-related sustained outages,
caused by vegetation from within the ROW, within the control of the TO can occur.
•
Clearance 1 was a fill-in the blank requirement and did not provide the TO any new easement rights, or land permit rights across any lands
whether those land be privately owned or publicly owned; therefore Clearance 1 remains removed from this draft. Furthermore, the relevance
of Clearance 1 depends on several other factors such as length of maintenance cycles, inspection frequency and growth rates. R3 is now
used as a more comprehensive method to address these concerns in lieu of a Clearance 1 requirement.
•
In order to meet the SAR FAC-003 is required. ANSI-A300 is not sufficient to meet the SAR requirements and contains many elements that do
not need to be related to transmission system electrical reliability.
•
The SDT suggests that the submittal of a NERC SAR on the PER standards be considered to address any proposed personnel qualifications,
certifications or training issues.
•
The SDT is following NERC guidelines as they understand them.
•
The SDT has re-established the concept of an Active Transmission Line ROW by changing the definition of Right of Way with the same
principles which was almost universally accepted by industry. Outages arising from vegetation from outside the ROW are not violations of
the standard. The SDT had determined this to be the most appropriate assignment of an area of maintenance responsibility considering the
numerous variations in easements and permit rights across North America.
•
The Standard requires the maintenance to be performed such that loading to Rating and Rated Conditions, and the dynamics of sag and
sway are taken into consideration. Additionally any real time observations of encroachments into the MVCD are to be reported as violations
of the standard. The SDT does not see the need to be prescriptive as to the technology or tools the TO used to be compliant with the
Standard, but is confident that if the vegetation in maintained such that no encroachments are ever observed, and no outages are ever occur,
then the reliability purpose of the standard will be fully accomplished. Furthermore, the results from a LIDAR survey are temporal in nature.
4
Voter
Entity
Segment
Vote
Comment
Any program relying on LIDAR would incur a substantial cost with a long term commitment that may not be justified for many Transmission
Owners.
•
FERC requested a defined period for inspection. The SDT agrees with you that annual inspection is required. Therefore the SDT has made
annual inspections a Requirement of this Standard. As to all lines versus applicable lines, FERC has accepted the 200 kV bright line for this
standard. They did order the SDT to ensure that no sub-200 kV lines that are important to the Bulk Electric System are missing from the
Applicability of the standard. The SDT has incorporated a FERC accepted test (as found in the referenced Standard) to make sure no such
important lines are missing.
•
The SDT agrees that erroneous obstacles to compliance with the standard should be addressed. However, they cannot be resolved in this
forum, or through language inserted in this standard. This Standard places requirements on the Transmission Owners, not on landowners.
There is no legal mechanism for this Standard to take rights from property owners and assign them to the Transmission Owner.
John J.
Moraski
Baltimore Gas &
Electric Company
1
Negative
BGE feels that the new standard does nothing to improve reliability over the existing
standard. Furthermore, it could be argued that it potentially diminishes reliability, based on
the new MVCD vs. Clearance 2 guidelines. It also includes requirements which could be
perceived as being more confusing than the existing requirements in the current standard,
e.g., the Active Right-of-Way, Calendar Year Inspections, etc. The new standard, If
adopted, would almost certainly require a complete restructuring of all TVMPs and related
compliance processes, with no commensurate value-added for individual utilities or the
industry in general. In addition, it would do little to enhance the overall intent of the
standard, which is to improve vegetation-related transmission reliability in North America.
Response: The SDT thanks you for your comments. The SDT believes the proposed version addresses concerns outlined in FERC Order 693 and
improves reliability of the BES. The industry overwhelmingly agrees the MVCD based on the Gallet Equation is superior to that of the Clearance 2
fill-in the blank requirement in the current version and in fact can be a greater distance depending on the basis used for Clearance 2 determination.
Based on your comment and others, the SDT has re-established the concept of an Active Transmission Line ROW by changing the definition of Right
of Way with the same principles which were almost universally accepted by industry. After thorough analysis of potential modifications to Table 3
and other alternatives, the team found no specific, prescriptive, or formulaic language which can be applied across the US, Canada and Mexico, thus
the team reverted to a ROW definition, removed Footnote 2 and Table 3. While it is true that any change to the standard may result in changes to
current documentation of practices and procedures (such as the TVMP), the SDT believes changes will be minor and be an improvement.
5
Voter
Paul Rocha
Entity
CenterPoint Energy
Segment
Vote
Comment
1
Negative
CenterPoint Energy believes the proposed FAC-003-2 is not a performance-based standard,
despite being labeled as such, because it remains too focused on processes and procedures.
CenterPoint Energy fails to see much difference in the approach from the current Standard.
CenterPoint Energy believes a performance based requirement would provide performance
criteria that an entity would be measured against. An example of a performance based
requirement would be the following: R1. “Each Transmission Owner shall manage
vegetation to prevent encroachment that results in no more than one (1) Sustained Outage
per XXX circuit miles of applicable lines within any twelve (12) month period.” M1. Each
Transmission Owner has evidence that it had no more than one (1) Sustained Outage per
XXX circuit miles of applicable lines within any twelve (12) month period. Examples of
acceptable forms of evidence may include dated reports of vegetation-related Sustained
Outages or dated attestations as to no vegetation-related Sustained Outages have occurred.
Response: The SDT thanks you for your comments. FAC-003-2 is a “results based standard” (RBS) with a stated objective to prevent outages that
could lead to cascading. Any requirement that has an allowance for a certain number of outages does not meet that objective.
Russell A
Noble
Cowlitz County PUD
3
Negative
Cowlitz votes negative with reluctance over two items: 1. Requirement R4 has a qualitative
nature in the statement “without intentional time delay” which will leave room for subjective
judgment on the part of the auditor in determining intent or the state of mind of the
Transmission Owner. Cowlitz understands the need to communicate to the control center a
vegetation condition that may cause a Fault at any moment as soon as possible. In this
light, it is not possible to set a quantitative time limit for this report to occur for all
occasions. In one scenario, a very short time limit may be arguable due to the proximity of
available radio/telephone communications. However, in another remote situation it may
take up to several hours to access communication equipment after discovery. Compounding
the problem is the need to document the time of day versus location progress of the
vegetation inspector to establish a discovery time stamp; this is not covered in M4. Cowlitz
suggests the following changes (see standards VAR-002-1, IRO-006-3, TOP-003-0, TOP-
6
Voter
Bob Essex
Entity
Cowlitz County PUD
Segment
Vote
Comment
5
Negative
007-0 for similar verbiage): R4. Each Transmission Owner shall notify the control center
holding switching authority for the associated transmission line when qualified personnel
confirm the existence of a vegetation condition that is likely to cause a Fault at any moment
as soon as possible, but no longer than one hour with the following exception: In areas
where communication with the control center is not possible within one hour due to lack of
radio/telephone service, the Transmission Owner shall document these areas along with the
reasonable time frame for reaching radio/telephone service. 2. Cowlitz agrees with United
Illuminating in that R7, as proposed, requires a VMP to be completed to ensure no
encroachment occurs. The Supplemental Reference for R7 does not describe the
requirement of the annual vegetation work plan to ensure no vegetation encroachments
occur within the MVCD. The Reference states the requirement is established to diminish the
risk of encroachment; very different from ensuring no encroachment. In the reference for
R7 the word “ensure” is only used to describe that flexibility in the VMP is allowed to ensure
the reliability of the Transmission System. M7 is measuring work plan completion not the
prevention of encroachment. United Illuminating and Cowlitz suggest that R7 be changed
to: Each Transmission Owner shall complete the work in an annual vegetation work plan to
manage the prevention of vegetation encroachments occur within the MVCD. In this way, a
violation of R1/R2 does not necessarily mean R7 is violated. The entity does not avoid a
penalty for an encroachment because a violation of R1/R2 occurs for actual encroachment.
If an encroachment occurs the compliance enforcement authority can review the entities
vegetation management plan to determine if it is compliance with R7/M7.
Response: The SDT thanks you for your comments.
1. The time required by the TO to report an issue is subject to many variables such as available communication for the area which could be a
hike-in location with no radio or cell phone coverage. For this reason it is difficult to establish a time period which would fairly apply to all
TO’s.
2. Please refer to the following responses to questions (which are responsive to your reference to your conncurrence with the United
Illuminating):
Question 1: Comment 12
Question 5: Comment 6
Question 6: Comment 44
Question 7: Comment 14
Question 8: Comment 39
7
Voter
Jason L.
Murray
Entity
Segment
Vote
Alberta Electric System
Operator
2
Negative
Comment
Due to slow vegetation growth rates in many parts of Alberta, not all transmission right-ofways require annual inspection as required in R6. TOs should be able to include planned
inspection cycles in their Transmission Vegetation Management Plan.
Response: Thank you for your comment. For the sake of consistency for all applicable entities, the SDT believes that an annual inspection
complements the required annual work plan. The standard allows for both maintenance inspections and vegetation inspections to be performed
concurrently. Additionally, annual inspections are useful to not only track growth, but also other potential issues such as identifying danger trees,
landslides, erosion, and tree damage caused by animals.
Ralph
Frederick
Meyer
Empire District Electric
Co.
1
Negative
EDE agrees with the concers raised by United Illuminating and therefore also provides the
following comments related to R7 and R4 for FAC-003-2. R4: The use of intentional time
delay is a qualitative attribute and not a quantitative measure. It will lead to endless
arguments over intentional versus non-intentional. EDE agrees with UI's comment: "In R4
the phrase: without any intentional time delay, is a concern. There is a time line between
identification and reporting of an imminent hazard that represents the minimal time
required to complete this Requirement. Any situation where the time between observation
and reporting is greater than this minimal time line indicates a time delay occurred. It will
be left to the compliance enforcement authority to determine if this delay was intentional or
not. It is not proper for the test to be based on Intentional versus Non-Intentional. Using
other synonyms such as reasonable, expeditious, prompt, immediate or without hesitation
all introduce a qualitative not a quantitative attribute to the measurement. The
Supplemental Reference for R4 indicates that the imminent threat requirement is measured
in minutes or hours; again no guidance for enforcement. R4 would be improved with an
explicit time requirement of 6 hours between observation and report. This is measurable
and clear. M4 becomes Each Transmission Owner that has a vegetation condition likely to
cause a Fault at any moment, as confirmed by qualified personnel, will have evidence that it
notified the control center holding switching authority for the associated transmission line
within 6 hours of observation." R7: R7, as proposed, requires a VMP to be completed to
ensure no encroachment occurs. The Supplemental Reference for R7 does not describe the
requirement of the annual vegetation work plan to ensure no vegetation encroachments
occur within the MVCD. The Reference states the requirement is established to diminish the
risk of encroachment; very different from ensuring no encroachment. In the reference for
R7 the word “ensure” is only used to describe that flexibility in the VMP is allowed to ensure
the reliability of the Transmission System. M7 is measuring work plan completion not the
prevention of encroachment. EDE agrees with United Illuminating suggestion that R7 be
changed to: Each Transmission Owner shall complete the work in an annual vegetation
work plan to manage the prevention of vegetation encroachments occur within the MVCD.
In this way, a violation of R1/R2 does not necessarily mean R7 is violated. The entity does
not avoid a penalty for an encroachment because a violation of R1/R2 occurs for actual
8
Voter
Entity
Segment
Vote
Comment
encroachment. If an encroachment occurs the compliance enforcement authority can review
the entities vegetation management plan to determine if it is compliance with R7/M7. EDE
also agrees with concerns raised by FMPA that Periodic data submittals as written are really
periodic self-certifications and ought to be named such, or 100% compliance reduced to a
more reasonable target
Response: Thank you for your comment. The SDT believes that it was not prudent to suggest a quantitative time element for notification in R4. The
technical reference offers examples of acceptable unintentional delays for your review. Confirmation that a threat actually exists due to vegetation is
key.
Based on comments, the language in R7 has been modified.
Robert
Martinko
FirstEnergy Energy
Delivery
1
Negative
Kevin
Querry
FirstEnergy Solutions
3
Negative
Douglas
Hohlbaugh
Ohio Edison Company
4
Negative
Kenneth
Dresner
FirstEnergy Solutions
5
Negative
Mark S
Travaglianti
FirstEnergy Solutions
6
Negative
FirstEnergy appreciates the hard work of the drafting team, but unfortunately we must cast
a Negative vote for the standard as written. If the SDT agrees with our comments below
and makes the suggested changes, we will consider supporting this standard in the
recirculation ballot. In the latest Draft 4, the SDT added a Table 3 titled "Minimum Distance
from the Centerline of the Circuit to the edge of the active transmission line ROW". We do
not support the addition of Table 3 because we believe it adds unnecessary prescriptiveness
to the requirements. It is also not clear if this Table was intended to be mandatory because
the only reference in the table is in Footnote #2. Furthermore, the SDT did not offer any
rationale for the minimum distances shown. If the SDT feels this table is a useful tool that
should be included in the standard, then we suggest adding it to the Guidelines and
Technical basis section as optional information with a discussion of the basis for the values
chosen. The standard being balloted includes an R1 and R2 detailing requirements for
managing vegetation. In addition, the SDT has asked for industry feedback on an alternate
R1/R2 through the comment form which may lead to changes to the standard after this
initial ballot. FirstEnergy supports the alternate R1/R2 but as we stated in the comment
form, we still need to see the final verbiage of the alternate R1/R2 along with their
associated measures M1 and M2 which have not yet been developed. Therefore, we cannot
support the standard until the alternate R1, R2, M1 and M2 are developed.
Response: Thank you for your comment. In response to comments regarding the addition of the “Minimum Distance from the Centerline of the
Circuit to the edge of the active transmission line ROW” Table 3, the SDT agrees to remove this table and use the new definition of Right of Way.
Additionally, language in M1/M2 has been modified based on comments received.
9
Voter
Frank
Gaffney
Entity
Florida Municipal
Power Agency
Segment
Vote
Comment
4
Negative
My biggest problem is with R1 and R2 "Each Transmission Owner shall manage vegetation
to prevent encroachment that could result in a Sustained Outage of applicable lines ....
Types of encroachment include: 1. An encroachment into the Minimum Vegetation
Clearance Distance (MVCD) as shown in Table 2, observed in real time, absent a Sustained
Outage, 2. An encroachment due to a fall-in from inside the active transmission line ROW
that caused a vegetation-related Sustained Outage, 3. An encroachment due to blowing
together of applicable lines and vegetation located inside the active transmission line ROW
that caused a vegetation-related Sustained Outage, 4. An encroachment due to a grow-in
that caused a vegetation-related Sustained Outage" One fundamental problem with all the
standards is the demand for no faults, no errors, 100% compliance. Requirements 1 and 2
basically say that any vegetation related outage, except for blow ins from outside the ROW,
is a violation. A few issues with this: How would we "prove" that an outage is vegetation
related or not, and if vegetation related, where the vegetation came from? Would this be a
"guilty until proven innocent" paradigm, e.g., if we don't know what the cause was, then we
assume guilty, or an "innocent until proven guilty" paradigm, e.g., clear evidence is needed
to prove guilt? Current compliance monitoring and enforcement methods are to assume
guilt with the need for clear evidence of innocence until a hearing is requested, at which
point the paradigm is reversed. If this is how we expect it to happen? I could see a large
number of "Possible" and "Alleged" violations where the cause of the sustained outage or
the source of the vegetation is unknown, and a large number of hearings, unless we begin
with the paradigm with "innocent until proven guilty", which is not the approach monitoring
and enforcement take currently. The requirement and the measures do not match. The
requirement is to "manage". Sometimes a well managed environment can still fail. The
measures are "failures". If the measures are failures and any failure is a violation, then, the
requirement should be to "prevent" not to "manage". Staff's proposed VSLs highlight this
inconsistency. The 100% compliance requirement, as opposed to a statistical measure such
as 99.99% availability, and Measures that say that any Sustained Outage is a possible
violation unless proven otherwise leads us to extreme methods of management, such as
possibly having video cameras monitoring the ROW at all times. Is this what the Drafting
Team intends? FMPA would suggest that if perfromance is the real purpose of these
standards, then "manage" is the wrong requirement, and "prevent" is a more appropriate
term. If prevention is the real requirement, then we need a paradigm of "innocent until
proven guilty" and any unknown source of a sustatined outage is assumed not to be a
vioaltion until proven guilty, and, 100% is not a reasonable target, 99.99% or similar umber
over a number of years (e.g., so many years rolling average) is a more reasonable target.
Do we require 100% compliance with vehicle brakes (ala Toyota Prius)? Or tire blowouts
(ala Ford Explorer)? With associated fines? If we did, the auto manufacturers would
probably not offer cars to the American market due to too much risk and liability. TQM (total
10
Voter
Entity
Segment
Vote
Comment
qulaity management) processes, such as six sigma (i.e., 6 standard deviations) do not
mandate 100% reliability becuase 100% reliability is too expensive. Rather, we need a
conservative target where outliers beyond regional management controls do not result in
huge fines and huge liability (especially in consideration with FERC's proposed Policy
Statement on Sanctions) R4 "Each Transmission Owner, without any intentional time delay,
shall notify the control center holding switching authority for the associated transmission
line when qualified personnel confirm the existence of a vegetation condition that is likely to
cause a Fault at any moment" How is R4 even measureble? How are we to measure how
someone would determine "the existence of a vegetation condition that is likely to cause a
Fault at any moment"? Having the requirement in the standard may have the unintended
consequence of reverse psychology e,g., not notifying may not even open up the question
of compliance with this requirement. However, if a sustained outage were to occur as a
result violating R1 or R2, would this requirement necessitate launching an investigation of
whether or not "qualified" personnel would have seen a problem. I see this requirement as
fraught with difficulties. Would this requirement essentially require a procedure for
"detecting" in R3 in addition to "preventing" If 100% compliance is the chosen method for
R1 and R2, why is R4 (and R5 for that matter) even needed? Obviously, if there is an
impending failure that would cause a vioaltion of R1 and R2, then there is obviously
incentive to report it to the System Operator. R7 "Each Transmission Owner shall complete
the work in an annual vegetation work plan to ensure no vegetation encroachments occur
within the MVCD. Modifications to the work plan in response to changing conditions or to
findings from vegetation inspections may be made and documented provided they do not
put the transmission system at risk of a vegetation encroachment. Examples of reasons for
modification to annual plan may include ...." The first sentence should not include the
phrase "to ensure no vegetation encroachments occur" since the requirement is to do the
work in the work plan. The added phrase sinply adds ambiguity, e.g., if there is an
encroashment, is R7 violated since it does not meet hte "unsure" phrase in addition to R1
and R2? Periodic Data Submittals Due to R1 and R2, this is really a self-certification process
because essentially only violations to R1 and R2 as curently drafted would be reported. So,
this section should be deleted in favor of a CMEP process for periodic self-certifications on
the standard.
Response: Thank you for your comments. Based on recommendations, the language in M1/M2 has been modified. Proof that an outage was
vegetation related will be determined through the investigation of the outage. If clear evidence as determined by the Transmission Owner exists, the
entity would then self-report. R4 exists to ensure that “expeditious communication between the Transmission Owner and proper operating personnel
when a critical situation is confirmed.” This situation does not necessarily imply a violation of R1 and R2. The intent is to minimize the risk of an
event that could cause a cascading event. Regarding the inclusion of the phrase “to ensure no vegetation encroachments occur” in R7, the intent of
the SDT is to include language to indicate who should do what when, where, and why as part of the Results Based Standards format.
11
Voter
Silvia P
Mitchell
Entity
Florida Power & Light
Co.
Segment
Vote
Comment
6
Negative
NextEra Energy, Inc believes that this standard is a step in the right direction; however, it is
not ready for ballot. The posted version uses the Measures and Compliance sections to
define and interpret Requirements. The Requirements should stand by themselves. This
version of the standard lumps grow-in violations with fall-in and blow-in violations. Fall-in
and grow-in violations have no correlation to the cascading events stated in the purpose.
We believe it needs more work before ballot approval.
Response: The SDT thanks you for your comment. The SDT modified R1 and R2 to incorporate the severity into the requirement. This will allow for a
graded VSL. The team also modified the measure so that it does not qualify the requirement. These changes should resolve your issues.
Larry E
Watt
Lakeland Electric
1
Negative
o The draft standard requires perfection, which is an unreasonable performance metric o
The standard is prone to arguments of whether or not an outage was caused by vegetation
encroachment in the current "guilty until proven innocent" paradigm we are currently in o
Are the requirements measurable (e.g., R4 and R5)? o Goals of requirements should not
be mixed with the requirement itself. Goals add ambiguity of what is being measured, the
requirement (e.g., "complete the work plan" in R7) or the goal (e.g., "ensure no vegetation
encroachment occurs"). o Periodic data submittals as written are really periodic selfcertifications and ought to be named such, or 100% compliance reduced to a more
reasonable target
Response: The SDT thanks you for your comments. The SDT recognizes that the Standard as written is zero tolerance and believes it is compelled to
write it that way. FERC staff and NERC assert that a revised standard cannot result in less reliability than the one it replaces, and, their belief is the
current Standard is zero tolerance. The SDT believes that R4 and R5 are measurable as described. The RBS process is essentially “Who should
perform What actions under What conditions.” Thus the Goals are included. Finally, FERC would prefer to have early warnings that reliability is at
risk, rather than wait for that indication when the next blackout occurs. Hopefully, periodic data offers that early warning detection.
David H.
Boguslawski
Northeast Utilities
1
Negative
Our main issue is with the change in the Active ROW definition. The recent addition of a
centerline distance to edge of Active ROW is not acceptable as it does not take into
consideration the construction of the line (e.g., mono-pole vs. H-frame). For mono-pole
construction, the use of the Table 3 centerline distance could result in additional clearing of
the forested edge on existing ROWs with no value added to system reliability. Instead of
using the term "Centerline" as referenced on Table 3, the use of "outer phase" or "phase
closest to tree line" would be more appropriate.
Response: The SDT thanks you for your response. Due to many commenters having issues with trying to define a “minimum” width, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way subsequently the definition of Active
Transmission Line Right of Way and Table 3 have been removed.
Mace
Hunter
Lakeland Electric
3
Negative
Perfection is not a reasionable performance metric
Response: The SDT thanks you for your comment. The SDT recognizes that the Standard as written is zero tolerance and believes it is compelled to
12
Voter
Entity
Segment
Vote
Comment
write it that way. FERC staff and NERC assert that a revised standard cannot result in less reliability than the one it replaces, and, their belief is the
current Standard is zero tolerance.
Brenda L
Truhe
PPL Electric Utilities
Corp.
1
Negative
Please refer to the Comments submitted by Earl Burnside, PPL Electric Utilities, via the NERC
Comment Form on 7/16/2010.
Response: See responses to Earl Burnside, PPL Electric Utilities.
Mark A.
Heimbach
PPL Generation LLC
5
Negative
Please refer to the comments submitted by Earl Burnside, PPL Electric Utilities, on 7/16/10.
Response: See responses to Earl Burnside, PPL Electric Utilities.
John C.
Collins
Platte River Power
Authority
1
Negative
Terry L
Baker
Platte River Power
Authority
3
Negative
PRPA appreciates the SDT’s reliability objective through a defense-in-depth strategy and the
improvements made to the standard since its last posting. However, several issues will
cause us to vote negative. Our first concern is that a violation caused by an encroachment
into the Minimum Vegetation Clearance Distance as shown in Table 2, observed in real time,
absent a Sustained Outage does not improve reliability of the BES. Instead we believe the
clearances to be achieved in the current version of the standard under R1.2. are a better
measurement of expectations because they establish a clearance to be achieved at the time
of work. Our next concern is with the ambiguity of the wording “without any intentional
time delay” in R4 of the proposed standard. For instance, would a call from the lineworkers
to his/her supervisor prior to a call to the control center constitute an intentional delay or
would that be part of the confirmation process? We also question what constitutes qualified
personnel in R4. Does this imply that R1.3. in the current standard requiring appropriate
qualifications and training is still applicable although not implicated stated and will those
qualifications be audited as they are now? Our last concern is that landowners will
intentionally constrain and delay work through court orders pointing to our Federal
requirement to take corrective action. We know this isn’t the intent of the requirement but
have some concern that it might be misinterpreted by landowners as their defense to force
us to investigate or perform alternate work methodology.
Response: Thank you for your comments. While the SDT has struggled with the issue of encroachments into the MVCD being a violation, the fact
that a TO would allow vegetation to approach, let alone encroach the MVCD indicates a serious flaw in the TO’s vegetation management program and
its application. The TO has every right and should under the proposed standard establish clearance distances at the time of work (Clearance 1 in
FAC-003-1) to allow for growth. With regard to Clearance 1 of version 1 the SDT considered it a “fill in the blank” requirement. Thus, including it in
version 2 was considered prescriptive and unnecessary.
The time required by the TO to report an issue is subject to many variables such as available communication for the area which could be a hike-in
location with no radio or cell phone coverage. For this reason it is difficult to establish a time period which would fairly apply to all TO’s. Thus, the
SDT has taken the approach which does create some subjectivity. With regard to your question regarding a call from a line worker to a supervisor
being viewed as intentional delay, we would need to know if this call is part of your process for reporting imminent threats. If your process has this
13
Voter
Entity
Segment
Vote
Comment
check point or the flexibility for the lone worker to call a supervisor, then the SDT would not view this as an intentional delay.
Qualified personnel is a function of many variables such as the size of the TO’s system, type and density of vegetation, access and complexity of the
vegetation management program. All these factors will drive the qualification requirements as defined by the TO for personnel developing and
administering the program. For instance a TO with little vegetation on its ROW may require little in the way of knowledge and methodologies in
meeting this standard while those TO’s with extensive and significant vegetation must use varied methodologies to control vegetation on its ROW
such as mechanical control, manual control, herbicides and so on. Thus, the standard leaves it to the TO to define what defines qualified personnel.
Refer to the reference document for more guidance.
As you point out, it is not the intent of this standard to cause the landowner to intentionally constrain and delay work. But, it is also not the intent of
the standard to drive the land owner or land manager to any other behaviors. It is the TO’s responsibility to manage relationships and develop
methodologies within and to the full extent of the easement or permit language. Requirement R5 deals with this issue and additional clarification is
given in the Rationale for this requirement.
David
Schumann
Florida Municipal
Power Agency
5
Negative
R1 & R2 My biggest problem is with R1 and R2 "Each Transmission Owner shall manage
vegetation to prevent encroachment that could result in a Sustained Outage of applicable
lines .... Types of encroachment include: 1. An encroachment into the Minimum Vegetation
Clearance Distance (MVCD) as shown in Table 2, observed in real time, absent a Sustained
Outage, 2. An encroachment due to a fall-in from inside the active transmission line ROW
that caused a vegetation-related Sustained Outage, 3. An encroachment due to blowing
together of applicable lines and vegetation located inside the active transmission line ROW
that caused a vegetation-related Sustained Outage, 4. An encroachment due to a grow-in
that caused a vegetation-related Sustained Outage" One fundamental problem with all the
standards is the demand for no faults, no errors, 100% compliance. Requirements 1 and 2
basically say that any vegetation related outage, except for blow ins from outside the ROW,
is a violation. A few issues with this: How would we "prove" that an outage is vegetation
related or not, and if vegetation related, where the vegetation came from? Would this be a
"guilty until proven innocent" paradigm, e.g., if we don't know what the cause was, then we
assume guilty, or an "innocent until proven guilty" paradigm, e.g., clear evidence is needed
to prove guilt? Current compliance monitoring and enforcement methods are to assume
guilt with the need for clear evidence of innocence until a hearing is requested, at which
point the paradigm is reversed. If this is how we expect it to happen? I could see a large
number of "Possible" and "Alleged" violations where the cause of the sustained outage or
the source of the vegetation is unknown, and a large number of hearings, unless we begin
with the paradigm with "innocent until proven guilty", which is not the approach monitoring
and enforcement take currently. The requirement and the measures do not match. The
requirement is to "manage". Sometimes a well managed environment can still fail. The
measures are "failures". If the measures are failures and any failure is a violation, then, the
requirement should be to "prevent" not to "manage". Staff's proposed VSLs highlight this
inconsistency. The 100% compliance requirement, as opposed to a statistical measure such
14
Voter
Entity
Segment
Vote
Comment
as 99.99% availability, and Measures that say that any Sustained Outage is a possible
violation unless proven otherwise leads us to extreme methods of management, such as
possibly having video cameras monitoring the ROW at all times. Is this what the Drafting
Team intends? FMPA would suggest that if perfromance is the real purpose of these
standards, then "manage" is the wrong requirement, and "prevent" is a more appropriate
term. If prevention is the real requirement, then we need a paradigm of "innocent until
proven guilty" and any unknown source of a sustatined outage is assumed not to be a
vioaltion until proven guilty, and, 100% is not a reasonable target, 99.99% or similar umber
over a number of years (e.g., so many years rolling average) is a more reasonable target.
Do we require 100% compliance with vehicle brakes (ala Toyota Prius)? Or tire blowouts
(ala Ford Explorer)? With associated fines? If we did, the auto manufacturers would
probably not offer cars to the American market due to too much risk and liability. TQM (total
qulaity management) processes, such as six sigma (i.e., 6 standard deviations) do not
mandate 100% reliability becuase 100% reliability is too expensive. Rather, we need a
conservative target where outliers beyond regional management controls do not result in
huge fines and huge liability (especially in consideration with FERC's proposed Policy
Statement on Sanctions) R4 "Each Transmission Owner, without any intentional time delay,
shall notify the control center holding switching authority for the associated transmission
line when qualified personnel confirm the existence of a vegetation condition that is likely to
cause a Fault at any moment" How is R4 even measureble? How are we to measure how
someone would determine "the existence of a vegetation condition that is likely to cause a
Fault at any moment"? Having the requirement in the standard may have the unintended
consequence of reverse psychology e,g., not notifying may not even open up the question
of compliance with this requirement. However, if a sustained outage were to occur as a
result violating R1 or R2, would this requirement necessitate launching an investigation of
whether or not "qualified" personnel would have seen a problem. I see this requirement as
fraught with difficulties. Would this requirement essentially require a procedure for
"detecting" in R3 in addition to "preventing" If 100% compliance is the chosen method for
R1 and R2, why is R4 (and R5 for that matter) even needed? Obviously, if there is an
impending failure that would cause a vioaltion of R1 and R2, then there is obviously
incentive to report it to the System Operator. R7 "Each Transmission Owner shall complete
the work in an annual vegetation work plan to ensure no vegetation encroachments occur
within the MVCD. Modifications to the work plan in response to changing conditions or to
findings from vegetation inspections may be made and documented provided they do not
put the transmission system at risk of a vegetation encroachment. Examples of reasons for
modification to annual plan may include ...." The first sentence should not include the
phrase "to ensure no vegetation encroachments occur" since the requirement is to do the
work in the work plan. The added phrase sinply adds ambiguity, e.g., if there is an
15
Voter
Entity
Segment
Vote
Comment
encroashment, is R7 violated since it does not meet hte "unsure" phrase in addition to R1
and R2? Periodic Data Submittals Due to R1 and R2, this is really a self-certification process
because essentially only violations to R1 and R2 as curently drafted would be reported. So,
this section should be deleted in favor of a CMEP process for periodic self-certifications on
the standard.
Response: Thank you for your comments. Your concern with respect to the cause of an outage is well-taken. As you know, transmission systems
are subject to many different influences which can cause a sustained outage. Among those causes is the encroachment of vegetation into the MVCD
which could be due to improper maintenance of vegetation on one’s ROW. However, there are many other causes which can initiate a sustained
outage. A TO usually investigate a sustained outage in the field to determine, if possible, the cause of the outage. Typically, a vegetation caused
outage will leave some evidence of the flashover such as burn marks on the conductor together with burned portions of the vegetation. Indications
may be found to explain the outage due to other causes but in some cases the cause cannot be determined and the line is successfully re-energized
without ever knowing what caused the outage. It is incumbent upon the TO to self- report those outages obviously caused by vegetation but
unexplained outages would not fall under this requirement or standard.
The SDT believes the language in the requirement matches the language in the measure such as in R1 “Each Transmission Owner shall manage
vegetation to prevent encroachment…” and in M1 “Each Transmission Owner has evidence that it managed vegetation to prevent encroachment…”.
Your suggestion of using statistical analysis may work well with large TO’s with many miles of transmission ROW to spread small numbers of
outages over but would disadvantage the small TO with significantly fewer miles of line. Only one outage on its system could result in huge fines.
The SDT believes R4 is a valid “Risk Based Requirement” giving guidance to industry on what to do upon discovery of an encroachment into the
MVCD in order to prevent a sustained outage. The key is for the TO to communicate with the appropriate switching authority and the measure is
evidence of such communication when a potential vegetation imminent threat occurs. R7, as documented in the Rationale, “…sets the expectation
that the work identified in the annual work plan will be completed as planned”. Documentation of the work completed (and any necessary
modifications) as written together with the lack of of a violation to either Requirement 1 or Requirement 2 is the overall reliability goal. The metric for
the work plan is the percentage of the plan complete. The lack of a violation of R1 or R2 is the outcome of the ideal work plan. It is the responsibility
of the TO to manage the quality of the work plan and its associated modifications to mitigate the risk of a violation of R1 or R2. With Version 2, an
outage is now clearly a violation of R1 and R2 and should not be linked to a failure of the work plan. The measure for the work plan is the percentage
of the completed as planned and we do not need to be subjectively trying to evaluate the quality of the TOs plan with this measure. With regard to
the “Periodic Reporting Data Submittal” section the SDT agrees with reporting outage to the Regional Entity on a quarterly basis. In addition
regulatory authorities are looking for leading reliability indicators which will support quarterly reporting rather than an annual self-certification.
Kenneth
Simmons
Gainesville Regional
Utilities
3
Negative
R4 The use of intentional time delay is a qualitative attribute and not a quantitative
measure. How does one judge intentional versus non-intentional on a qualitative basis;
subjective at best leading to many arguments between auditor and auditee?
Response: Thank you for your comment. We agree the time required by the TO to report an issue is subject to many variables such as available
communication for the area which could be a hike-in location with no radio or cell phone coverage. For this reason it is difficult to establish a time
period which would fairly apply to all TO’s. Thus, the SDT has taken the approach which does create some subjectivity. The key is for the TO to have
an imminent threat process that includes the communication with the appropriate switching authority. The measure for compliance will be evidence
such as written and taped radio/telephone logs maintained by the control center; written daily diaries kept by the patrollers and inspectors could
also be used for this purpose.
16
Voter
Luther E.
Fair
Entity
Gainesville Regional
Utilities
Segment
Vote
Comment
1
Negative
R4: The use of intentional time delay is a qualitative attribute and not a quantitative
measure. It will lead to endless arguments over intentional versus non-intentional. R4
should be: Each Transmission Owner shall notify the control center holding switching
authority for the associated transmission line no more than 6 hours of a qualified personnel
confirm the existence of a vegetation condition that is likely to cause a Fault at any
moment. R7: R7, as proposed, requires a VMP to be completed to ensure no encroachment
occurs. The Supplemental Reference for R7 does not describe the requirement of the annual
vegetation work plan to ensure no vegetation encroachments occur within the MVCD. The
Reference states the requirement is established to diminish the risk of encroachment; very
different from ensuring no encroachment. In the reference for R7 the word “ensure” is only
used to describe that flexibility in the VMP is allowed to ensure the reliability of the
Transmission System. The above comments are from United Illuminating and shared by
myself. Earl
Response: Thank you for your comments. We agree the time required by the TO to report an issue is subject to many variables such as available
communication for the area which could be a hike-in location with no radio or cell phone coverage. For this reason it is difficult to establish a time
period which would fairly apply to all TO’s. Thus, the SDT has taken the approach which does create some subjectivity. The key is for the TO to have
a imminent threat process that includes the communication with the appropriate switching authority. The measure for compliance will be evidence
such as written and taped radio/telephone logs maintained by the control center; written daily diaries kept by the patrollers and inspectors could
also be used for this purpose.
R7, as documented in the Rationale, “…sets the expectation that the work identified in the annual work plan will be compiled as planned”.
Documentation of the work completed (and any necessary modifications) as written together with the lack of of a violation to either Requirement 1 or
Requirement 2 is the overall reliability goal. The metric for the work plan is the percentage of the plan complete. The lack of a violation of R1 or R2 is
the outcome of the ideal work plan. It is the responsibility of the TO to manage the quality of the work plan and its associated modifications to
mitigate the risk of a violation of R1 or R2. With Version 2, an outage is now clearly a violation of R1 and R2 and should not be linked to a failure of
the work plan. The measure for the work plan is the percentage of the completed as planned and we do not need to be subjectively trying to evaluate
the quality of the TOs plan with this measure.
David A.
Lapinski
Consumers Energy
3
Negative
Table 3 does not adequately address ROW width requirements based on the type of
construction used for structures, especially for the two lower voltage classes, 69-138kV and
17
Voter
David Frank
Ronk
Entity
Consumers Energy
Segment
Vote
Comment
4
Negative
139-230 kV. Lines constructed on H-Frame structures have a much wider footprint across
the ROW than do single pole construction and most steel tower construction types. The
minimum ROW width listed in Table 3 for a 138 kV line constructed on a wooden H-Frame
may put the outside conductor within MVCD under windy conditions due to wind
displacement of conductors and trees. Consumers Energy recommends that Table 3 be
modified to describe the minimum distance in the table is the vertical plane of the outside
conductor to the edge of the active transmission ROW and therefore independent of the
width of the structure construction type. MI and M2 fail to provide examples of acceptable
forms of evidence to prove that a Transmission Owner actively managed vegetation to
prevent encroachment into the MVCD. The Measures should require proof of active ROW
clearing activity in accordance with the transmission vegetation management plan, such as
invoicing or crew field reports or vegetation inspection data from the annual vegetation
inspection R3 avoids defining a minimum clearance specification and is not practical. As
written, this would require each Transmission Owner to define and document the
procedures, processes or specification by individual span for every line owned or operated
by the Transmission Owner. Each span varies in length and profile and a single line may
have several different conductor types with different load ratings. Line loadings will vary
along the line based on substation taps, etc. The dynamics described in the language could
only be done on an individual span basis to be reasonably accurate. This is not practical
from a planning standpoint or from a standpoint of implementing clearing work in the field.
Response: The SDT thanks you for your comments.
1) Based on your comment and others, the SDT has revised the definition of Right of Way to embody the concept of an Active Transmission
Right of Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
2) M1 and M2 do provide samples of acceptable forms of evidence. The examples you have provided in your comment would also be acceptable
forms of evidence. The SDT recognizes that there are many acceptable forms of evidence and only included three specific examples in both
Measures M1 and M2 utilizing the phrase ‘may include’ so that the list is not limited to the samples provided.
R3 specifically states that the TO shall prevent encroachment into the MVCD which is a defined minimum clearance distance, contrary to your
comment. To prevent a Sustained Outage, each TO must recognize that each transmission line is unique and establish a general plan that
encompasses each scenario. In their procedures or processes or specifications, the TO shall establish a maintenance strategy that ensures
vegetation will never violate the MVCD. This strategy should take into consideration the dynamics of vegetation growth and conductor movement as
explained in the Guidelines and Technical Basis section of the Standard (Page 21). This strategy does not necessarily require a span by span
analysis.
Bernard
Pelletier
Hydro-Quebec
TransEnergie
1
Negative
Table 3 is not acceptable for HQTE. In many places, our standard of design allow us a ROW
width much narrower. We think that Table 3 should cover only the lines operated at 200 kV
or higher. Finally, the Table 3 should not be a requirement of the FAC-003-2.
Response: Based on your comment and others, the SDT has revised the definition of Right of Way to embody the concept of an Active Transmission
Right of Way subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
18
Voter
Stan T.
Rzad
Entity
Keys Energy Services
Segment
Vote
Comment
1
Negative
The draft standard requires perfection, which is an unreasonable performance metric The
standard is prone to arguments of whether or not an outage was caused by vegetation
encroachment in the current "guilty until proven innocent" paradigm we are currently in Are
the requirements measurable (e.g., R4 and R5)? Goals of requirements should not be mixed
with the requirement itself. Goals add ambiguity of what is being measured, the
requirement (e.g., "complete the work plan" in R7) or the goal (e.g., "ensure no vegetation
encroachment occurs"). Periodic data submittals as written are really periodic selfcertifications and ought to be named such, or 100% compliance reduced to a more
reasonable target
Response: The SDT thanks you for your comments.
1. The SDT recognizes that the Standard as written is zero tolerance and believes it is compelled to write it that way because FERC staff and
NERC assert that a revised standard cannot result in less reliability than the one it replaces and their belief is the current Standard is zero
tolerance.
2. As explained in M1 and M2, only real time observations confirmed by a qualified person would constitute an encroachment. There may be
some difficulty proving whether or not an outage was caused by vegetation but, if an investigation at any time reveals definitive evidence of a
vegetation contact as determined by the Transmission Owner, this would be the proof.
3. The SDT believes that R4 and R5 are measurable as described in the Draft but would gladly accept suggestions for revision in future
postings. The RBS process essentially is “Who should do what, under what conditions, when, and why?” Thus the Goals are included.
Finally, FERC staff has stated that they would prefer to have early warnings that reliability is at risk rather than wait for that indication when
the next blackout occurs. Thus, periodic data offers that early warning detection.
Periodic data submittal is not only restricted to self-certifications so the SDT has chosen to keep the language the same as currently drafted.
Thomas W.
Richards
Fort Pierce Utilities
Authority
4
Negative
The draft standard requires perfection, which is an unreasonable performance metric. Also,
the standard is prone to arguments of whether or not an outage was caused by vegetation
encroachment in the current "guilty until proven innocent" paradigm we are currently in. I
have the question about the ability to measure compliance with R4 and R5 as written. Goals
of requirements should not be mixed with the requirement itself. Goals add ambiguity of
what is being measured, the requirement (e.g., "complete the work plan" in R7) or the goal
(e.g., "ensure no vegetation encroachment occurs"). Periodic data submittals as written are
really periodic self-certifications and ought to be named such, or 100% compliance reduced
to a more reasonable target
Response: The SDT thanks you for your comments.
1. The SDT recognizes that the Standard as written is zero tolerance and believes it is compelled to write it that way because FERC staff and
NERC assert that a revised standard cannot result in less reliability than the one it replaces and their belief is the current Standard is zero
tolerance.
2. As explained in M1 and M2, only real time observations confirmed by a qualified person would constitute an encroachment. There may be
19
Voter
Entity
Segment
Vote
Comment
some difficulty proving whether or not an outage was caused by vegetation but, if an investigation at any time reveals definitive evidence
of a vegetation contact as determined by the Transmission Owner, this would be the proof.
3. The SDT believes that R4 and R5 are measurable as described in the Draft but would gladly accept suggestions for revision in future
postings. The RBS process essentially is “Who should do what, under what conditions, when, and why?” Thus the Goals are included.
Finally, FERC staff has stated that they would prefer to have early warnings that reliability is at risk rather than wait for that indication
when the next blackout occurs. Thus, periodic data offers that early warning detection.
4. Periodic data submittal is not only restricted to self-certifications so the SDT has chosen to keep the language the same as currently
drafted.
Thomas E
Washburn
Florida Municipal
Power Pool
6
Negative
The draft standard requires perfection, which is an unreasonable performance metric The
standard is prone to arguments of whether or not an outage was caused by vegetation
encroachment in the current "guilty until proven innocent" paradigm we are currently in Are
the requirements measurable (e.g., R4 and R5)? Goals of requirements should not be mixed
with the requirement itself. Goals add ambiguity of what is being measured, the
requirement (e.g., "complete the work plan" in R7) or the goal (e.g., "ensure no vegetation
encroachment occurs"). Periodic data submittals as written are really periodic selfcertifications and ought to be named such, or 100% compliance reduced to a more
reasonable target
Response: The SDT thanks you for your comments.
1. The SDT recognizes that the Standard as written is zero tolerance and believes it is compelled to write it that way because FERC staff and
NERC assert that a revised standard cannot result in less reliability than the one it replaces and their belief is the current Standard is zero
tolerance.
2. As explained in M1 and M2, only real time observations confirmed by a qualified person would constitute an encroachment. There may be
some difficulty proving whether or not an outage was caused by vegetation but, if an investigation at any time reveals definitive evidence
of a vegetation contact as determined by the Transmission Owner, this would be the proof.
3. The SDT believes that R4 and R5 are measurable as described in the Draft but would gladly accept suggestions for revision in future
postings. The RBS process essentially is “Who should do what, under what conditions, when, and why?” Thus the Goals are included.
Finally, FERC staff has stated that they would prefer to have early warnings that reliability is at risk rather than wait for that indication
when the next blackout occurs. Thus, periodic data offers that early warning detection.
4. Periodic data submittal is not only restricted to self-certifications so the SDT has chosen to keep the language the same as currently
drafted.
Laurie
Williams
Public Service
Company of New
Mexico
1
Negative
The draft standard suggests that the expectation for compliance is perfection or zero
encroachments at all times. It would be cost prohibitive to maintain the system under those
rules and should be amended to include a provision to account this issue - particularly for
small utilities that operate over very large geographic region with sparsely distributed
20
Voter
Entity
Segment
Vote
Comment
transmission assets.
Response: The SDT thanks you for your comments. The SDT recognizes that the Standard as written is zero tolerance and believes it is compelled to
write it that way because FERC staff and NERC assert that a revised standard cannot result in less reliability than the one it replaces and their belief
is the current Standard is zero tolerance.
Matt
Culverhouse
City of Bartow, Florida
3
Negative
The proposed standard requires perfection which we feel is unreasonable.
Response: The SDT thanks you for your comments. The SDT recognizes that the Standard as written is zero tolerance and believes it is compelled to
write it that way because FERC staff and NERC assert that a revised standard cannot result in less reliability than the one it replaces and their belief
is the current Standard is zero tolerance.
Robert D
Smith
Arizona Public Service
Co.
1
Negative
The reasons for APS to vote NO. The standard drafting team went above and beyond
and changed the whole standard and didn’t address all of FERC’s concerns.
(0) The minimum clearances must be sufficient to avoid any sustained vegetation-related
outages for all applicable conditions.
(1) The team eliminated clearance 1 requirement which isn’t addressed in this revision
according to FERC’s request. FERC wanted this requirement to be standardized. Elimination
of clearance 1 doesn’t give utilities leverage when dealing with federal land agencies. They
are making decisions without any education or knowledge on UVM activities which affect
transmission reliability. There needs to be a clearance 1 requirement in the standard. If
utilities are required to follow this standard it gives them leverage with dealing with these
federal land agencies.
(2) They removed ANSI-A300 from the standard. It was a footnote but should be part of the
standard. Utilities should be held to following ANSI A-300 standards and BMP’s for best
management practices. By following these standards there wouldn’t be a need for the FAC003 standard.
(3) Removal of ‘fill in the blank’ components where the Transmission Owner determines the
requirement with no limits or direction. Examples include and “personnel requirements” in
version 1. The SDT removed this requirement from the current version. ? Personnel
qualifications should be a requirement. There are certification programs through the
International Society of Arboriculture that certify a minimum level of competence to manage
a vegetation management program. This also requires ongoing training and education to
keep up with the latest technologies on UVM. ? There are other standards that require
qualifications and training.
21
Voter
Entity
Segment
Vote
Comment
(4) Application of new NERC Drafting Team Guidelines (DTG) to the standard. Examples
include the replacement of the current compliance section with Violation Risk Factors (VRFs)
and Violation Severity Levels (VSLs) as referenced in the Sanction Guidelines. Additionally,
documentation and implementation elements are separated into different requirements in
the proposed standard as required by the DTG.
(5) This requirement in regard to outages from within the ROW was diluted to remove
accountability from maintaining the full width of utilities easement. An outage is an outage
from a grow-in or from a blow in. If a utility has rights to maintain vegetation there
shouldn’t be any outages due to vegetation from blowing into the conductors. The active
ROW should be wide enough to prevent these types of outages.
o Address the applicability and appropriateness of IEEE 516 in determining clearance
distances. ? No issues with the change to Gallet equation. ?
The issue is each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of evidence
may include dated attestations, dated reports containing no Sustained Outages associated
with encroachment types 2 through 4 above, or records confirming no Real-Time
observations of any MVCD encroachments. ?
(6) A real-time observation doesn’t take into account all rated conditions and the time the
recording was made. Conditions change and if load is increased those previous observations
could be potential outages. I would assume our Energy Control people would want to be
confident there wouldn’t be any tree-related issues if load had to be increased. ? There is
technology available with LIDAR to simulate all-rated conditions, contour and tree height to
remove these potential trees hazards before an outage occurs.
o Address applicability of this standard to sub 200kV lines that could place the grid at an
unacceptable risk of instability, separation, or cascading failures. ?
(7)The utilities should be required to inspect all the lines annually. The change isn’t what
FERC requested.
o Address applicability to federal lands. ?
22
Voter
Entity
Segment
Vote
Comment
(8)There should be a footnote that if federal or state agencies fail to approve annual work
plans within 90 days of submittal the utility will not be held accountable for not completing
its annual work plan or taking into account the time it takes to get approval. We have land
agencies that give us approvals within 2 weeks and others that have taken over a year.
Utilities are at their mercy on the approval process. If there is turn-over in the land agency
the approval process changes again and it is impossible to determine the anticipated
timeline by state, tribal and federal agencies. ? The SDT didn’t address the need for FERC
oversight on federal lands as the example listed above. Agencies are not qualified to make
decisions on utility vegetation management and can change utilities TVMP.
(9)Finally the current version FAC-003-1 is performing and there is no need to make the
change.
Response: Thank you for your comments.
(0)If vegetation is maintained as required in this draft of the standard in requirements R1 and R2, then no vegetation related sustained outages,
caused by vegetation from within the ROW, within the control of the TO can occur.
(1) Clearance 1 was a fill-in the blank requirement and did not provide the TO any new easement rights, or land permit rights across any lands
whether those land be privately owned or publicly owned; therefore Clearance 1 remains removed from this draft. Furthermore, the relevance of
Clearance 1 depends on several other factors such as length of maintenance cycles, inspection frequency and growth rates. R3 is now used as a
more comprehensive method to address these concerns in lieu of a Clearance 1 requirement.
(2) In order to meet the SAR FAC-003 is required. ANSI-A300 is not sufficient to meet the SAR requirements and contains many elements that do not
need to be related to transmission system electrical reliability.
(3)The SDT suggests that the submittal of a NERC SAR on the PER standards be considered to address any proposed personnel qualifications,
certifications or training issues.
(4) The SDT is following NERC guidelines as they understand them.
(5) The SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way; subsequently the definition of
Active Transmission Line Right of Way and Table 3 have been removed. Outages arising from vegetation from outside the ROW are not violations of
the standard. The SDT had determined this to be the most appropriate assignment of an area of maintenance responsibility considering the
numerous variations in easements and permit rights across North America.
(6)The Standard requires the maintenance to be performed such that loading to Rating and Rated Conditions, and the dynamics of sag and sway are
are taken into consideration, additionally any real time observations of encroachments into the MVCD are to be reported as violations of the
standard. The SDT does not see the need to be prescriptive as to the technology or tools the TO used to be compliant with the Standard, but is
confident that if the vegetation in maintained such that no encroachments are ever observed, and no outages are ever occur, then the reliability
purpose of the standard will be fully accomplished. Furthermore, the results from a LIDAR survey are temporal in nature. Any program relying on
LIDAR would incur a substantial cost with a long term commitment that may not be justified for many Transmission Owners.
(7) FERC requested a defined period for inspection. The SDT agrees with you that annual inspection is required. Therefore the SDT has made annual
inspections a Requirement of this Standard. As to all lines versus applicable lines, FERC has accepted the 200 kV bright line for this standard. They
did order the SDT to ensure that no sub-200 kV lines that are important to the Bulk Electric System are missing from the Applicability of the standard.
23
Voter
Entity
Segment
Vote
Comment
The SDT has incorporated a FERC accepted test (as found in the referenced Standard) to make sure no such important lines are missing.
(8)The SDT agrees that erroneous obstacles to compliance with the standard should be addressed. However, they cannot be resolved in this forum,
or through language inserted in this standard. This Standard places requirements on the Transmission Owners, not on landowners. There is no
legal mechanism for this Standard to take rights from property owners and assign them to the Transmission Owner.
(9)The SDT is changing the Standard in responds to the SAR. The success of the existing standard will be preserved and enhanced with this
revision.
Paul Shipps
Lakeland Electric
6
Negative
The standard is prone to arguments of whether or not an outage was caused by vegetation
encroachment.
Response: Thank you for your comments.
The Compliance Section of the Standard provides the direction under which the Compliance Monitoring and Enforcement Processes and the TOs
must report compliance to this standard. All possible violations need adequate investigation to determine if a vegetation related outage occurred.
The SDT recognizes that such determination are often very challenging, however more prescriptive language on investigations has been seen as
necessary by the SDT and would not contribute to increased reliability. NERC also requires the TOs to document all outages and their related
causes in the TADS system.
Daniel
Brotzman
Commonwealth Edison
Co.
1
Negative
The term “Centerline of the Circuit” in Table 3 is not defined. Until it is defined, there is no
way to know if the standard is technically reasonable or whether existing circuits would be
in violation of the standard and unable to operate. In addition, it is unclear what types of
construction and span lengths were used to develop the distances for active right-of-way
widths in Table 3. Furthermore, it is not clear whether Table 3 contains requirements
against which compliance will be measured or best practice guidelines. Footnote 2, in the
background section, compounds this ambiguity. In short, the lack of a definition for
“Centerline” combined with Footnote 2 and Table 3 make this draft unclear and
unenforceable. Exelon does not necessarily have easement widths for all transmission lines
that equal those defined in Table 3 of this draft; This may require the acquisition of
additional easements, if even possible.
Response: Thank you for your comments.
In response to your comments and similar comments to yours, the SDT has revised the definition of Right of Way to embody the concept of an
Active Transmission Right of Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
Alan Gale
City of Tallahassee
5
Negative
There is still confusion in R7. If I do not complete the work plan, but do not have any
encroachments, have I violated R7? As worded I would argue no. I do not believe the
ambiguity can remain in the standard. If the goal is to complete the work plan (as modified)
leave out the "to ensure no vegetation encroachments..." If the goal is to have no
encroachments, do not rely on a work plan to exist. Make the standard "Each TO shall
ensure no vegetation encroachments occur." I do agree with the performance based
24
Voter
Entity
Segment
Vote
Comment
approach and format.
Response: Thank you for your comments. The SDT considered your response but feels that when one considers all the text in R7, M7, the Rationale
and the related VSL, along with the text in the Guidelines and Technical Basis, it is sufficiently clear that this requirement is about the completion of
the work plan.
Roger C
Zaklukiewicz
8
Negative
To maintain reliability, the minimum distance from a conductor to tall vegetation should be
measured from the conductor nearest the edge of the cleared ROW to the edge of the ROW
and not from the center line of the transmission structure. The type of transmission line
configuration, horizontal or vertical - monopole versus H-Frame versus lattice-structure
versus a V-Guided structure will influence how effective a transmission circuit's performance
or reliability is when the measurement is made from the centerline of the transmission line.
Table 3 should be modified to reflect this concern to ensure the reliability of the EPS.
Response: In response to your comments and similar comments to yours, the SDT has revised the definition of Right of Way to embody the concept
of an Active Transmission Right of Way; subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
Brian
EvansMongeon
Utility Services, Inc.
8
Negative
Utility Services supports the NPCC position on the fixes to this standard proposal.
Response: Thank you for your comments. Please refer to our response to NPCC.
John K
Loftis
Dominion Virginia
Power
1
Negative
Michael F
Gildea
Dominion Resources
Services
3
Negative
Mike Garton
Dominion Resources,
Inc.
5
Negative
We do not agree with replacing the term “Active Transmission Line Right of Way” with
footnote 2. Our objection is around the distances proposed in Table 3. Minimum Distance
from the Centerline of the Circuit to the edge of the active transmission line ROW may not
be consistent with the centerline distances cleared and maintained by the TO. For example,
a TO maintaining 75’ from centerline for a 500kV circuit would be required to clear and
maintain an additional 12.5’ to meet the proposed standard’s requirement. We suggest
either allowing individual TOs to maintain active ROW widths consistent with their normal
clearing/maintenance practices, going back to Draft 3’s definition of Active Transmission
Line Right-of-Way, or changing the footnote in Draft 4 to read: A strip or corridor of land
25
Voter
Louis S
Slade
Entity
Dominion Resources,
Inc.
Segment
Vote
6
Negative
Comment
that is occupied by active transmission facilities. This corridor does not include the parts of
the Right-of-Way that are unused or intended for other facilities. However, the portion of
the ROW that has been cleared must at least meet design clearance requirements such as
National Electric Safety Code or other design criteria, for the reliable operation of active
facilities.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has revised the definition of Right of Way to
embody the concept of an Active Transmission Right of Way; subsequently the definition of Active Transmission Line Right of Way and Table 3 have
been removed.
Ronald L
Donahey
Tampa Electric Co.
3
Negative
We have concern with the “Minimum Distances” as listed in Table 3. What analytical
methodology, criteria and rationale was utilized to determine each recommended distance?
In addition, we have concerns regarding the change to a pre-determined distance. This
seems to be a major shift from the vegetation to conductor methodology employed
previously and throughout this standard? NERC/FERC must recognize that while protecting
and securing grid reliability, each utility must also balance the environmental, political,
customer and economic issues and impacts which will occur with the implementation of the
Table 3 clearances. We question whether this is the most responsible action to take given
the current state of the economy as well as the environmental and political sensitivity
impacts which will result. Tampa Electric questions whether Table 3 will improve System
reliability. Since the inception of standard FAC-003-1 Tampa Electric has not had a Category
1 or Category 2 outage on our 230kV Transmission System. We don’t believe that the
changes proposed to table 3 will improve overall service reliability. It is Tampa Electric’s
opinion that each utility should define the width of its own Active Transmission line ROW.
However, if such a table is to be utilized, Tampa Electric recommends the following changes
or adjustments to Table 3. 1. Expand the table to account for the various types of
Transmission construction; i.e. vertical versus horizontal conductor configurations. 2. Use a
distance from the outermost conductor, not the centerline. This will account for construction
type and better achieve a consistent clearance from conductors. 3. We recommend reducing
the distances in Table 3 by 12.5 feet for each voltage category. 4. Specify whether the
voltage is based upon the design or operating voltage. 5. Reformat the voltage ranges to
100kV - 200kV, 200kV - 300kV, 300kV - 400kV, etc. as an example; this would create a
more appropriate range of voltages and clearance distances. The reformatted voltage
ranges eliminate confusion. For example, under the current proposal it is unclear in which
category a nominal 230kV line should be since sometimes such a line can operate at up to
232kV during low-load conditions.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has revised the definition of Right of Way to
embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have
been removed.
26
Voter
Joseph
O'Brien
Entity
Northern Indiana
Public Service Co.
Segment
Vote
Comment
6
Negative
While there are some enhancements to the organization and content of the standard such
as the addition of the Guidelines and Technical Basis section, clarification of what
constitutes evidence of compliance, and tailoring of VSL severity levels for the requirements
based on the risk each poses to the likelihood of contributing to a cascade, too many
elements present in FAC-003-1 and which are vital to preventing vegetation caused outages
and maximizing system reliability, have been eliminated from FAC-003-2. Specifically, the
elimination of concrete, declared and audited clearance standards between vegetation and
conductors (the existing Clearance 1 and Clearance 2 (R1.2)) Requirements) in the revised
standard is a major defect that will decrease system reliability. It has been indispensable for
NIPSCO when communicating with stake holders (governments, interest groups, land
owners, the public, etc.) to point to these clearance standards to give credibility and support
to the kind of tree removal and trimming that is necessary to achieve the stated objective of
zero preventable tree caused outages. Without these declared clearance standards in the
NERC standard, utility vegetation managers will constantly be challenged by stake holders
to show them that such work is required rather than an elective choice on the utility's part.
One of the key lessons learned from the 2003 blackout and First Energy's overgrown ROW
tree problem was that individual land owners, local governments, and interest groups will
exert pressure on the utility to only do the minimum amount of vegetation management.
Without external and enforceable Vegetation Clearance Standards and by returning to a
pre-2003 regime where the extent of vegetation clearing is left to the individual discretion
and pressures at each utility, there is no doubt that tree clearance conditions will deteriorate
over time and put system reliability at greater risk of vegetation contact
Response: The SDT thanks you for your comments. At the request of FERC in Order 693, the SDT was asked to eliminate the fill-in-the-blank
clearance requirements that are currently in FAC-003-1. A proven Engineering calculation was utilized to determine when a transmission line could
spark over to vegetation without direct contact. Based on this calculation, each utility must determine what clearance levels need to be maintained
as part of their TVMP. The current version does not preclude a utility from removing or pruning vegetation well beyond the MVCD, it just establishes
a line in the sand that determines when a violation occurs. Individual TOs must establish a program that addresses the many variables that exist
such as growth rates, vegetation management cycles, conductor sag and sway, etc. that could result in an encroachment of the MVCD which would
be a direct violation of the standard. Establishing a specific clearance value to be attained during vegetation management activities is too
prescriptive and is in direct conflict with the Results-Based Standard initiative that the SDT is currently implementing. Each TO must factor in delays
and/or mitigation measures associated with stakeholder concerns but must clearly communicate the challenges with maintaining strict compliance
with this zero-tolerance standard.
27
Voter
Entity
Segment
Vote
Comment
Greg Lange
Public Utility District
No. 2 of Grant County
3
Negative
While this standard as written is a marked improvement to previous versions, to claim R1
and R2 as results based is simply not right. Had this standard revision not been advertised
as the first RBS I probably would have voted yes. Results based by definition should be
attained by something either happening or not and should be based on evidence that
already exists. If you cause an outage and it is vegetation related then you violate. Why all
the words around "managing vegetation encroachment" take care of that in the competency
requirements.
Response: The SDT thanks you for your comments. In a Results Based Standard, there are three different levels of defense to achieve the desired
outcome (performance-based requirements, risk-based requirements and competency based requirements). R1 and R2 are considered PerformanceBased requirements and are one component in the defense-in-depth strategy that is described in the Background Section of the current Draft. The
MVCD is the minimum clearance distance before a spark-over occurs so R1 and R2 were designed to ensure that the TO manages vegetation
appropriately before an outage occurs. If the TO was judged based on outages alone, the defense in depth strategy would fail and, thus, a less
reliable standard would exist.
Gregory L
Pieper
Xcel Energy, Inc.
1
Negative
Michael
Ibold
Xcel Energy, Inc.
3
Negative
Liam
Noailles
Xcel Energy, Inc.
5
Negative
David F.
Lemmons
Xcel Energy, Inc.
6
Negative
Xcel Energy votes Negative for several reasons which are outlined in the comments
submitted to NERC during the comment period that ran concurrently with this ballot. One of
the primary objections is the requirement for an annual vegetation inspection. Xcel Energy
urges the retention of the provision in the existing standard that allows the Transmission
Owner to set the frequency of inspection.
Response: The SDT thanks you for your comments. In FERC Order 693, the SDT was asked to look at setting a specific frequency for vegetation
inspections across North America. This was a difficult task since vegetation characteristics vary across the continent but the team voted to accept
an annual inspection frequency as a minimum and provide utilities the flexibility to include this mandatory vegetation inspection as part of a general
line inspection.
Terry
Harbour
MidAmerican Energy
Co.
1
Affirmative
Thomas C.
Mielnik
MidAmerican Energy
Co.
3
Affirmative
All rationale boxes should have a disclaimer at the top to the effect "For Guidance Only, Not
for Enforcement".
Response: The SDT thanks you for your affirmative votes and comments. A “disclaimer” is addressed by the Standards Committee Process
Subcommittee however its location remains under discussion.
28
Voter
Guy V. Zito
Entity
Northeast Power
Coordinating Council,
Inc.
Segment
Vote
Comment
10
Affirmative
Although NPCC and its members support the results based initiative and this proof of
concept standard and format, there has been some concern with the proposed FAC-003-2.
Some of NPCC's members that have active vegetation management programs have stated
that in the application of Table 3 - specifically, the use of a "Minimum Distance from the
Centerline of the Circuit". Mono-pole and frame construction have significantly different
footprints which don't support a one size fits all approach. The use of Table 3 for 345kV,
mono-pole construction could result in excessive clearing of additional forested edge on
existing ROWs with little if any value added to system reliability and at great cost. There is
an issue with use of the term "easements" in the definition and seek clarification on several
questions-is there a reason the Active ROW only includes easements not fee ownership,
license or some other right to occupy and manage the ROW? Would active ROW include
"danger tree rights" on land? Not all entities that own transmission facilities and have
vegetation management programs agree with these statements however there is cause
enough for concern. In addition, this standard represents a "proof of concept for the
"reliability based standards" initiative NERC is putting forward. NPCC RSC believe this
initiative will result in better standards over time.
Response: The SDT thanks you for your affirmative vote and comments. Based on your comment and others, the SDT has revised the definition of
Right of Way to embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active Transmission Line Right of Way
and Table 3 have been removed.
Jason
Shaver
American
Transmission
Company, LLC
1
Affirmative
ATC raises a concern on including Rationale Boxes plus Guidelines and Technical Basis as
part of the NERC Reliability Standard. ATC recommends that the SDT either remove these
sections or make them separate from the formal standard to eliminate any risk that these
may be construed as requirements. An alternative method is to very clearly identify which
parts of the standard are subject to compliance and considered mandatory and which are
not considered requirements and are only for guidance in meeting the requirements.
Response: The SDT thanks you for your affirmative vote and comments. A “disclaimer” is addressed by the Standards Committee Process
Subcommittee however its location remains under discussion.
Horace
Stephen
Williamson
Southern Company
Services, Inc.
1
Affirmative
Richard J.
Mandes
Alabama Power
Company
3
Affirmative
Anthony L
Wilson
Georgia Power
Company
3
Affirmative
Comments for this ballot are included in the Southern Company submitted comment form Project 2007-07: Transmission Vegetation Management.
29
Voter
Entity
Segment
Vote
Gwen S
Frazier
Gulf Power Company
3
Affirmative
Don Horsley
Mississippi Power
3
Affirmative
Comment
Response: The SDT thanks you for your affirmative votes and comments. Please refer to the SDT responses in the Comment Report.
Ajay Garg
Hydro One Networks,
Inc.
1
Affirmative
Michael D.
Penstone
Hydro One Networks,
Inc.
3
Affirmative
Hydro One would like to submit the following comments for consideration of the SDT. 1. In
the application of Table 3 - specifically, the use of a "Minimum Distance from the Centerline
of the Circuit", Mono-pole and frame construction have significantly different footprints
which don't support a one size fits all approach. The use of Table 3 for 345kV, mono-pole
construction could result in excessive clearing of additional forested edge on existing ROWs
with little if any value added to system reliability and at great cost. 2. The use of the term
"easements" in the definition needs clarification. For example, is there a reason the Active
ROW only includes easements and not ownership, license or some other right to occupy and
manage the ROW? Would active ROW include "danger tree rights" on land?
Response: The SDT thanks you for your affirmative vote and comments. Based on your comment and others, the SDT has revised the definition of
Right of Way to embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active Transmission Line Right of Way
and Table 3 have been removed.
Richard J.
Padilla
Pacific Gas and
Electric Company
5
Affirmative
In principle we agree but we have the following concerns: Removes reference to ANSI A300
as an effective management strategy to comply with the standard. We often point to ANSI
A300 to support our position of "wire zone - border zone" vegetation management practices
in public education and legal disputes. However, Eastern and Southern utilities, who
dominate the VMSDT, feel that ANSI A300 places constraints on their desire to perform bare
ground clearing, which A300 and PG&E does not endorse. Most Western utilities support
retaining reference to A300. Minimum clearance distances have been reduced from the
current IEEE 516 distances to the distances derived from the Gallet equation. Reduced
clearance distances make it more difficult to justify some work with property owners. FERC
and NERC have also stated they are opposed to reduced clearances. The VMSDT spent
much time and effort to construct the standard in a manner where there is violation
gradation within some requirements. NERC and FERC have indicated they disagree with the
latitude to ignore the VSL's as proposed
Response: The SDT thanks you for your affirmative vote and comments. The proposed draft of FAC-003-2 continues to make reference to ANSI A300
as a best practice but short of endorsement into a requirement. This represents the best compromise that the team could achieve.
Use of the Gallet Equation, contrary to your comment, provides for greater distances than IEEE-516-2003 under the same conditions of elevation,
voltage and transient overvoltage factor. Please refer to the Technical Reference Document (posted on NERC webpage) for more information.
The SDT indeed has worked hard to achieve a technically valid set of VSLs for this standard and believe its perspective is correct.
30
Voter
Entity
Segment
Vote
Comment
MEAG is voting yes in support of the improvements and significant effort that went into
modifying FAC-003-2 with the understanding that the vegetation management standard will
continue to develop and evolve. Vegetation management’s increased visibility and
dramatically increased oversight is resulting in increasingly defined and demanding
language contained in the standard’s requirements. Some of the new requirements
overreach but the intent is clear, create and manage a vegetation management program to
prevent outages that potentially create a cascading outage threat. As the application of this
new standard is reviewed over time, improved requirements and measures based on
experience and results should be used to further improve the standard. Additional lines of
lesser voltages will now be included under this standard. The tendency may be to include a
line when in doubt even if there is a remote possibility that it can potentially cause a threat
of a cascading outage. The same philosophy will occur with rights-of-way. The legal rightof-way will be cleared even if it was secured for a future line of greater voltage. We need to
continue to review FAC-003-2 for future improvements to achieve reasonableness in
protecting against cascading outages without heaping unnecessary costs on electric
consumers.
Steven
Grego
MEAG Power
3
Affirmative
Steven M.
Jackson
Municipal Electric
Authority of Georgia
3
Affirmative
Response: The SDT thanks you for your affirmative vote and comments. The SDT agrees with your comments.
Michael T.
Quinn
Oncor Electric Delivery
1
Affirmative
Oncor believes that the proposed standard is a significant improvement over the current
standard. We strongly support the suggested VSL’s as proposed by the VMSDT. However,
we also take the position that adoption of a virtual binary VSL to describe an encroachment
without an outage, as a high VSL doesn’t adequately address the different levels of
encroachment and any potential impact that could lead to Cascading. Oncor is not aware of
any vegetation fall-ins or blow-ins that have caused or have lead to Cascading.
Response: The SDT thanks you for your affirmative vote and comments. The SDT has worked hard to achieve a technically valid set of VSLs for this
standard and believe its perspective is correct.
Chifong L.
Thomas
Pacific Gas and
Electric Company
1
Affirmative
PG&E believes this version is an improvement over the last draft. However, PG&E is
concerned with the removal of the reference to ANSI A300 as an effective management
strategy to comply with the standard. ANSI A300 provides clarity on the "wire zone - border
zone" vegetation management practices. PG&E is also concerned that the minimum
clearance distances have been reduced from the current IEEE 516 distances to the
distances derived from the Gallet equation. Reduced clearance distances make it more
difficult to implement certain types of work needed to support reliability.
Response: The SDT thanks you for your affirmative vote and comments. The proposed draft of FAC-003-2 continues to make reference to ANSI A300
as a best practice but short of endorsement into a requirement. This represents the best compromise that the team could achieve.
31
Voter
Scott M.
Helyer
Entity
Tenaska, Inc.
Segment
Vote
5
Affirmative
Comment
Please note that further changes may be needed to this standard to address issues related
to generation interconnection facilities per other standards development efforts.
Response: The SDT thanks you for your affirmative vote and comments. The SDT is aware that a separate Project 2010-07 Transmission
Requirements at the Generator Interface is underway to address the issue you raise.
Brandy A
Dunn
Western Area Power
Administration
1
Affirmative
Please see comments provided on Official Comment Form
Response: The SDT thanks you for your affirmative vote and comments. Please refer to the responses in the Comment Report.
Donald S.
Watkins
Bonneville Power
Administration
1
Affirmative
Rebecca
Berdahl
Bonneville Power
Administration
3
Affirmative
Francis J.
Halpin
Bonneville Power
Administration
5
Affirmative
Brenda S.
Anderson
Bonneville Power
Administration
6
Affirmative
Regarding footnote number 2, and the description of an "Active Transmission Line Right of
Way", BPA has the following comments: The distance is reasonable in the table, but due to
widely varying designs of structures it does not give a relationship of the outside wire to
edge of ROW. It should be noted as outside wire, phase or conductor to edge of ROW. In
addition, the effective date should allow transmission owners time to achieve this distance,
perhaps one cycle. Other Comments: The basis of managing vegetation to MVCD in Table 2
( essentially withstand distances) will likely prove problematic. BPA believes NERC should
develop an additional table that calls out minimum "buffers" based on attributes such as line
voltage, line rating etc. This table should be a companion to Table 2. It is NERC's
responsibility to regulate and we believe that they should do so. In this case, the loss of
flexibility for the owners is not necessarily a bad thing.
Response: The SDT thanks you for your affirmative votes and comments. Based on your comment and others, the SDT has revised the definition of
Right of Way to embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active Transmission Line Right of Way
and Table 3 have been removed.
Tim Kelley
Sacramento Municipal
Utility District
1
Affirmative
James
LeighKendall
Sacramento Municipal
Utility District
3
Affirmative
Mike
Ramirez
Sacramento Municipal
Utility District
4
Affirmative
Bethany
Wright
Sacramento Municipal
Utility District
5
Affirmative
SMUD appreciates the efforts of the Drafting Team. However, use of the phrase “intentional
time delay” in R4 no clear definitive time frame for “intentional time delay” this leads to
difficulty in its definition. SMUD respectively offers the recommendation for the DT to use a
term along the lines of “expeditious.”
Response: The SDT thanks you for your affirmative votes and comments. The SDT struggled with the selection of language in R4 and considered
your term among many others. The team ended up with the drafted version as the best compromise.
32
Voter
Marjorie S.
Parsons
Entity
Tennessee Valley
Authority
Segment
Vote
Comment
6
Affirmative
Suggest a clarifying change to the language in footnote 2 and or Table 3 to address those
lines that have ROW width variations from the prevailing width due to factors unrelated to
the needs for vegetation maintenance for the subject line. Add the following sentence to
footnote 2 “The widths and distances in Table 3 shall be that prevailing width of the ROW
exclusive of any variations in the prevailing width due to factors unrelated to the needs for
vegetation maintenance for the subject line.” TVA asserts that the new language in R1, R2,
M1, and M2 in concert with new language in R3 and M3 are fully adequate and superior to
any of the proposed alternative A-F. TVA asserts that the VSLs as proposed by the SDT are
appropriate since they reflect in various degrees the typical types of right of way
maintenance failure. For example vegetation removal from under the conductors should be
the highest priority work, followed by vegetation removal in the side-growth/blow-out areas,
and lastly of all fall-in risks should be removed. TVA suggests that another sentence be
added to the end of Section 4.4 Other, as follows: Nothing is this Standard is shall be used
to require the Transmission Owner to acquire additional easement rights beyond those
currently owned, or to perform any maintenance outside the limits of its legal rights.
Response: The SDT thanks you for your affirmative vote and comments. Please see drafting team responses to your same comments in the
Comment Report.
Paul B.
Johnson
American Electric
Power
1
Affirmative
Edward P.
Cox
AEP Marketing
6
Affirmative
The VSL chart states that it is a Lower Violation if the TO has an encroachment into the
MVCD observed in real time, absent a sustained outage. While the Moderate and High
categories specifically note that the reference is to inside the right-of-way, the Lower level
does not. Should the Lower category read: " The Transmission Owner has an encroachment
into the MVCD from inside the right-of-way in real time, absent a Sustained Outage"?
Response: The SDT thanks you for your affirmative votes and comments. The suggested edit has been considered and the SDT determined that no
change to the VSL would be made.
Robert
Smith
Duke Energy
5
Affirmative
This Version 2 of FAC-003 takes a big step forward to clarify expectations and compliance
with the standard. The results-based format is a big improvement.
Response: The SDT thanks you for your affirmative vote and comment.
33
Voter
George T.
Ballew
Entity
Tennessee Valley
Authority
Segment
Vote
5
Affirmative
Comment
TVA suggests a clarifying change to the language in footnote 2 and or Table 3 to address
those lines that have ROW width variations from the prevailing width due to factors
unrelated to the needs for vegetation maintenance for the subject line. Add the following
sentence to footnote 2 “The widths and distances in Table 3 shall be used as the prevailing
width of the ROW regardless of any variations in width due to factors unrelated to the
needs for vegetation maintenance for the subject line.” TVA asserts that the VSLs as
proposed by the SDT are appropriate since they reflect in various degrees the typical types
of right of way maintenance failure. For example vegetation removal from under the
conductors should be the highest priority work, followed by vegetation removal in the sidegrowth/blow-out areas, and lastly of all fall-in risks should be removed. TVA suggests that
another sentence be added to the end of Section 4.4 Other, as follows: Nothing in this
Standard shall be used to require the Transmission Owner to acquire additional easement
rights beyond those currently owned, or to perform any maintenance outside the limits of
its legal rights.
Response: The SDT thanks you for your affirmative votes and comments. Based on your comment and others, the SDT has revised the definition of
Right of Way to embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active Transmission Line Right of Way
and Table 3 have been removed.
The SDT agrees with your comment on the VSLs, and the SDT points out that the following sentence at the end of Section 4.4 is comparable to your
suggestion, “Nothing in this section should be construed to limit the Transmission Owner’s right to exercise its full legal rights on the ROW.”
Spencer
Tacke
Modesto Irrigation
District
4
Affirmative
We approve of the proposed revised standard as written. However, we have a concern
about the Minimum Vegetation Clearance Distance (MVCD) of 2.97 feet shown in Table 2 for
230kV lines, as being too small. We will continue to maintain a much larger clearance than
specified in Table 2, and in this case, no less than 10 feet of clearance for 230kV lines,
taking into consideration the maximum sag designed for a given line. Thank you.
Response: The SDT thanks you for your affirmative vote and comments. The MVCD was set up to be a “minimum” distance to never violate.
Certainly, each TO must maintain larger clearances in order to account for growth, movement of conductor and other factors that influence the
distance between the conductor and vegetation. Use of the Gallet Equation provides for greater distances than IEEE-516-2003 under the same
conditions of elevation, voltage and transient overvoltage factor. Please refer to the Technical Reference Document (posted on NERC webpage) for
more information.
James L.
Jones
Southwest
Transmission
Cooperative, Inc.
1
Abstain
Entities have a problem with other Government Agencies in tha they are not real receptive
for Vegetation Management. Burea of Land Management will usually take 2 years to get
permission to trim vegetation in BLM ROW. State Land Department will usually not let you
cut any cactuses in ROW on State land. ROW crossing on a Sovereign Indian Reservation is
just as bad. If this is such a big issue for FERC/NERC, then they need to get other
governmental agencies on board with them.
34
Voter
Entity
Segment
Vote
Comment
Response: The SDT thanks you for your comments. Jurisdictional issues need to be addressed in other appropriate arenas. The Utility Arborist
Association among other groups have sought to coordinate cooperation between agencies in the past.
35
Consideration of Comments on 4th Draft of FAC-003-2 Transmission Vegetation
Management —Project 2007-07 Vegetation Management
The Vegetation Management Standard Drafting Team thanks all commenters who submitted
comments on the 4th draft of reliability standard FAC-003-2 — Transmission Vegetation
Management. This standard and its associated implementation plan and technical reference
paper were posted for a 30-day public comment period from June 17, 2010 through July 17,
2010. The stakeholders were asked to provide feedback on the standard through a special
Electronic Comment Form. There were 45 sets of comments, including comments from more
than 100 different people from over 50 companies representing 7 of the 10 Industry Segments
as shown in the table on the following pages.
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
The standard and its associated implementation plan and technical reference paper were
balloted from July 9 – 19, 2010. The voting had a quorum of 86.18 percent and an affirmative
vote of 65.93 percent. Because at least one negative ballot included a comment and the
affirmative votes did not meet the two thirds threshold for approval, the results were not final.
On November 4, 2010, NERC staff provided a Quality Review of FAC-003-2 to the Standards
Committee (SC). The SC met on November 11, 2010 to determine if the draft standard should
proceed to posting. During the meeting, the SC requested the Vegetation Management
Standard Development Team (VMSDT) to work with NERC staff in addressing the items
identified in the Quality Review. The VMSDT conducted several conference calls and acted in
good faith to produce Draft 5 of FAC-003-2. The VMSDT considered the feedback provided in
the Quality Review by NERC staff and reached consensus in the following areas:
1. Elaborated upon the Purpose Statement to encompass more of the standard’s content.
2. Added a Rationale text box to the section 4 - Applicability to explain the exclusion of
substation facilities. Clarified 4.2.4 by adding specific boundary details.
3. Updated Requirement R1 and R2 to emphasize the “planning” time horizon as the
applicable temporal context.
4. Elaborated upon the explanation in the Rationale text boxes for R1 and R2 to highlight
the range of non-compliant performance.
5. Re-organized the content of Requirement R3 for improved readability.
6. Augmented Requirement R5 to include a “reliability objective”.
7. Modified Requirement R6 and the associated VSLs for improved enforceability and for
consistency in the units of measure between the Requirement and the associated VSLs.
8. Modified Requirement R7 and the associated VSLs for improved enforceability and for
consistency in the units of measure between the Requirement and the associated VSLs.
9. Updated the Evidence Retention section in accordance with current guidelines.
Modifications incorporated into Draft 5 of FAC-003-2 in response to stakeholder comments
include:
A. Removed reference to Active Transmission Line Right of Way (ROW).
B. Redefined the Glossary term for ROW to address Paragraph 734 of FERC Order 693
addressing the width of ROW to be maintained.
C. Redefined the Glossary term for Vegetation Inspection to include identifying hazards to
the line inside the ROW.
D. Included the term referred to as “applicable lines” under Section 4.2 Facilities.
E. Removed Section4.4 and footnote 2 addressing “force majeure” and addressed the
issue in new footnotes 2, 3 and 4.
F. In R1./R2 – M1/M2
• Added reference “into the MVCD” (Minimum Vegetation Clearing Distance – MVCD)
into the text.
• Eliminated “types of encroachment” and added “The four types of failure to manage
vegetation, in order of increasing severity.”
• In M1/M2, added a paragraph defining “later confirmation of a Fault by the TO as a
real-time observation.”
• Added to the Rationale box types of failures to manage vegetation.
G. In R4, changed “qualified personnel” to TO.
H. In R5, added the term “is constrained from performing vegetation work” and referenced
MVCD. Also removed reference to the 2003 northeast blackout from Rationale box
I. In R6, added the phrase “ but no more than 18 months between inspections.” Also
added Footnote 3.
J. In R7, replaced major storms bullet with “circumstances that are beyond the control of a
Transmission Owner.” Also added Footnote 4 to this requirement.
K. In Additional Compliance Information
• Category 2 was split into two parts recognizing Interconnection Reliability Operating
Limits (IROL’s) and Major Western Electric Coordinating Council (WECC) Transfer
Paths.
• Added Category 3 for Fall-ins from outside the ROW.
• Category 4 was split into two parts recognizing IROL’s and Major WECC Transfer
Paths
L. Removed alternate versions of Violation Severity Levels (VSL’s) for Requirements R1
and R2.
M. Deleted Table 3 from the Guidelines and Technical Basis section.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is
to give every comment serious consideration in this process! If you feel there has been an error
or omission, you can contact the Vice President and Director of Standards, Herb Schrayshuen,
at 609-452-8060 or at [email protected]. In addition, there is a NERC Reliability
Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Index to Questions, Comments, and Responses
1.
2.
3.
4.
5.
6.
7.
8.
The SDT replaced the defined term “Active Transmission Line Right of Way”
with footnote number 2 that provides a description of “active transmission
line ROW” and added Table 3, “Minimum Distance from the Centerline of the
Circuit to the edge of the active transmission line ROW” to support that
description. Do you agree? Please explain. ..................................................... 10
In response to comments received regarding the terms “reasonable” and
“human errors/human activity”, the SDT modified the Other Section and
Background Section. Do you agree? Please explain. ....................................... 28
In response to comments received regarding the language in M1 and M2, the
SDT modified the first bulleted item and added a sentence to the end of the
paragraph in M1 and M2. Do you agree? Please explain. ................................ 35
In response to comments received that requirement R3 is deficient in detail,
the SDT modified the requirement. Do you agree? Please explain. ................. 46
In response to comments received that requirement R7 is unclear with respect
to flexible work plans, the SDT modified the requirement. Do you agree?
Please explain. ............................................................................................... 57
In response to comments received that requirement R1/R2 may not
adequately protect the transmission conductors under all conditions of sag
and sway, the SDT drafted alternate language for the industry to provide
feedback. The SDT did not opt to incorporate this language into “Draft 4” until
further comment was solicited from industry. Which do you prefer? Please
comment on your choice in the comment box below: ..................................... 68
The drafting team and NERC staff disagree on an appropriate set of VSLs for
Requirements R1 and R2 and the Standards Committee has directed that both
sets of VSLs be posted for stakeholder comments. Which set of proposed VSLs
best supports NERC’s VSL Criteria? ................................................................ 82
Is there anything that you have not addressed above regarding the draft FAC003-2 Transmission Vegetation Management standard or the Technical
Reference Document? If yes, please provide what you believe should be
changed, added or deleted and the rationale for your proposal. ..................... 94
3
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Commenter
1.
Group
Guy Zito
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
Northeast Power Coordinating Council
Additional Member
10
X
Additional Organization
Region
Segment Selection
1. Alan Adamson
New York State Reliability Council, LLC
NPCC
10
2. Gregory Campoli
New York Independent System Operator
NPCC
2
3. Kurtis Chong
Independent Electricity System Operator
NPCC
2
4. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
5. Michael Schiavone
National Grid
NPCC
1
6. Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
7. Dean Ellis
Dynegy
NPCC
5
8. Ben Eng
New York Power Authority
NPCC
4
9. Brian Evans-Mongeon
Utility Services
NPCC
8
10. Peter Yost
Consolidated Edison Co. of New York, Inc.
NPCC
3
11. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC
5
12. Kathleen Goodman
ISO - New England
NPCC
2
13. Chantel Haswell
FPL Group, Inc.
NPCC
5
14. David Kiguel
Hydro One Networks Inc.
NPCC
1
15. Michael R. Lombardi
Northeast Utilities
NPCC
1
4
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
16. Randy MacDonald
New Brunswick System Operator
NPCC
2
17. Bruce Metruck
New York Power Authority
NPCC
6
18. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
10
19. Robert Pellegrini
The United Illuminating Company
NPCC
1
2.
Group
Denise Koehn
Bonneville Power Administration
Additional Member
X
Additional Organization
X
X
Region
WECC
1
2. Steve Narolski
BPA, Tx Vegetation/Access Road Mgmt
WECC
1
3. Vince Ierulli
BPA, Transmission Line Design
WECC
1
4. Frank Weintraub
BPA, Transmission Line Design
WECC
1
5. Daniel Tuominen
BPA, Transmission Line Design
WECC
1
6. Joel Billings
BPA, Transmission Line Design
WECC
1
7. Michael Staats
BPA, Transmission Engineering
WECC
1
8. Don Swanson
BPA, Transmission Line Maintenance Technical Svcs
WECC
1
Sasa Maljukan
Additional Member
Hydro One
Additional Organization
Region
Segment Selection
Hydro One Networks Inc.
NPCC
1
2. Patrick HOWE
Hydro One Networks Inc.
NPCC
1
3. Leslie KOCH
Hydro One Networks Inc.
NPCC
1
4. Jonathan MARRIOTT
Hydro One Networks Inc.
NPCC
1
Group
Richard Kafka
Additional Member
Pepco Holdings, Inc - Affiliates
X
Additional Organization
X
X
X
Region
Segment Selection
1. Pat Byrne
Potomac Electric Power Company
RFC
1
2. Dave Paduda
Potomac Electric Power Company
RFC
1
3. Steve Benn
Delmarva Power & Light
RFC
1
4. Olivia Watts
Atlantic City Electric
RFC
1
5.
Group
Joseph DePoorter
10
X
1. David kiguel
4.
9
Segment Selection
BPA, Tx Vegetation/Access Road Mgmt
Group
8
X
1. Chuck Sheppard
3.
7
MRO’s NERC Standards Review Subcommittee
(nsrs)
X
5
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Commenter
Organization
Additional Member
Industry Segment
1
Additional Organization
2
3
4
5
6
Region
7
OPPD
MRO
1, 3, 5, 6
2. Chuck Lawrence
ATC
MRO
1
3. Tom Webb
WPSC
MRO
3, 4, 5, 6
4. Jason Marshall
MISO
MRO
2
5. Jodi Jenson
WAPA
MRO
1, 6
6. Ken Goldsmith
ALTW
MRO
4
7. Dave Rudolph
BEPC
MRO
1, 3, 5, 6
8. Eric Ruskamp
LES
MRO
1, 3, 5, 6
9. Joseph Knight
GRE
MRO
1, 5, 6
10. Joe DePoorter
MGE
MRO
3, 4, 5, 6
11. Scott Nickels
RPU
MRO
4
12. Terry Harbour
MEC
MRO
1, 3, 5, 6
13. Carol Gerou
MRO
MRO
10
Group
Sam Ciccone
FirstEnergy
Additional Member
X
Additional Organization
X
X
X
Region
Segment Selection
1. Rebecca Spach
FE
RFC
1
2. Katrina Schnobrich
FE
RFC
1
3. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
4. Dave Folk
FE
RFC
1, 3, 4, 5, 6
7.
Group
Michael Gammon
Kansas City Power & Light
Additional Member
X
Additional Organization
X
X
X
Region
Segment Selection
1. Jennifer Flandermeyer
KCPL
SPP
1, 3, 5, 6
2. Duane Ansteate
KCPL
SPP
1, 3, 5, 6
3. Dean Beasley
KCPL
SPP
1, 3, 5, 6
8.
Group
Mallory Huggins
NERC Staff
Additional Member
1. Robert Novembri
9
Segment Selection
1. Mahmood Safi
6.
8
Additional Organization
NERC
Region
NA - Not Applicable
Segment Selection
NA
6
10
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
2. Gerry Adamski
NERC
NA - Not Applicable
NA
3. Joel deJesus
NERC
NA - Not Applicable
NA
4. Valerie Agnew
NERC
NA - Not Applicable
NA
5. Mike DeLaura
NERC
NA - Not Applicable
NA
6. Maureen Long
NERC
NA - Not Applicable
NA
7. David Taylor
NERC
NA - Not Applicable
NA
8. Herb Schrayshuen
NERC
NA - Not Applicable
NA
9.
Group
Louis Slade
Additional Member
Dominion
X
Additional Organization
X
X
7
8
9
10
X
Region
Segment Selection
1. Aaron Jonas
SERC
1
2. John Loftis
SERC
3
3. Mike Garton
5
10.
Individual
Brandy A. Dunn
Western Area Power Administration
X
11.
Individual
Jana Van Ness
Arizona Public Service Company
X
12.
Individual
Steve Rueckert
Western Electricity Coordinating Council
13.
Individual
Luke Diruzza
Tampa Electric Company
X
14.
Individual
Silvia Parada Mitchell
FPL FPL Corporate Compliance
X
15.
Individual
JT Wood
Southern Company Transmission
X
16.
Individual
Linwood Blacksmith
Tri-State Generation & Transmission
X
17.
Individual
David Burke
Orange and Rockland Utilities, Inc.
X
18.
Individual
Weston Davis
Central Maine Power Company, Iberdrola USA
X
19.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
20.
Individual
Jonathan Appelbaum
The United Illuminating Company
X
21.
Individual
Patrick Simons
Idaho Power Company
X
22.
Individual
Sam Stonerock
Southern California Edison Company
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
7
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
X
23.
Individual
Marty Berland
Progress Energy
X
X
X
24.
Individual
John Bee
Exelon
X
X
X
25.
Individual
Hugh Conley
Allegheny Power
X
26.
Individual
Edward Davis
Entergy Services
X
X
X
X
27.
Individual
Jon Kapitz
Xcel Energy
X
X
X
X
28.
Individual
Gordon Rawlings
BC Hydro
X
X
X
29.
Individual
Bill Rees
BGE Forestry Management
X
30.
Individual
Michael R. Lombardi
Northeast Utilities
X
X
X
31.
Individual
Bryan Taylor
Idaho Power
X
32.
Individual
Anne Beard
PNM
X
X
33.
Individual
James Sharpe
South Carolina and Gas
X
X
X
X
34.
Individual
Greg Rowland
Duke Energy
X
X
X
X
35.
Individual
Andrew Z.Pusztai
American Transmission Company
X
36.
Individual
Terry Harbour
MidAmerican Energy
X
37.
Individual
Claudiu Cadar
GDS Associates
X
38.
Individual
Joe Knight
Great River Energy
X
X
X
X
39.
Individual
Kirit Shah
Ameren
X
X
X
X
40.
Individual
Earl V. Burnside
PPL Electric Utilities
X
X
41.
Individual
Jianmei Chai
Consumers Energy Company
42.
Individual
Michael Pakeltis
CenterPoint Energy
X
43.
Individual
E Hahn
MWDSC (METROPOLITAN WATER DISTRICT
OF SOUTHERN CALIFORNIA)
X
44.
Individual
George Czerniewski
Consolidated Edison Company of New York Inc
X
X
X
X
7
8
9
X
8
10
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Commenter
45.
Individual
James W. Smith
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
ITC Transmission
9
10
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
1. The SDT replaced the defined term “Active Transmission Line Right of Way” with footnote number 2
that provides a description of “active transmission line ROW” and added Table 3, “Minimum Distance
from the Centerline of the Circuit to the edge of the active transmission line ROW” to support that
description. Do you agree? Please explain.
Summary Consideration:
Of 45 respondents, there is 1 abstention, 19 are in agreement, and 25 are in disagreement.
The major comment issues raised are:
1.
The values used in Table 3 needs to be justified.
2.
The definition of an active transmission line ROW ought to be a Glossary term.
3.
The Table does not account for different structure designs and the term “centerline” is not applicable in all
cases.
The VM SDT considerations for the major comment issues are:
1.
The VM SDT added explanatory text in the Guideline and Technical Basis section.
2.
Based on comments from 4th posting the SDT is revising the definition of ROW in the NERC Glossary.
3.
Table 3 has been removed.
Some minor comment issues are:
1.
Add distances for DC lines into Table 3.
2.
The term and Table 3 needs further clarification.
The VM SDT considerations for the minor comment issues are:
1.
Table 3 has been removed.
2.
Table 3 has been removed.
10
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
1
MWDSC
(METROPOLITAN
WATER DISTRICT
OF SOUTHERN
CALIFORNIA)
2
Hydro One
Yes or No
Question 1 Comment
No
A DC table for Table 3 similar to the MVCD table should be added.There
should be a statement in Table 3 that is consistent with footnote number 2
stating that the minimum width of the Active Transmission Line ROW is either
the full width of the easement or, if the easement is wider than the distances
in Table 3, the minimum distances must not be less than the distances
shown in the Table. The use of a minimum distance from the centerline of the
circuit or structure is an incorrect measure to use for a set clearance distance
of the active transmission right-of-way. The description does not take into
account vertical versus horizontal design configuration. Consideration
should be given for the type of construction as different construction types
(H-Frame, Lat-tice towers, Monopole delta or vertical construction) will
require different widths of a cleared right-of-way to provide the necessary
openings for these circuits. A minimum distance for 345-kV is now set at 150
feet based on the minimum distances from centerline. This may be correct
for certain H-Frame and Lattice Tower configurations but it is excessive for
monopole situations. A single pole configuration with vertically aligned
conductors does not need this full 150 foot width. It is strongly
recommended that a minimum distance from conductor be used in place of a
set distance from centerline. As long as there is at least 30 - 40 feet of
clearance in the right-of-way from the outermost conductors (adjusted to
account for maximum sway at mid-span for longer spans), then this is the
distance that should be used to develop the right-of-way widths.For example,
a monopole structure with vertically aligned conductors would result in a
cleared active right-of-way width of only 80 feet (40 feet from conductor to
edge of cleared active right-of-way) using the minimum distances from the
conductors. There is no need to extend this distance another 35 feet (on
each side) in order to obtain the full 150 foot width. This requirement is
excessive and must be adjusted to account for line construction variations.
11
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
Instead of using the term "Centerline" as referenced on Table 3, the use of
"outer phase" or "phase closest to tree line" would be more appropriate.
There is published literature using the term “cleared width” to indicate the
distance from the outer phase to the tree line. This distance should be used
in the Active ROW definition. The word easement is also used in the
definition. Is there a reason the Active ROW only includes easements, not
fee ownership, license or some other right to occupy and manage the ROW?
Would Active ROW include “danger tree rights” on land? These questions
need to be addressed in the standard (in text) and technical reference
document (in graphics).
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has revised
the definition of Right of Way to embody the concept of an Active Transmission Right of Way. Subsequently the
definition of Active Transmission Line Right of Way and Table 3 have been removed.
3
Allegheny Power
No
Allegheny Power strongly disagrees with the numbers or widths stated within
Table 3. These numbers seem arbitrary and have no accompanying
reasonable explanation as to their origin, basis, or other criteria noting the
rationale for inclusion in this standard. This inclusion effectively prohibits a
TO from establishing corridor widths less than the widths (which may be
easily possible by utilizing various tower or structures heights or
configurations) stated in Table 3 without placing the TO in extreme jeopardy
of non-compliance issues from a falling off-corridor tree, during minor storm
conditions as an example. Furthermore, this Table insinuates the TO has no
ability to successfully manage vegetation WITH NO RESULTING OUTAGES
or encroachments within the MVCD from off-corridor trees where corridors
are less that the widths stated in Table 3.Allegheny Power suggests that the
definition of the “Active Transmission line Right Of Way” be “the transmission
line ROW corridor that is actively maintained as part of the entity's vegetation
management plan.".
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has revised
the definition of Right of Way to embody the concept of an Active Transmission Right of Way. Subsequently the
definition of Active Transmission Line Right of Way and Table 3 have been removed.
4
FPL Corporate
Compliance
No
Although there is support for making Active Transmission Line Right of Way
a clearly defined term, and the foundation for compliance with FAC-003-2,
the distances in the table are arbitrary and are not supported by any scientific
12
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
or engineering analysis. It is possible that such a table could be interpreted to
define the minimum width of future lines. Different construction configurations
require different ROW widths.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
5
PPL Electric Utilities
No
Centerline (CL) distances shown in Table 3 are shown as Minimal distances
from CL. If utility is not able to define its ultimate ROW, due to CL agreement
or other circumstances, these minimal distances may not be applicable and
as such could result in non-compliance as written.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
6
Southern Company
Transmission
No
Depending on the intent this may create a problem. We are concerned the
addition of Table 3 could be interpreted to mean something completely
different than what we believe to be its intention. Please consider alternate
wording to Footnote 2: A strip or corridor of land that is occupied by active
transmission facilities. This corridor does not include the parts of the Right-ofWay that are unused or intended for other facilities. However, the active
transmission line ROW cleared width it is not to be less than the width of the
easement itself unless the easement exceeds distances as shown in Table 3
for various voltage classes.If the SDT determines keeping Table 3 is the
appropriate course of action, we recommend clarifying its intent better; either
in a footnote or in the title. Adding a footnote stating the Table is not
applicable if the distance from the center line of the conductor to the right-ofway edge is less than the appropriate distance indicated in the table.Another
option might be to add a statement to the title such as, “If the distance from
the centerline of the circuit to the edge of the easement is less than the
values in Table 3, that distance is considered active ROW”.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
13
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
7
Ameren
No
Does this mean wider ROW easements will need to be acquired to be
compliant or will this apply to ROW’s for new circuits going forward?
Response: Based on your comment and others, the SDT has revised the definition of Right of Way to
embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active
Transmission Line Right of Way and Table 3 have been removed.
8
Progress Energy
No
In Applicability Section 4.4, “active transmission line ROW” is not capitalized
indicating it is not a defined term, but Footnote 2 is effectively a definition for
active transmission line ROW. However, in the first paragraph of Section 5
Background, Active Transmission Line Right-of-Way is capitalized indicating
it’s a defined term. It would seem cleaner to make “Active Transmission Line
Right of Way” a formal NERC definition. Alternatively and at a minimum,
Footnote 2 should be revised to say “An active transmission line ROW is a
strip or corridor...” and also in Section 5 Background, “Active Transmission
Line Right of Way” should be changed to no longer be capitalized.
Response: Based on your comment and others, the SDT has revised the definition of Right of Way to
embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active
Transmission Line Right of Way and Table 3 have been removed.
9
PNM
No
ROW easements vary according to land ownership therefore, potentially
subjecting the utility to be liable for land outside of easement/ROW.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
10
Central Maine Power
Company, Iberdrola
USA
No
Table 3 distances may not be appropriate, for example table 3 should reflect
a clearance zone based on construction type, topography, species, or growth
rates. Table 3 could give the impression that the listed distances are the
maximum, therefore suggest table 3 be removed or revised.The Active
Transmisson Line Right-of-Way defination uses the word easement, which
most likely would include danger trees in situations where danger removals
14
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
are included in the the easement language. This would expand the scope of
FAC 003 2 beyond the cleared right-of-way width.
Response: The SDT agrees that Table 3 does not reflect the structural differences which directly determines
the right of way width. Based on your comment and others, the SDT has revised the definition of Right of
Way to embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active
Transmission Line Right of Way and Table 3 have been removed.
11
Consumers Energy
Company
No
Table 3 does not adequately address ROW width requirements based on the
type of construction used for structures, especially for the two lower voltage
classes, 69-138kV and 139-230 kV. Lines constructed on H-Frame
structures have a much wider footprint across the ROW than do single pole
construction and most steel tower construction types. The minimum ROW
width listed in Table 3 for a 138 kV line constructed on a wooden H-Frame
may put the outside conductor within MVCD under windy conditions due to
wind displacement of conductors and trees.Consumers Energy recommends
that Table 3 be modified to describe the minimum distance in the table is the
vertical plane of the outside conductor to the edge of the active transmission
ROW and therefore independent of the width of the structure construction
type.
Response: The SDT agrees that Table 3 does not reflect the structural differences which directly determines
the right of way width. Based on your comment and others, the SDT has revised the definition of Right of
Way to embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active
Transmission Line Right of Way and Table 3 have been removed.
12
The United
Illuminating Company
No
The definition has been altered. The last sentence "However, it is not to be
less than the width of the easement itself unless the easement exceeds
distances as shown in Table 3 for various voltage classes..." was added.
The concept of the easement is confusing and not included in the
Supplemental Reference. Table 3 of the standard is titled "Minimum
Distance from the Centerline of the Circuit to the edge of the active
transmission line ROW", no mention of easements. It is suggested that the
definition state "strip or corridor of land that is occupied by active
transmission facilities. This corridor does not include the parts of the Right-ofWay that are unused or intended for other facilities. At a minimum the width
is to be the distances as shown in Table 3 for various voltage classes."The
15
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
proper location for the definition is in the Glossary.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
13
Dominion
No
The distances proposed in Table 3 - Minimum Distance from the Centerline
of the Circuit to the edge of the active transmission line ROW may not be
consistent with the centerline distances cleared and maintained by the TO.
For example, a TO maintaining 75’ from centerline for a 500kV circuit would
be required to clear and maintain an additional 12.5’ to meet the proposed
standard’s requirement. We suggest either allowing individual TOs to
maintain active ROW widths consistent with their normal
clearing/maintenance practices, going back to Draft 3’s definition of Active
Transmission Line Right-of-Way, or changing the footnote in Draft 4 to
read:A strip or corridor of land that is occupied by active transmission
facilities. This corridor does not include the parts of the Right-of-Way that are
unused or intended for other facilities. However, the portion of the ROW that
has been cleared must at least meet design clearance requirements such as
National Electric Safety Code or other design criteria, for the reliable
operation of active facilities.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
14
BC Hydro
No
The footnote definition is ok but Table 3 is poorly developed. The voltage
classes should be better segregated (e.g. nominal voltage 69kV, 138kV,
230kV, 287kV, 345kV, 500kV, 765kV) along with distances in feet and
metres as Canadian utilities are metric. Also the table should include
recommended right of way widths for single circuits. The assumption made
in the footnote is that the legal easement is larger than in Table 3. However,
as currently defined, some of the distances in Table 3 exceed statutory rights
of way at our utility and exceed engineering standards as defined by the
Canadian Standards Association - Overhead Systems (CAN/CSA C22.3 No.
1-6). Also, clearances will very much depend on line design (e.g. structure
architecture such as flat, Post T, H-frame, steel lattice, and other variables
16
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
such as ruling span length, conductor type used, etc.) To some degree this
will vary quite a bit between utilities. As such Table 3 as currently presented
is not workable.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
15
Exelon
No
The term “Centerline of the Circuit” in Table 3 is not defined. Until it is
defined, there is no way to know if the standard is technically reasonable or
whether existing circuits would be in violation of the standard and unable to
operate. In addition, it is unclear what types of construction and span lengths
were used to develop the distances for active right-of-way widths in Table 3.
Furthermore, it is not clear whether Table 3 contains requirements against
which compliance will be measured or best practice guidelines. Footnote 2,
in the background section, compounds this ambiguity. In short, the lack of a
definition for “Centerline” combined with Footnote 2 and Table 3 make this
draft unclear and unenforceable. Exelon does not necessarily have
easement widths for all transmission lines that equal those defined in Table 3
of this draft; This may require the acquisition of additional easements, if even
possible.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
16
Northeast Utilities
No
The use of a minimum distance from the centerline of the circuit or structure
is an incorrect measure to use for a set clearance distance of the active
transmission right-of-way. Consideration should be given for the type of
construction as different construction types (H-Frame, Lattice towers,
Monopole delta or vertical construction) will require different widths of a
cleared right-of-way to provide the necessary openings for these circuits. A
minimum distance for 345-kV is now set at 150 feet based on the minimum
distances from centerline. This may be correct for certain H-Frame and
Lattice Tower configurations but it is excessive for monopole situations. A
single pole configuration with vertically aligned conductors does not need this
full 150 foot width. It is strongly recommended that a minimum distance from
17
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
conductor be used in place of a set distance from centerline. As long as
there is at least 30 - 40 feet of clearance in the right-of-way from the
outermost conductors (adjusted to account for maximum sway at mid-span
for longer spans), then this is the distance that should be used to develop the
right-of-way widths.For example, a monopole structure with vertically aligned
conductors would result in a cleared active right-of-way width of only 80 feet
(40 feet from conductor to edge of cleared active right-of-way) using the
minimum distances from the conductors. There is no need to extend this
distance another 35 feet (on each side) in order to obtain the full 150 foot
width. This requirement is excessive and must be adjusted to account for
line construction variations.Instead of using the term "Centerline" as
referenced on Table 3, the use of "outer phase" or "phase closest to tree line"
would be more appropriate.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
17
Idaho Power
Company
No
The way I interpret this, the new definition of active transmission line right of
way takes away our ability to clear potential fall ins if they are outside of the
active transmission line ROW>
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
18
CenterPoint Energy
No
There is no rationale provided for the “minimum distances” stated in Table 3,
and they far exceed the ROW widths that CenterPoint Energy owns (typical
total 100’ ROW width for 2-ckt 345kV line) for its current 345kV system, and
as such, are open for misapplication and misinterpretation as an intended
minimum standard for making a fall-in determination for R1 and R2 outside
the legal limits of the utility. Table 3 should be deleted. If kept, there should
be sufficient rationale included within the Guidelines and Technical Basis to
explain how it was derived and how it is to be used within the Standard.
CenterPoint Energy agrees with the removal of “active transmission line
ROW” as a defined term; however, the footnote should be deleted as well
since it attempts to create a definition which is not accurate, necessary or
18
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
useful. Throughout the Standard, the phrase “active transmission line ROW”
should be replaced with “transmission line ROW” to eliminate the qualifying
term “active”. In making a fall-in determination for R1 and R2, the limit
should be “within the full extent of the Transmission Owner’s transmission
ROW as defined by easement, fee simple, or other legal rights” as discussed
in the Guidelines and Technical Basis regarding the vegetation management
maintenance approach. This places the determination of the width of the
ROW for determination of fall-in violations clearly on the Transmission Owner
and the within the limits of its legal rights to control the vegetation that has
fallen into the line under R1 and R2.
Response: The SDT thanks you for your comments. The SDT disagrees with the point that the TO should be
required to clear the entire extent of legal rights. FERC Order 693 agreed that expansion easements needed
to be adressed. Based on your comment and others, the SDT has revised the definition of Right of Way to
embody the concept of an Active Transmission Right of Way. Subsequently the definition of Active
Transmission Line Right of Way and Table 3 have been removed.
19
Northeast Power
Coordinating Council
No
There should be a statement in Table 3 that is consistent with footnote
number 2 stating that the minimum width of the Active Transmission Line
ROW is either the full width of the easement or, if the easement is wider than
the distances in Table 3, the minimum distances must not be less than the
distances shown in the Table.The use of a minimum distance from the
centerline of the circuit or structure is an incorrect measure to use for a set
clearance distance of the active transmission right-of-way. The description
does not take into account vertical versus horizontal design configuration.
Consideration should be given for the type of construction as different
construction types (H-Frame, Lattice towers, Monopole delta or vertical
construction) will require different widths of a cleared right-of-way to provide
the necessary openings for these circuits. A minimum distance for 345-kV is
now set at 150 feet based on the minimum distances from centerline. This
may be correct for certain H-Frame and Lattice Tower configurations but it is
excessive for monopole situations. A single pole configuration with vertically
aligned conductors does not need this full 150 foot width. It is strongly
recommended that a minimum distance from conductor be used in place of a
set distance from centerline. As long as there is at least 30 - 40 feet of
clearance in the right-of-way from the outermost conductors (adjusted to
account for maximum sway at mid-span for longer spans), then this is the
19
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
distance that should be used to develop the right-of-way widths.For example,
a monopole structure with vertically aligned conductors would result in a
cleared active right-of-way width of only 80 feet (40 feet from conductor to
edge of cleared active right-of-way) using the minimum distances from the
conductors. There is no need to extend this distance another 35 feet (on
each side) in order to obtain the full 150 foot width. This requirement is
excessive and must be adjusted to account for line construction
variations.Instead of using the term "Centerline" as referenced on Table 3,
the use of "outer phase" or "phase closest to tree line" would be more
appropriate. There is published literature using the term “cleared width” to
indicate the distance from the outer phase to the tree line. This distance
should be used in the Active ROW definition. The word easement is also
used in the definition. Is there a reason the Active ROW only includes
easements, not fee ownership, license or some other right to occupy and
manage the ROW? Would Active ROW include “danger tree rights” on land?
These questions need to be addressed in the standard (in text) and technical
reference document (in graphics).
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
20
Arizona Public
Service Company
No
These clearances could exceed the permitted ROW’s on federal lands and
the utility has no legal right to clear beyond those rights. In some cases the
permitted ROW can exceed those distance and federal agencies could not
allow you to clear beyond those clearances in this version.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
21
Entergy Services
No
This is very unclear, and creates much uncertainty as to how certain
potential outage situations should be reported. Clarification language should
be added within the Standard to help define and guide the TO's actions when
an outage occurs from a location at a point that is less than the documented
ROW boundaries (Easements) but greater than the ROW distances
represented in Table 3. It is unclear which distance should guide our
20
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
reporting actions........ROW Document Width, Table 3 ROW Widths, or the
lesser of the two.......See scenarios / examples below for consideration to aid
with clarification points:Example 1: If our documented ROW width for a
500kV line is 100' from centerline (200' total ROW width) and we have a fall
in from 90' from centerline, do we report this as a Category 2 Outage due to
the fact that it fell from within our ROW limits, or is it non-reportable due to
the fact that it is located at a greater distance than 87.5' from the centerline of
the ROW as listed in Table 3 in the Standard?Example 2: How does
maintenance and outage reporting correlate with the example defined as
follows.......You have a 230 kV line situated on one side of a 150' wide ROW
that was initially cleared to a width that would accommodate 2 separate
parallel transmission lines and structures. The second set of lines/structures
have not yet been constructed, and the current Transmission line is situated
on one side of the 150' ROW, and is being maintained to the edge of the
actual ROW on the side of the ROW that it was constructed on (maintained
to a distance of 50' from centerline that puts it at the legal edge of the ROW),
but it has been typically maintained to a distance of approximately 60' from
centerline to the inside portion/other side of the ROW (the side of the ROW
that has never been cleared), but a tree falls into the line from approx 58'
from centerline (2' within the 60' distance typically being maintained on that
line).......would this be considered a Category 2 outage since it was approx 2'
within the average width being maintained on that side of the ROW or would
it not be reported due to the fact that it was located at a distance greater than
50' as indicated in Table 3??
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
22
Kansas City Power &
Light
No
This needs to be a defined term since the Standard uses that as a basis for
use with Table 3. Using this term as a footnote does not allow the industry to
weigh in on its definition. Footnotes should not be used as a means of
definition or clarification. Footnotes are for references to other sources of
statements or documents that support a particular thought.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
21
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
23
Xcel Energy
No
We believe Active Transmission ROW should be a defined term, not buried
in a “footnote” of the “Other” section of a Standard. It still begs the question what is an “active transmission facility”? Regarding the substance, overall
we believe that the Active Transmission ROW should not include the new
reference to Table 3. This newly added sentence in footnote 2, referencing
Table 3, is confusing to interpret. If retained, please rephrase to make it
clearer that a Transmission Owner never has to increase the size of its
easement/land right to satisfy this table. As drafted, our team had various
interpretations and it is unclear whether the intent is that a Transmission
Owner has to increase its easement or acquire land to meet this requirement,
or conversely if the easement is well beyond the values in Table 3, the
Transmission Owner has to maintain that the entire easement or only the
values in Table 3.”Active Transmission Right of Way” is still used in the first
paragraph of the Background section.In total, we suggest that the definition
of Activate Transmission ROW return to the version used in the prior draft
and be placed in the definition section.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
24
ITC Transmission
No
We disagree with footnote comment as this adds confusion to the standard.
Is a footnote considered part of the standard or not? The reference to table
#3 is something new and has never been discussed or commented on prior
to this revision and appears to be a bright line concept which we are in total
disagree with.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
25
FirstEnergy
No
We do not support replacement of the term Active Transmission Line Right of
Way with Footnote #2. Since the term "active transmission line ROW" is used
in the requirements, compliance section, and VSLs, and since the drafting
team has a very definite view of what this term means, the term should be a
22
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
definition included in the NERC Glossary. Also, since ROW is defined in the
NERC Glossary, it further supports the reasons this term should also be
defined. Therefore, we suggest the team revert back to the Draft 3 proposed
NERC Glossary term.Lastly, we do not support the addition of Table 3. We
believe this adds unnecessary prescriptiveness to the requirements. It is also
not clear if this Table was intended to be mandatory because the only
reference in the table is in Footnote #2. If the SDT feels this table is a useful
tool that should be included in the standard, then we suggest adding it to the
Guidelines section as optional information. Also, reference to this Table 3 in
the Active Transmission Line ROW definition should be removed.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
26
Tampa Electric
Company
No
We have concern with the “Minimum Distances” as listed in Table 3. What
analytical methodology, criteria and rationale was utilized to determine each
recommended distance? In addition, we have concerns regarding the change
to a pre-determined distance. This seems to be a major shift from the
vegetation to conductor methodology employed previously and throughout
this standard? NERC/FERC must recognize that while protecting and
securing grid reliability, each utility must also balance the environmental,
political, customer and economic issues and impacts which will occur with
the implementation of the Table 3 clearances. We question whether this is
the most responsible action to take given the current state of the economy as
well as the environmental and political sensitivity impacts which will result.
Tampa Electric questions whether Table 3 will improve System reliability.
Since the inception of standard FAC-003-1 Tampa Electric has not had a
Category 1 or Category 2 outage on our 230kV Transmission System. We
don’t believe that the changes proposed to table 3 will improve overall
service reliability. It is Tampa Electric’s opinion that each utility should define
the width of its own Active Transmission line ROW. However, if such a table
is to be utilized, Tampa Electric recommends the following changes or
adjustments to Table 3.1. Expand the table to account for the various types
of Transmission construction; i.e. vertical versus horizontal conductor
configurations.2. Use a distance from the outermost conductor, not the
centerline. This will account for
construction type and better achieve a
23
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 1 Comment
consistent clearance from conductors.3. We recommend reducing the
distances in Table 3 by 12.5 feet for each voltage category. 4. Specify
whether the voltage is based upon the design or operating voltage.5.
Reformat the voltage ranges to 100kV - 200kV, 200kV - 300kV, 300kV 400kV, etc. as an example; this would create a more appropriate range of
voltages and clearance distances. The reformatted voltage ranges eliminate
confusion. For example, under the current proposal it is unclear in which
category a nominal 230kV line should be since sometimes such a line can
operate at up to 232kV during low-load conditions.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
27
American
Transmission
Company
Yes
28
BGE Forestry
Management
Yes
29
Great River Energy
Yes
30
MidAmerican Energy
Yes
31
NERC Staff
Yes
32
Pepco Holdings, Inc Affiliates
Yes
33
South Carolina and
Gas
Yes
34
Western Electricity
Coordinating Council
Yes
24
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
35
GDS Associates
Yes or No
Question 1 Comment
Yes
- ROW abbreviation comes prior to the full term (marked footnote prior to the
full term as stated in 5. Background). Please make correction accordingly.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
36
Duke Energy
Yes
However, due to different design attributes of transmission lines, it may be
better to change the distance in Table 3 from a centerline distance to a
“Minimum Full Active Transmission Line ROW Width Distance”.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has
revised the definition of Right of Way to embody the concept of an Active Transmission Right of Way.
Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
37
Idaho Power
Yes
I support the description for the active right of way. However, I believe there
needs to be a provision that addresses identifying potential hazards outside
the active right of ways that may pose a risk to the transmission lines.
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
38
Manitoba Hydro
Yes
Please add metric equivalents in the standard.While it makes some aspects
easier around pointing to what we need to keep "clear" to meet NERC rules it does limit some of our flexibility to design lines and ROWs to your own
standards. Also, the minimum only applies when you have easement larger
than the minimums in table 3, and I would assume that does not relieve you
of the responsibility to maintain ROWs appropriately if the design of your
lines requires a wider ROW.
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
25
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
39
Southern California
Edison Company
Yes or No
Question 1 Comment
Yes
SCE appreciates the SDT’s efforts to replace the defined term with a set of
minimum distances. However, the proposed new Table 3 appears to assume
a horizontal configuration of transmission lines. Thus, it would appear that
those lines configured vertically (for example, two circuits on opposite sides
of a tower), the “active right of way” required would be at least twice as large
as that for horizontal lines. SCE respectfully recommends a footnote be
added to Table 3 that allows the TO to recalculate the active right of way for
lines in a vertical configuration, based on a horizontal line configuration.
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
40
Western Area Power
Administration
Yes
Suggest using a total right-of-way width in Table 3 rather than a distance
measured from centerline.
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
41
Tri-State Generation
& Transmission
Yes
Table 3 should be referenced as a guideline only.
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
42
MRO’s NERC
Standards Review
Subcommittee (nsrs)
Yes
The NSRS agrees in whole to the question but has the SDT taken into
consideration the difference in ROW may be different in Urban and Rural
settings?
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
26
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
43
Consolidated Edison
Company of New
York Inc
Yes or No
Yes
Question 1 Comment
The same verbiage in footnote number 2 should appear below Table 3 to
avoid any confusion.
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
44
Orange and Rockland
Utilities, Inc.
Yes
There should be a statement in Table 3 that is consistent with footnote
number 2 stating that the minimum width of the Active Transmission Line
ROW is either the full width of the easement or, if the easement is wider than
the distances in Table 3, the minimum distances must not be less than the
distances shown in the Table.
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
45
Bonneville Power
Administration
Yes
This distance is reasonable in the table, but due to widely varying designs of
structures it does not give a relationship of the outside wire to edge of ROW.
It should be noted as outside wire, phase or conductor to edge of ROW.In
addition, the effective date should allow transmission owners time to achieve
this distance, perhaps one cycle.
Response: The NERC Standard does limit or grant property rights. Based on your comment and others, the
SDT has revised the definition of Right of Way to embody the concept of an Active Transmission Right of
Way. Subsequently the definition of Active Transmission Line Right of Way and Table 3 have been removed.
27
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
2. In response to comments received regarding the terms “reasonable” and “human errors/human
activity”, the SDT modified the Other Section and Background Section. Do you agree? Please explain.
Summary Consideration:
Of 45 respondents, there are 3 abstentions, 38 are in agreement, and 4 are in disagreement.
The major comment issues raised are:
1.
Of the 4 in disagreement, only NERC believes “force majeure” statement is not necessary.
2.
Three respondents believe the “force majeure” statement should be expanded to include Federal, State,
Regulatory and legal interference.
The VM SDT considerations for the major comment issues are:
1. a) The SDT believes this language is appropriate for this standard due to the many factors related to
vegetation that are truly outside the TO’s control. Unlike the vast majority of other NERC standards,
implementation of FAC-003 is not under the absolute control of the utilities. These influences range from
landowner and agency obstacles to weather events, and as such the SDT believes the force majeure
provisions should be applicable. The recognition of this provision is also supported by 90% of the industry.
An attempt at similar language is contained in version 1 but it is ambiguous and lacks clarity. This language
adds clarity and reduces the opportunity for mis-application. Further, TO’s who elect to invoke “force
majeure” must have supporting evidence of such action. The lack of a force majeure section means a
Transmission Owner would have a violation of a Requirement, even if the penalty might have been
mitigated by the circumstances.
b) However, the SDT moved the force majeure from applicability to a footnote (Footnote 2) based on comments
concerning the structure of NERC standards. The footnotes are referenced in R1, R2, and R7. In R6, an
exclusion clause was added in Footnote 3.
3.
The SDT recommends no expansion. The “force majeure” provision is intended to recognize circumstances
that are completely outside the TO’s control. Federal, State or regulatory interference is certainly a barrier
but there are actions available to mitigate such interference. The TO should be aware of such interference
and should take whatever corrective actions necessary, up to and including re-rating or de-energizing the
line, to avoid a vegetation conflict.
28
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Some minor comment issues are:
1.
One respondent would like to specifically define wind speed.
2.
Two respondents suggested moving the language elsewhere in the standard.
The VM SDT considerations for the minor comment issues are:
1.
The SDT recommends no change. Wind speed is addressed by “fresh gale”.
2.
The SDT moved it to a footnote.
Organization
1
MWDSC
(METROPOLITAN
WATER DISTRICT
OF SOUTHERN
CALIFORNIA)
2
Western Electricity
Coordinating Council
3
Central Maine Power
Company, Iberdrola
USA
4
NERC Staff
Yes or No
Question 2 Comment
No comment suggested.
No
NERC staff does not support the language in the Other Section. Staff
believes that the force majeure provision is unnecessary and calls into
question whether NERC and the regions have enforcement discretion to take
such things into account in applying other standards that do not include this
type of provision.
Response: The SDT thanks you for your comments. The SDT believes this language is appropriate for this
standard due to the many factors related to vegetation that are truly outside the TO’s control. Unlike the vast
majority of other NERC standards, implementation of FAC-003 is not under the absolute control of the
29
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
utilities. These influences range from landowner and agency obstacles to weather events, and as such the
SDT believes the force majeure provisions should be applicable. The recognition of this provision is also
supported by 90% of the industry. An attempt at similar language is contained in version 1 but it is
ambiguous and lacks clarity. This language adds clarity and reduces the opportunity for mis-application.
Further, TO’s who elect to invoke “force majeure” must have supporting evidence of such action.
5
BGE Forestry
Management
No
Suggest including in “4.4. Other” a phrase referencing government
interference, such as “Federal, State or other regulatory interference,
including legal or other legislative actions, that prevents performance to
comply with this reliability standard.”
Response: The SDT thanks you for your comments. The “force majeure” provision is intended to recognize
circumstances that are completely outside the TO’s control. Federal, State or regulatory interferrence is
certainly a barrier but there are actions available to mitigate such interference. The TO should be aware of
such interference and should take whatever corrective actions necessary, up to and including re-rating or
de-energizing the line, to avoid a vegetation conflict.
6
Kansas City Power &
Light
No
The theme of the “Other” section are the conditions for excluding applicable
transmission facilities under certain conditions. Recommend the Drafting
Team consider renaming this section to “Exclusions”. In addition, the term,
“Active Transmission Line Right-of-Way” is capitalized in the “Background”
section. If it is determined this term should not be a definition, then this
should be lower case.
Response: The SDT thanks you for your comments. The recommendation does not materially change the
“force majeure” provision and the SDT does not recommend any change. The SDT did modify the ROW
definition in response to industry concerns. Capitalization is now appropriate.
7
Xcel Energy
No
Xcel Energy urges the retention of the word "reasonable" as a modifier to
"control" in Introduction, Section 4.4. The concept that a Transmission
Owner should exercise reasonable control is sensible, and is of some aid in
countering claims that any incident could be prevented. For example, in
Colorado, the transmission of electricity has been judicially found to be
subject to the highest degree of care. Without the inclusion of the word
"reasonable," Xcel Energy could possibly be faced with a claim that for the
exceptions set forth in Introduction, Section 4.4, to apply, the circumstances
would have to be "beyond the control (using the highest degree of care) of
30
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 2 Comment
Xcel Energy." Retention of "reasonable" helps counter such claims. Since
this section appears to lean toward legal language, the use of the term
“reasonable” is better suited for the goal of this section.
Response: The SDT thanks you for your comments. While we understand the concerns, the word
reasonable is ambigous and open to intrepretation and therefore not an appropriate modifier to the language.
8
Allegheny Power
Yes
9
Ameren
Yes
10
American
Transmission
Company
Yes
11
Arizona Public
Service Company
Yes
12
Bonneville Power
Administration
Yes
13
Consolidated Edison
Company of New
York Inc
Yes
14
Consumers Energy
Company
Yes
15
FPL Corporate
Compliance
Yes
16
Dominion
Yes
17
Duke Energy
Yes
31
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
18
Entergy Services
Yes
19
Exelon
Yes
20
GDS Associates
Yes
21
Hydro One
Yes
22
Idaho Power
Company
Yes
23
ITC Transmission
Yes
24
Manitoba Hydro
Yes
25
MidAmerican Energy
Yes
26
Northeast Power
Coordinating Council
Yes
27
Northeast Utilities
Yes
28
Orange and Rockland
Utilities, Inc.
Yes
29
Pepco Holdings, Inc Affiliates
Yes
30
PNM
Yes
31
PPL Electric Utilities
Yes
32
Progress Energy
Yes
Question 2 Comment
32
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
33
South Carolina and
Gas
Yes
34
Southern Company
Transmission
Yes
35
The United
Illuminating Company
Yes
36
Tri-State Generation
& Transmission
Yes
37
Western Area Power
Administration
Yes
38
Great River Energy
Yes
Question 2 Comment
GRE believes that the new definition provides greater clarity with respect
what does not constitute a compliance violation versus the previous version.
Response: The SDT thanks you for your comments and we are in agreement.
39
CenterPoint Energy
Yes
No preference.
Yes
SCE generally agrees with the information contained in Part 5 - Background.
However, we question the value of placing a rationale within the body of the
standard. SCE respectfully recommends that the revised “Background”
information be added to the beginning of the “Guidelines and Technical
Basis,” which also includes explanations for various standard segments.
Response:
40
Southern California
Edison Company
Response: The SDT thanks you for your comments. It is not specific to “force majeure” and is best
answered in general comments.
41
MRO’s NERC
Standards Review
Yes
The NSRS believes that the new definition provides greater clarity with
respect what does not constitute a compliance violation versus the previous
33
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Subcommittee (nsrs)
Question 2 Comment
version.
Response: The SDT thanks you for your comments and we are in agreement.
42
Tampa Electric
Company
Yes
These changes add improved clarity and defintion to this section.
Response: The SDT thanks you for your comments and we are in agreement.
43
Idaho Power
Yes
This will allow the utilities to address conditions that are within their control.
Response: The SDT thanks you for your comments and we are in agreement.
44
FirstEnergy
Yes
While we agree with the changes proposed, we would recommend that the
list contained in the "Other" section should be revised to include judicial
actions such as injunctions. While this is not a natural occurring situation, it
is certainly one that will prevent an entity from removing vegetation when
needed or desired.
Response: The SDT thanks you for your comments. The “force majeure” provision is intended to recognize
circumstances that are completely outside the TO’s control. Legal and judicial actions are certainly a barrier
but there are other corrective actions available to mitigate such interference. The TO should be aware of
such interference and should take whatever actions necessary, up to and including re-rating or de-energizing
the line to avoid a vegetation conflict.
45
BC Hydro
Yes
Yes but there should be more commentary around exceptions. You should
get away from certain descriptive terms and be more empirical when you can
to avoid ambiguity. For example “Fresh Gale” on the Beaufort Scale is not
common as there are several variants to this scale and on some scales is
defined as “Gale”. So do you mean winds of 39-46 mph (62-74 kmh) or
greater wind speed? If so, why not state that?
Response: The SDT thanks you for your comments. The “force majeure” provision is not intended to
address every possible exclusion but to be a general statement intended to recognize circumstances that are
completely outside the TO’s control.
34
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
3. In response to comments received regarding the language in M1 and M2, the SDT modified the first
bulleted item and added a sentence to the end of the paragraph in M1 and M2. Do you agree? Please
explain.
Summary Consideration:
Of 45 respondents, there are 2 abstentions, 27 are in agreement, and 16 are in disagreement.
The major comment issues raised are:
1.
Definition of “qualified personnel”.
2.
Confusion around “real time observation of an encroachment into the MVCD” and documentation required to
report a violation or attest that a violation did not occur. Also issues regarding an encroachment with no
fault and/or momentary fault as being a violation.
The VM SDT considerations for the major comment issues are:
1.
SDT changed the language to “confirmation by Transmission Owner”.
2.
Considered language proposed by Duke in comment 16 and adopted and modified by SDT.
A minor comment issue is:
1.
The inclusion of examples in the requirement instead of the rationale box.
The VM SDT consideration for the minor comment issue is:
1.
The SDT changed the language to “confirmation by Transmission Owner”.
Organization
1
Yes or No
Question 3 Comment
MWDSC
(METROPOLITAN
35
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
WATER DISTRICT
OF SOUTHERN
CALIFORNIA)
2
Xcel Energy
3
GDS Associates
No comments/no position
No
- Need to specify who qualifies as “qualified personnel” to observe the
vegetation condition.
Response: Thank you for your comment. The SDT changed the wording to confirmation by the
Transmission Owner.
4
Hydro One
No
A clarification for M1 is needed regarding whether entities will have to attest
to the fact that there has never been an encroachment in the MVCD.
Response: Thank you for your comment. It is not the intent of this standard for entities to be required to
prove a negative. The SDT believes the proposed language does not imply that an entity will be required to
prove that an encroachment has not occurred.
5
Northeast Power
Coordinating Council
No
A clarification for M1 is needed regarding whether entities will have to attest
to the fact that there has never been an encroachment in the MVCD.
Response: Thank you for your comment. It is not the intent of this standard for entities to be required to
prove a negative. The SDT believes the proposed language does not imply that an entity will be required to
prove that an encroachment has not occurred.
6
PPL Electric Utilities
No
As written M1 requires evaluation of condition by “qualified person” but no
definition of qualified person given. Should be more direct and point to
physical evidence of vegetation encroachment into MVCD, i.e. burned
vegetation.
Response: Thank you for your comment. The SDT changed the wording to confirmation by the
Transmission Owner. It is not the intent of this standard for entities to be required to prove a negative. The
SDT believes the proposed language does not imply that an entity will be required to prove that an
encroachment has not occurred.
36
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
7
CenterPoint Energy
Yes or No
Question 3 Comment
No
CenterPoint Energy does not believe a performance based requirement
should require evidence of processes and procedures to demonstrate
compliance. However, if the majority of industry commenters agree with the
SDT’s approach, CenterPoint Energy has several concerns.Assuming R1.1
and R2.1 regarding observations of encroachments are not deleted from the
Standard, then only the first paragraph regarding forms of evidence is helpful
and necessary. The second paragraph is not relevant or necessary. The
special qualification of Sustained Outage should be contained in R1 and R2,
not M1 and M2. Also, the reference to a “Fault” in M1 and M2 instead of a
“Sustained Outage” changes the scope of what is specified in R1 and R2
which is not reasonable. A “Fault” can be associated with a Momentary
Outage or a Sustained Outage. The scope of R1 and R2 is specific to
Sustained Outages.
Response: Thank you for your comment. The SDT chose the word “fault” as it is a NERC defined term. A
fault associated with vegetation indicates that encroachment into the MVCD occurred.
8
Arizona Public
Service Company
No
Do not agree with real-time observation. Utility can use technology to
determine all rated conditions if a tree related outage occurred.
Response: Thank you for your comment. The real-time observation reference applies to cases where
vegetation encroaches into the MVCD but flash-over has not occurred. Enroachment into the MVCD where
no fault occurs is the least severe violation of the requirement.
9
MidAmerican Energy
No
Examples should be moved to the rationale boxes to avoid confusion on
what is required and what is an example. All rationale boxes should have a
disclaimer to the effect saying "For guidance only, not for enforcement".
Response: Thank you for your response. Examples were included in the Requirement at the response of
NERC staff to add clarity. By definition, verbiage within the rationale boxes are for guidance and are not
enforcable.
10
Kansas City Power &
Light
No
In response to the informal comment period, the SDT is clear that it believes
the use of encroachment as a basis for determining the effectiveness and
compliance of a vegetation management program. The purpose of this
Standard is to identify the criteria for effective monitoring of vegetation in
37
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
transmission right-of-way and to take appropriate actions when that
monitoring identifies the need to “clear” vegetation to prevent potential
transmission facility outages resulting from contact with vegetation. These
proposed Measures as written do not give credit to the Transmission Owners
for effectively monitoring their systems and taking appropriate actions in
regard to vegetation clearing. Why does it make sense to punish and
penalize a Transmission Owner for discovering an encroachment when they
take the appropriate actions to remedy the condition before any facility
outage occurs that results in compromising the reliability of the Bulk Electric
System? These Measures and Standard should recognize the good
practices of effective response to a vegetation condition and penalize
ineffective response. Highly recommend the SDT consider including
appropriate language to recognize effective remedial actions by
Transmission Owners and by doing so, recognize effective efforts instead of
punishing them.In addition, proving encroachments have not occurred will
pose audit challenges in determining that encroachments have not occurred
for the Auditors as well as Registered Entities. If no encroachments occur,
then there is nothing to report or record. This is a weak platform to stand
compliance on. Facility interruption events caused by vegetation contacts is
definitively measurable and recordable. Recommend the SDT reconsider the
concept of compliance with FAC-003 on the basis of sustained outages.
Response: Thank you for your comment. The real-time observation reference applies to cases where
vegetation encroaches into the MVCD but flash-over has not occurred. Enroachment into the MVCD where
no fault occurs is the least severe violation of the requirement. It is not the intent of this standard for entities
to be required to prove a negative. The SDT believes the proposed language does not imply that an entity
will be required to prove that an encroachment has not occurred.
11
BGE Forestry
Management
No
M1 & M2 bullet: “Real-time observation of any MVCD encroachments.”
implies that real-time observation of vegetation encroachment ensures
reliable operation the Bulk Electric System. The reliability standard objective
states;”To improve the reliability of the electric Transmission system by
preventing those vegetation related outages that could lead to
Cascading.”However, real time observation of current operating conditions
provides no assurance that vegetation will not lead to outages. BGE
recommends removing the language. If an inspector finds vegetation
encroaching into the MVCD during a visual inspection he / she should
38
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
immediately initiate an Immediate Threat Notification. Therefore, this
measure has no value.
Response: Thank you for your comment. The real-time observation reference applies to cases where
vegetation encroaches into the MVCD but flash-over has not occurred. Enroachment into the MVCD where
no fault occurs is the least severe violation of the requirement.
12
PNM
No
Needs a definition of Real Time Observations
Response: Thank you for your comment. The SDT believes that “Real Time” observations (the actual time
during which the observation occurs) is sufficiently clear.
13
Consumers Energy
Company
No
None of the three examples of acceptable forms of evidence provided in the
revision prove that a Transmission Owner actively managed vegetation to
prevent encroachment into the MVCD. The Measure should require proof of
active ROW clearing activity per the transmission vegetation management
plan, such as invoicing or crew field reports or vegetation inspection data
from the annual vegetation inspection.
Response: Thank you for your comment. The SDT would suggest you refer to R6 and R7, which addresses
evidence of an annual vegetation inspection and work plan.
14
BC Hydro
No
Overall, the definition of these measures is improved over draft 3. However,
the standard should better define who a “qualified person” is and who has the
authority to make attestations. R1 and R2 could be better defined relative to
the standard definitions in section 4.2 as to what voltage levels in R2 are part
of the standard and what is excluded. That is:R1 is any circuit that is an
element of an IROL or WECC transfer path regardless of the transmission
voltage.R2 is any circuit >200kV which is not an element of an IROL or
WECC transfer path.Lower voltage circuits that do not fit the R1 definition are
not part of this standard.
Response: Thank you for your comment. The SDT changed the wording to confirmation by the
Transmission Owner. R1 and R2 intentionally differentiate between the components of the transmission
system that are part of the IROL or WECC Transfer Path and the BES. The SDT believes that violations in the
IROL or WECC Transfer Paths pose a greater risk of cascading events, and therefore carry higher VSLs.
39
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
15
Central Maine Power
Company, Iberdrola
USA
Yes or No
No
Question 3 Comment
Recommend SDT create two measures one measure if a tree violated the
MVCD and no outage occurred and second measure and severity level if an
outage occurred
Response: The SDT believes that enroachments into the MVCD where no fault occurs are a violation to the
standard and should be included in R1 and R2.
16
Duke Energy
No
The last sentence of this modification could be misinterpreted by a
compliance representative to imply that all Faults must be investigated to
eliminate or confirm vegetation as the cause of the fault. There are several
sources (e.g. lightning, wind-blown debris) of Faults and several appropriate
operational responses, some of which may not include field investigations,
depending on the circumstances surrounding each Fault. Thus, the current
wording is gray and should be modified to aid industry’s understanding and
thus to ensure compliance.The interpretation we suggest may not be
obvious, but our experience with previous interpretations of certain facets of
FAC-003-01 would indicate the need to better define the expectation.A
potential modification to the last sentence of M1/M2 could be:If a later
confirmation of a Fault by a qualified person shows that a vegetation
encroachment within the MVCD has occurred, this shall be considered the
equivalent of a Real-time observation.
Response: Thank you for your comment. The SDT agrees with your recommendation and has adopted the
proposed language. The SDT believes that faults that occur on applicable lines included in R1 and R2
should be investigated to determine if the cause was vegetation related. If an entity can determine to their
satisfaction, through documentable means such as through technology or other sources, that the fault was
caused by some other reason (i.e. lightning), it is the entity’s decision whether or not to investigate further.
17
FPL Corporate
Compliance
No
The measure is adding to the requirement. The measure should define how a
requirement is met and not interpret or add to the requirement, otherwise this
will add to confusion, instead of clarity, which should be the goal of any
revised reliability Standard.Also, the measure implies that a fault
investigation must be done. As written, momentary outages are included, and
a fault investigation should not be required for momentary outage.It also
places the same weight of violation on a momentary outage as it does a
Sustained outage, which appears on its face not to appropriate nor
40
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
necessary to meet the goal of FAC-003-2. In addition, an outage
investigation is not a finite process that produces identical homogenous
results every time. Of particular concern is the possibility that should a
Transmission Owner have one or more momentary outages and not find the
cause, then later have another outage (Sustained or Momentary), such a
finding appears to lead to a multiple violation. This is inconsistent with
focusing requirements on reliability risks to the bulk electric system.
Response: Thank you for your comment. A fault caused by the grow-in, fall-in, or blow-in of vegetation on
the active right-of-way is a violation of the requirements regardless of whether the fault was momentary or
sustained. Based on other comments, the SDT has modified the language in M1/M2.
18
NERC Staff
No
With respect to both M1 and M2, NERC staff finds the “acceptable forms of
evidence” incomplete. To assess compliance, the auditors would also need
to see the processes and procedures identified under Requirement R3 and
the annual work plan under Requirement R7 to see how the entity planned to
prevent sustained outages and what the entity had done to implement that
plan. Finally, what is the purpose of the following sentence?: “If an
investigation of a Fault by a qualified person confirms that a vegetation
encroachment within the MVCD occurred, then it shall be considered a Realtime observation.” Recommend adding each report of a real-time observation
of encroachment into the MVCD to the periodic data submittal.
Response: Thank you for your comment. The SDT believes that an attempt to list all “acceptable forms of
evidence” would be difficult, as entities employ a myriad of documentation types. The SDT agrees that an
auditor would need to see the processes and procedures indentified under R3 and R7 to perform an audit.
An auditor with an understanding of vegetation management would be able to validate “acceptable forms of
evidence” as part of compliance audit process. Real time observations of an encroachment into the MVCD
is a violation of the standard and should be documented and self-reported. The RE’s currently require
periodic reporting.
19
Allegheny Power
Yes
20
Ameren
Yes
21
American
Yes
41
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
Transmission
Company
22
Bonneville Power
Administration
Yes
23
Consolidated Edison
Company of New
York Inc
Yes
24
Dominion
Yes
25
Exelon
Yes
26
Idaho Power
Yes
27
Idaho Power
Company
Yes
28
ITC Transmission
Yes
29
Manitoba Hydro
Yes
30
MRO’s NERC
Standards Review
Subcommittee (nsrs)
Yes
31
Northeast Utilities
Yes
32
Orange and Rockland
Utilities, Inc.
Yes
33
Pepco Holdings, Inc –
Affiliates
Yes
42
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
34
Progress Energy
Yes
35
South Carolina and
Gas
Yes
36
Southern Company
Transmission
Yes
37
The United
Illuminating Company
Yes
38
Tri-State Generation
& Transmission
Yes
39
FirstEnergy
Yes
Question 3 Comment
Although we agree with the language of M1 and M2 for the proposed R1 and
R2 in the standard being balloted, we support the alternate versions of R1
and R2 (see comments in Question 6) and wish to see M1 and M2
developed for the alternate R1 and R2.
Response: Thank you for your comment.
40
Great River Energy
Yes
GRE agrees with the revisions made to this standard since the last posting
and requests clarification on what constitutes a qualified person.
Response: Thank you for your comment. The SDT changed the wording to confirmation by the
Transmission Owner.
41
Western Electricity
Coordinating Council
Yes
however the statement of acceptable forms of evidence implies that a dated
attestation alone could provide evidence of compliance. An attestation alone
would not represent sufficient evidence to support a conclusion of
compliance with encroachment limits only of the absence of an outage.
Response: Thank you for your comment. Real time observations of an encroachment into the MVCD is a
violation of the standard and should be documented and self-reported.
43
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
42
Western Area Power
Administration
Yes or No
Yes
Question 3 Comment
However, the last sentence added to the measure is imprecise and
introduces undesirable subjectivity and confusion to the process for
determining a compliance violation.
Response: Thank you for your comment. Based on the recommendation from several commentors, the last
sentence in M1/M2 has been modified.
43
Southern California
Edison Company
Yes
SCE generally agrees with the revisions to M1 and M2, however we would
suggest the last sentence of the second paragraphs in both M1 and M2 be
modified to read: M1- Multiple Sustained Outages on an individual line, if
caused by the same vegetation, will be reported as one outage regardless of
the actual number of outages within a 24-hour period. If an investigation of a
Fault, by a qualified person, confirms that a vegetation encroachment, as
described in R1 items 2-4 (above), occurred within the MVCD occurred, then
it shall be considered a Real-time observation.M2- Multiple Sustained
Outages on an individual line, if caused by the same vegetation, will be
reported as one outage regardless of the actual number of outages within a
24-hour period. If an investigation of a Fault, by a qualified person, confirms
that a vegetation encroachment, as described in R2 items 2-4 (above),
occurred within the MVCD occurred, then it shall be considered a Real-time
observation.
Response: Thank you for your comment. Based on the recommendation from several commentors, the last
sentence in M1/M2 has been modified.
44
Tampa Electric
Company
Yes
These changes allow for qualified review of field findings.
Response: Thank you for your comment.
45
Entergy Services
Yes
We agree, IF the determination is made by a Qualified Person to have been
caused by vegetation breaking the MVCD (if not breaking MVCD in real time
when observed) based on close observation/inspection and hard evidence
that a Flashover occurred, and that there is no evidence that the issues
spotted on the tree were caused by environmental or biological symptoms or
stressors of the tree in question. Hard evidence has to be present to classify
44
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 3 Comment
the item as a vegetation outage if the tree is not within MVCD when the real
time observation is made.....an assumption cannot be made that vegetation
was the cause of an outage if the tree is situated at a distance that is greater
than MVCD when observed unless there is hard evidence supporting the
flashover as determined by a qualified person.
Response: Thank you for your comment.
45
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
4. In response to comments received that requirement R3 is deficient in detail, the SDT modified the
requirement. Do you agree? Please explain.
Summary Consideration:
Of 45 respondents, there are 32 in agreement, 12 in disagreement and1 abstention.
The major comment issues raised are:
1.
The additional wording placed in the requirement after the first sentence adds confusion to the extent of
documentation that will be required.
2.
The use of the phrase “incorporate the dynamics” adds confusion to the requirement.
The VM SDT considerations for the major comment issues are:
1.
The response pointed out that the reason that the additional wording was inserted was due to the numerous
comments from the previous posting that the requirement needed more specificity.
2.
The SDT agreed with some suggested wording to replace the phrase “incorporate the dynamics” and revised
the requirement accordingly.
Some minor comment issues are:
1.
One commenter questioned the use of the word “intent” in the rationale.
2.
One commenter questioned the language of the measure.
3.
One commenter was concerned that the removal of the programmatic details renders the requirement less
auditable and questionably effective.
The VM SDT considerations for the minor comment issues are:
1.
The wording in the rationale was changed to eliminate the word “intent”.
2.
In the response to the commenter questioning the language of the measure, the SDT explained that the
focus of the measure is on the logic test of the Transmission Owner’s vegetation maintenance program.
46
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
3.
In response to the commenter concerned about the programmatic details being removed, the SDT
responded by explaining various ways that this requirement could be audited and further explained the
main focus of the requirement.
Organization
1
MWDSC
(METROPOLITAN
WATER DISTRICT
OF SOUTHERN
CALIFORNIA)
2
GDS Associates
Yes or No
Question 4 Comment
No
- We suggest to eliminate / change the word “dynamics” because can create
confusion with regards to the extent of documentation that has to be
prepared.- Requirement should clearly state the criteria as in the maximum
design (rating) or maximum operat
Response: The SDT thanks you for your comment. The intent of the more detailed wording of R3 in this
version of the Standard is to make sure that the Transmission Owner adequately documents and
demonstrates that it understands the complex relationship of conductor movement under thermal and wind
load and vegetation growing and moving in proximity to the line. In light of your comment, and similar
comments from others, the SDT has revised the wording of R3. We feel that this change will alleviate any
perceived confusion.
3
PPL Electric Utilities
No
As written, R3 now requires documentation of conductor dynamics as related
to ratings and rated operational conditions. Not clear how this information is
to be presented and documented and how vegetation conditions that exist
are to be documented to provide evidence that management processes and
procedures are adequate to prevent encroachment into MCVD.
Response: The SDT thanks you for your comment. The Technical Reference Document attempts to provide
further explanation, along with examples, of how to present this information. While this information is not in
the Standard itself, the supplemental information in the Technical Reference Document should help the
Transmission Owner understand the SDT’s intent for the requirement. Also, The SDT has revised the
wording in R3 and has removed the word “dynamics”.
47
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
4
Great River Energy
Yes or No
Question 4 Comment
No
GRE does not believe that the new specificity that has been added to R3 will
improve the reliability of the BES. It is our opinion that the requirement would
have been clearer if it had ended after the first sentence. The additional
language after the first sentence does not improve clarity.In measures for
other requirements the SDT has done a very good job of stating and
clarifying (in their opinion) what acceptable forms of evidence are. M3 would
benefit from this type of clarification.
Response: The SDT thanks you for your comment. The previous version of the Standard was crafted very
much as you suggest. Many commenters disagreed with this approach, which led to the SDT crafting this
more verbose version.
5
Kansas City Power &
Light
No
It is unclear that this requirement may utilize the industry practice of “ruling
span” methods to determine the vegetation clearances for a transmission
facility. “Ruling span” methods are used to determine the construction
design for transmission facilities and includes maintaining safe clearance
distances. This requirement could be interpreted as being applied to every
individual span to determine vegetation clearances for a transmission facility
which would not be practical.
Response: The SDT thanks you for your comment. The intent of R3 in this version of the Standard is to
make sure that the Transmission Owner adequately documents and demonstrates that it understands the
complex relationship of conductor movement under thermal and wind load and vegetation growing and
moving in proximity to the line. It leaves the decision to the Transmission Owner how to satisfy this
“competency based” requirement. While a Transmission Owner could certainly take the approach that each
individual span be addressed separately, it is also possible for a Transmission Owner to have a specific
“vegetation maximum height” approach, based on the minimum ground clearance specification of an entire
line. Either approach would satisfy this requirement.
6
MidAmerican Energy
No
MidAmerican supports the additional detail the R3 should end after the first
sentence. The additional detail should be moved to the rationale box as
additional guidance.
Response: The SDT thanks you for your comment. If we understand your comment, the reason that R3 has
greater detail was due to comments received after the last posting. The SDT felt compeled to add this
additional information.
48
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
7
Xcel Energy
Yes or No
Question 4 Comment
No
R3 requires the Transmission Owner to have a documented process that
shall contain certain items. Please bulletize these items for
clarity.Additionally, the measure for this requirement indicates that the
process document elements ‘prevent’ encroachment. It is presumed that the
elements identified in the requirement are what need to be addressed in
order to minimize the likelihood of encroachment. Essentially, M3 should be
reworded to state “The procedures, processes, or specifications provided
incorporate the elements identified in R3 (dynamics of a transmission line
conductor’s...)
Response: : The SDT thanks you for your comment. The SDT feels that the requirement is adequate in a
non-bullet form. R3 has been revised to clarify the intent of this “competency based” requirement. The
measure for this requirement should be a “logic” test looking at the methodology that the Transmission
Owner uses in order to determine what vegetation actions need to take place. The Technical Reference
Document gives examples of several ways to satisfy this requirement. The SDT feels that the measure as
stated is adequate.
8
Southern California
Edison Company
No
SCE prefers the Draft 3 version of R3 which read:”Each Transmission Owner
shall have a documented transmission vegetation management program that
describes how it conducts work on its Active Transmission Line ROWs to
avoid Sustained Outages due to vegetation, considering all possible
locations the conductor may occupy assuming operation within Rating and
Rated Electrical Operating Conditions.”However, if the SDT believes it is
prudent to revise R3 in response to certain commenters, SCE would
respectfully recommend R3 be revised to read:”Each Transmission Owner
shall document the procedures, processes, or specifications it uses to
prevent the encroachment of vegetation into the MVCD. Such documentation
will account for the movement of transmission line conductors under their
Rating and Rated Electrical Operating Conditions; and the inter-relationships
between vegetation growth rates, vegetation control methods, and inspection
frequency, for the Transmission Owner’s applicable lines.”
Response: The SDT thanks you for your comment. The SDT agrees that the wording in R3 should be
modified. R3 has been revised to remove the reference to “incorporate the dynamics” and has recrafted the
requirement wording similar to your latter recommendation.
49
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
9
CenterPoint Energy
Yes or No
Question 4 Comment
No
See response to Q3 above. However, assuming R3 is not revised to exclude
processes and procedures, we have no preference to the wording between
the two drafts.
Response: The SDT thanks you for your comment.
10
Arizona Public
Service Company
No
Still lacks detailed information. SDT needs to specify the documentation it is
left up to interpretation by the utility.
Response: The SDT thanks you for your comment. The SDT feels that the combination of the requirement
wording and the examples and explanations in the Technical Reference Document are sufficient detail to
portray the intent.
11
MRO’s NERC
Standards Review
Subcommittee (nsrs)
No
The NSRS does not believe that the new specificity that has been added to
R3 will improve the reliability of the BES. It is our opinion that the
requirement would have been clearer if it had ended after the first sentence.
The additional language after the first sentence does not improve clarity.
The whole (as written) requirement may be interpreted as a requirement for
“each span” of Transmission line to which the Requirement will be applied. In
measures for other requirements the SDT has done a very good job of
stating and clarifying (in their opinion) what acceptable forms of evidence
are. M3 would benefit from this type of clarification.
Response: The SDT thanks you for your comment. The previous version of the Standard was crafted very
much as you suggest. Many commenters disagreed with this approach, which led to the SDT to address this
issue by adding the specificity.
R3 is a “competency based” requirement. The measure should be whether the methodology used by the TO
to maintain vegetation passes the basic logic test. (eg: Our max growth rate is 3’ per year. We have a
minimum ground clearance spec for 230 kV of 24 feet at maximum sag. We maintain the lines every three
years. During maintenance of 230 kV lines we remove all vegetation over 11.5 feet high) For a “results
based” standard, the emphasis should be on the Tranmssion Owner demonstrating competency in its
approach, however simple or complex that approach may be
12
NERC Staff
No
The removal of programmatic details from R3 renders the auditing task much
more difficult. How does one assess the quality of the program except
50
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
through the results required in R1 and R2? Since maintaining specific cut-to
clearances is not required, there is much greater subjectivity in application
that greatly complicates the auditor job. If the team does not want to limit the
available approaches, it could provide flexibility by offering an array of
deterministic formulas or approaches for maintaining vegetation. This might
include maintaining vegetation to remain within a certain height from the
ground given maximum sag distances.
Additionally, this requirement does not seem to require the entity to actually
follow its policies and procedures (unlike, for instance, R7). What is a
violation here? Not having the documented procedure(s) OR whether the
documented procedure(s) actually demonstrate that the entity can prevent
encroachment?
NERC staff is also concerned with some of the language in M3. Consider the
following modification: “The Transmission Owner will have procedures,
processes, or specifications as identified in Requirement R3, records
showing work done to support its annual work plan identified in Requirement
R7, and its quarterly vegetation reports, to demonstrate that it can prevent
encroachment into the MVCD.”
Finally, with respect to the Rationale associated with R3, how would NERC
enforce poor intent or a poor indication of competency (especially if the entity
was performing well)? Recommend: Provide a basis for evaluating whether
the Transmission Owner’s procedures, processes, or specifications used to
maintaining vegetation are achieving that goal. There may be many
acceptable approaches to controlling vegetation so that it does not encroach
into the MVCD.
And one small copyedit: “interrelationships” should not have a hyphen.
Response: The SDT thanks you for your comment.
51
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
Regarding the comments pertaining to the requirement wording: The intent of R3 in this version of the
Standard is to make sure that the Transmission Owner adequately documents and demonstrates an
understanding of the complex relationship of conductor movement under thermal and wind load and
vegetation growing and moving in proximity to the line. The SDT points out that inclusion of a programatic
list of activities by itself does nothing to to ensure reliability. R3 is a competency based requirement. The
audit test is simply one of logic. Does the methodology the TO conveys in R3 logically ensure that no
encroachments into the MVCD occur? The SDT feels that it is important for the Transmission Owner to have
the flexiblity to choose how it satisfies this requirement and not to provide a limited menu of approaches that
could be used. (eg: Our max growth rate is 3’ per year. We have a minimum ground clearance spec for 230 kV
of 24 feet at maximum sag. We maintain the lines every three years. During maintenance of 230 kV lines we
remove all vegetation over 11.5 feet high) For a “results based” standard, the emphasis should be on the
Tranmssion Owner demonstrating competency in its approach, however simple or complex that approach
may be. The violation for this requirement would be either the TO failed to specify its approach or that the
approach specified does not pass the logic test.
Regarding the comments pertaining to the measures M3: The SDT feels that an auditor knowledgeable of
utility vegetation management work would be capable to evaluate if a well documented approach is sufficient
to ensure no vegetation encroachments into the MVCD.
Regarding the comments pertaining to the Rationale: The drafting team agrees that “intent” is not
measurable or enforceable and has removed it from the rationale. The evaluation and measurement of the
competency is listed above.
13
Consumers Energy
Company
No
This really is another attempt at avoiding defining a minimum clearance
specification and is not practical. As written, this would require each
Transmission Owner to define and document the procedures, processes or
specification by individual span for every line owned or operated by the
Transmission Owner. Each span varies in length and profile and a single line
may have several different conductor types with different load ratings. Line
loadings will vary along the line based on substation taps, etc. The dynamics
described in the language could only be done on an individual span basis to
be reasonably accurate. This is not practical from a planning standpoint or
from a standpoint of implementing clearing work in the field.
Response: The SDT thanks you for your comment. The intent of R3 in this version of the Standard is to
make sure that the Transmission Owner adequately documents and demonstrates that it understands the
complex relationship of conductor movement under thermal and wind load and vegetation growing and
moving in proximity to the line. It leaves the decision to the Transmission Owner how to satisfy this
52
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
“competency based” requirement. While a Transmission Owner could certainly take the approach that each
individual span be addressed separately, it is also possible for a Transmission Owner to have a specific
“vegetation maximum height” approach based on the minimum ground clearance specification of an entire
line. Either extreme would satisfy this requirement. A Transmission Owner also could have an approach
that contained a mixture of the two extremes.
14
Allegheny Power
Yes
15
Ameren
Yes
16
American
Transmission
Company
Yes
17
BGE Forestry
Management
Yes
18
Bonneville Power
Administration
Yes
19
Central Maine Power
Company, Iberdrola
USA
Yes
20
Consolidated Edison
Company of New
York Inc
Yes
21
FPL Corporate
Compliance
Yes
22
Duke Energy
Yes
23
Entergy Services
Yes
53
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
24
Exelon
Yes
25
FirstEnergy
Yes
26
Hydro One
Yes
27
Idaho Power
Yes
28
Idaho Power
Company
Yes
29
ITC Transmission
Yes
30
Manitoba Hydro
Yes
31
Northeast Power
Coordinating Council
Yes
32
Northeast Utilities
Yes
33
Orange and Rockland
Utilities, Inc.
Yes
34
Pepco Holdings, Inc Affiliates
Yes
35
PNM
Yes
36
Progress Energy
Yes
37
South Carolina and
Gas
Yes
38
The United
Yes
Question 4 Comment
54
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
Illuminating Company
39
Tri-State Generation
& Transmission
Yes
40
Western Area Power
Administration
Yes
41
Western Electricity
Coordinating Council
Yes
Response:
42
Dominion
Yes
Although we agree with the intent of the proposed language, we feel the
requirement should be revised to read:Each Transmission Owner shall
document the procedures, processes, or specifications it uses to prevent the
encroachment of vegetation into the MVCD. Such procedures, processes, or
specifications shall consider the dynamics of a transmission line conductor’s
movement throughout its Rating and Rated Electrical Operating Conditions
and the inter-relationships between vegetation growth rates, vegetation
control methods, and inspection frequency, for the Transmission Owner’s
applicable lines.
Response: The SDT thanks you for your comment. The SDT agrees that the wording in R3 should be
modified. R3 has been revised to remove the reference to “incorporate the dynamics” and has recrafted the
requirement wording similar to your latter recommendation.
43
BC Hydro
Yes
As a competency requirement, R3 seems to be missing any requirement for
a utility to define who is qualified to develop these plans, which is a departure
from FAC-003-1 R1.3. I think that the utility should in their standards define
who is qualified to develop their transmission vegetation management
program
Response: The SDT thanks you for your comment. While the SDT agrees that personnel qualifications are
important in any pursuit for perfection, the overall approach for this version of the Standard is a “results
based’ product. In light of that, the SDT does not feel that a “fill in the blank” requirement for personnel
55
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 4 Comment
qualifications is necessary.
44
Tampa Electric
Company
Yes
This better clarifies section R3
Yes
While voting yes we are concerned about the interpretation of the expanded
verbiage, how much documentation will be enough.
Response:
45
Southern Company
Transmission
Response: The SDT thanks you for your comment. The Technical Reference Document attempts to provide
further explanation, along with examples, of how to present this information. While these examples are not
in the Standard itself, the supplemental information in the Technical Reference Document should help the
Transmission Owner understand the SDT’s intent for the requirement, and therefore the documentation
required to demonstrate competency.
56
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
5. In response to comments received that requirement R7 is unclear with respect to flexible work plans,
the SDT modified the requirement. Do you agree? Please explain.
Summary Consideration:
Of 45 respondents, there are 2 abstentions, 34 are in agreement, and 9 are in disagreement.
The major comment issues raised by those in disagreement are:
1.
2.
The Requirement is vague and needs more specificity and explanation.
•
Does not require development of the Annual Vegetation Work Plan
•
Language allowing modifications to the Work Plan should specifically require documentation of changes
•
M7 is measuring completion of Work Plan, not prevention of encroachments into the MVCD
•
The phrase “…provided they do not put the transmission system at risk of a vegetation encroachment”
could be better written as “…they do not allow encroachment of vegetation into the MVCD”
Examples describing potential reasons for plan modification should be clarified or eliminated.
•
Decreases in funding not valid.
•
Encroachments due to Major Storms are exempted in Footnote 2. R7 allows modification to Plan due to
major storms but does not allow encroachments associated with plan change.
•
Generally. the examples identified are broad in nature
Some minor comment issues are:
1.
Eliminate requirement or use the first sentence only.
2.
Some concern with lack of agreement of language with other parts of the Standard.
The VM SDT appreciated both the major and minor comment issues identified but decided that the requirement
and measures are appropriate and clear as currently written and did not modify any of the language. The SDT
reviewed the Funding Adjustment example for R7 and feels this is a valid reason for modifying the Annual Plan
keeping in mind that a modification must not place the transmission system at risk of vegetation encroachment
into the MVCD. In addition, as expressed in the Rationale, R7 sets the expectation that the work identified in the
57
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
annual work plan will be completed as planned. Documentation of the work completed (and any necessary
modifications) as written together with the lack of a violation to either Requirement 1 or Requirement 2 is the
overall reliability goal. The metric for the work plan is the percentage of the plan completed. The lack of a violation
of R1 or R2 is the outcome of the ideal work plan. It is the responsibility of the Transmission Owner to manage the
quality of the work plan and its associated modifications to mitigate the risk of a violation of R1 or R2. With
Version 2, an outage is now clearly a violation of R1 and R2 and should not be linked to a failure of the work plan.
The measure for the work plan is the percentage of the completed work as planned and we do not need to be
subjectively trying to evaluate the quality of the Transmission Owner’s work plan with this measure.
Organization
1
GDS Associates
2
MWDSC
(METROPOLITAN
WATER DISTRICT
OF SOUTHERN
CALIFORNIA)
3
Western Area Power
Administration
Yes or No
Question 5 Comment
No
As the list of “examples of reasons for modification” is not all inclusive, it is
unnecessary and could result in confusion regarding compliance when a
scenario other than one listed requires a change. Further, documentation of
changes to the annual plan adds unnecessary administrative burden which is
inconsistent with a performance based standards approach.
Response: Thank you for your response. The SDT feels the list of examples, while not all inclusive, is
helpful to the TO in determining how and when to apply flexibility to its annual plan, when required. It is
important the TO documents modefication to the plan to insure the work not completed during that period is
carried over and completed within a reasonable time frame.
4
Ameren
No
Funding Adjustments (increase or decrease) - need more description to imply
only when planned vegetation work is “over and above”.
58
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
Response: Thank you for your comment. The SDT reviewed the Funding Adjustment example for R7 and
feels this is a valid reason for modefying the Annual Plan keeping in mind that a modefication must not place
the transmission system at risk of vegetation encroachement into the MVCD.
5
MidAmerican Energy
No
MidAmerican supports the additional detail. However R7 should end after
the first sentence. All additional material should be moved to the rationale
box.
Response: Thank you for your comment. The position of the SDT is to have this langiage in the requirement
such to allow for flexibility to the work plan. Keep in mind Rationale language is clarifying documentation and
not enforcable. The SDT feels it is important that the TO have the flexibility to revise its Annual Plan which is
subject to many issues that can influence the completion of work.
6
The United
Illuminating Company
No
R1 and R2 are requirements that no encroachment occurs. R7, as
proposed, requires a VMP to be completed to ensure no encroachment
occurs. The Supplemental Reference for R7 does not describe the
requirement of the annual vegetation work plan to ensure no vegetation
encroachments occur within the MVCD. The Reference states the
requirement is established to diminish the risk of encroachment; which is
very different from ensuring no encroachment. In the Reference for R7 the
word “ensure” is only used to describe that flexibility in the VMP is allowed to
ensure the reliability of the Transmission System.M7 is measuring work plan
completion not the prevention of encroachment. United Illuminating suggests
that R7 be changed to: Each Transmission Owner shall complete the work in
an annual vegetation work plan to manage the prevention of vegetation
encroachments occur within the MVCD. In this way, a violation of R1/R2
does not necessarily mean R7 is violated. The entity does not avoid a
penalty for an encroachment because a violation of R1/R2 occurs for actual
encroachment. If an encroachment occurs the compliance enforcement
authority can review the entities vegetation management plan to determine if
it is compliance with R7/M7.
Response: Thank you for your comments. As expressed in the Rationale, R7 sets the expectation that the
work identified in the annual work plan will be completed as planned. Documentation of the work completed
(and any necessary modifications) as written together with the lack of a violation to either Requirement 1 or
Requirement 2 is the overall reliability goal. The metric for the work plan is the percentage of the plan
completed. The lack of a violation of R1 or R2 is the outcome of the ideal work plan. It is the responsibility of
59
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
the Transmission Owner to manage the quality of the work plan and its associated modifications to mitigate
the risk of a violation of R1 or R2. With Version 2, an outage is now clearly a violation of R1 and R2 and
should not be linked to a failure of the work plan. The measure for the work plan is the percentage of the
completed work as planned and we do not need to be subjectively trying to evaluate the quality of the
Transmission Owner’s work plan with this measure.
7
CenterPoint Energy
No
See response to Q3 above.However, assuming R7 is not revised to exclude
processes and procedures, the new wording is preferred since it is more
specific. Additionally, a new ambiguous phrase is introduced, “provided they
do not put the transmission system at risk of a vegetation encroachment”,
which we recommend to be changed to more specific wording, “provided
they do not allow encroachment of vegetation into the MVCD”.
Response: Thank you for your comments. The SDT felt the language was appropriate.
8
Southern Company
Transmission
No
The first sentence of the Requirement 7 Rationale conflicts with the second
sentence. The R7 Rationale should be reworded as follows:"This
requirement sets the expectation that the work identified in the annual work
plan should be completed as planned. However, an annual vegetation work
plan must allow for work to be modified in response to changing conditions.
These modifications must take into consideration the anticipated growth of
vegetation and all other environmental factors, provided that the changes do
not cause a vegetation encroachment within the MVCD."
Response: Thank you for your comments. The SDT felt the language was appropriate.
9
NERC Staff
No
This is the first instance in which an annual work plan is discussed. It would
appear necessary to first develop an annual work plan component of the
overall vegetation management program. There should also be some
performance review or expectation that the annual plan as implemented
achieved the intended program objectives, or that modifications would be
necessary.
Does R7 require both that a Transmission Owner has an annual vegetation
60
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
work plan AND that it completes the work plan? Detail is required as to what
is expected in the work plan, as there is currently no basis to judge whether
the work plan is adequate or not adequate. And what does a modification
entail? Does this mean reduction of performance, delay in performance, or
complete postponement of performance?
NERC staff is also concerned with the list of examples one might use to
modify an annual plan. Several of these items should not pose any greater
risk to vegetation contact and render the requirement virtually unenforceable.
It provides a wide array of reasons to postpone vegetation management and
may make it a very low priority for an entity:
• “Rescheduling work between growing seasons”: This could be an
honest change (if there are unexpected seasonal changes) or it could
reflect bad initial planning. If there will be occasion for auditors and
investigators to distinguish, there should be guidance on differentiating.
• “Crew or contractor availability”: This could be an honest change (if
there is an unexpected labor dispute or if crews are needed to help a
neighboring utility during an unexpected emergency) or it could reflect
bad initial planning. If there will be occasion for auditors and
investigators to distinguish, there should be guidance on differentiating.
Alternatively, it could be removed from the list as it is within the
exclusive control of the Transmission Owner.
• “Identified unanticipated high priority work”: This could be an honest
change or it could reflect bad initial planning. If there will be occasion for
auditors and investigators to distinguish, there should be guidance on
differentiating. It is also vague and would necessitate a judgment call for
enforcement.
• “Permitting delays”: Annual plans should account for anticipated
permitting schedules and maybe even add a factor for uncertainty. It is a
planning issue for the entity and should not be an acceptable excuse for
not conducting vegetation management.
• “Land ownership changed”: If a landowner has the ability to affect the
reliability of the bulk power system, the landowner should be subject to
61
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
the reliability standards. A registered entity should be responsible for the
land in its ROW, especially if it has turned control of the land, and the
ability to affect reliability of the BPS, over to another entity or person for
financial gain.
• “Funding adjustments”: NERC staff is not convinced that this is a
legitimate reason for adjusting an annual vegetation work plan.
Economic considerations should not be a reason to delay or modify
vegetation management.
• “Emerging technologies”: It is unclear what this example is intended to
accomplish.
In general, these examples should be bounded in some way to ensure that a
modification due to one of their occurrences does not impart a greater risk of
vegetation contact.
Response: Thank you for your comments. Per the SDT, developing the annual work plan is an understood
requirement in order for the TO to complete the work plan. Thus, a requirement to develop the plan is not
needed. R3 specifies the processes, procedures and/or specifications that are utilized by a TO to prevent an
encroachment of the MVCD. This “Competency Based” requirement sets the core foundation that a TO will
utilize to develop their annual work plan.
As expressed in the Rationale, R7 sets the expectation that the work identified in the annual work plan will be
completed as planned. Documentation of the work completed (and any necessary modifications) as written
together with the lack of a violation to either Requirement 1 or Requirement 2 is the overall reliability goal.
The metric for the work plan is the percentage of the plan completed. The lack of a violation of R1 or R2 is
the outcome of the ideal work plan. It is the responsibility of the Transmission Owner to manage the quality
of the work plan and its associated modifications to mitigate the risk of a violation of R1 or R2. With Version
2, an outage is now clearly a violation of R1 and R2 and should not be linked to a failure of the work plan. The
measure for the work plan is the percentage of the completed work as planned and we do not need to be
subjectively trying to evaluate the quality of the Transmission Owner’s work plan with this measure.
By bounding the flexibility as advocated, there are several variables involved such it makes it impractical to
be able to address the many operational scenerios that a TO may experience. Thus, without being very
prescriptive, the SDT feels that it is best to provide general guidance to what are valid modifications to the
work plan.
62
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
10
Kansas City Power &
Light
Yes or No
Question 5 Comment
No
This requirement is in direct conflict with the “exclusions” as described in
section 4.4. Section 4.4 makes it clear that effects of “major storms” on a
vegetation programs efforts will be allowed as an exclusion toward
compliance with these requirements, yet, R7 does not allow any
encroachment due to modifications to a vegetation plans efforts due the
“Major Storms” (second bullet) or “Weather conditions/Accessibility” (bullet
6). Please explain what is intended here that is different than what was
intended in section 4.4.In addition, this presents some audit difficulties
regarding the notion of detecting a “modified work plan”. Once a work plan is
altered and new objectives are laid out, that becomes the plan and the plans
that were replaced may be discarded since they would be of no value.
Further, what difference does it make to track or monitor any changes to a
work plan provided effective vegetation management is maintained?
Recommend the SDT consider removing the language regarding “work plan
flexibility” as this may suggest and impose an unnecessary compliance
burden on Registered Entities and Auditors.
Response: Thank you for your comments. The SDT views Major Storms in the list of examples differently
than in Footnote 2. The example has more to do with schedules being revised as a result of a major storm
while Footnote 2 refers to issues of sustained outages caused by circumstanses beyond the control of the
Transmission Owner, and excepting resulting violations to the standard.
The SDT feels it is important to track and document changes in the work plan to insure rescheduled work is
completed at some later date. Work plan flexibility through modification to the work plan is critical and must
be recognized so that the Transmission Owner can propertly plan and revise work schedules when
necessary.
11
Xcel Energy
No
What exactly does complete an annual work plan mean? It infers that an
annual work plan must be developed/documented and executed. If this is
the case, then clearly state as such.In general, R6 & R7 go against the grain
of the results based standard concept. R1 already established that the
Transmission Owner cannot have encroachment. R3 requires annual
inspection (essentially establishing the plan). Why replicate in R6 & R7, it
does not seem to serve any useful purpose.
Response: Thank you for your comments. As stated in the Rationale, “This requirement sets the
expectations that the work identified in the annual work plan will be completed as planned.” Because the
63
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
work plan is recurring in nature, a new work plan must be developed each year to state work planned for that
period. This requirement directly supports Requirement 3 which calls for a documented vegetation
management approach to prevent MVCD encroachments.
12
Allegheny Power
Yes
13
American
Transmission
Company
Yes
14
Arizona Public
Service Company
Yes
15
BGE Forestry
Management
Yes
16
Bonneville Power
Administration
Yes
17
Central Maine Power
Company, Iberdrola
USA
Yes
18
Consolidated Edison
Company of New
York Inc
Yes
19
Consumers Energy
Company
Yes
20
FPL Corporate
Compliance
Yes
21
Dominion
Yes
64
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
22
Duke Energy
Yes
23
Entergy Services
Yes
24
Exelon
Yes
25
FirstEnergy
Yes
26
Great River Energy
Yes
27
Hydro One
Yes
28
Idaho Power
Yes
29
Idaho Power
Company
Yes
30
ITC Transmission
Yes
31
Manitoba Hydro
Yes
32
Northeast Power
Coordinating Council
Yes
33
Northeast Utilities
Yes
34
Orange and Rockland
Utilities, Inc.
Yes
35
Pepco Holdings, Inc Affiliates
Yes
36
PNM
Yes
Question 5 Comment
65
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
37
PPL Electric Utilities
Yes
38
Progress Energy
Yes
39
South Carolina and
Gas
Yes
40
Tri-State Generation
& Transmission
Yes
41
Western Electricity
Coordinating Council
Yes
Question 5 Comment
annual vegetation management plans must have some flexibility. If the TO
has the authority to create the plan they should have the authority to modify
the plan. The key point is that changes, particularly delays to planned work
would have to be approved. Do not believe “decreases in funding” should be
listed as a valid reason for modification of work plan related to a reliability
standard.From an enforcement viewpoint, there is ambiguity or perceived
ambiguity in “provided they do not put the transmission system at risk of a
vegetation encroachment.” Provided the potential that there may never be a
self-report addressing this violation.
Response: Thank you for your comments. The SDT agrees the plan needs flexibility and the Transmission
Owner has authority for plan oversite. No approval for changes is called for in the requirement, but
documentation is required to note the change.
The SDT reviewed the Funding Adjustment example for R7 and feels this is a valid reason for modifying the
Annual Plan keeping in mind that a modification must not place the transmission system at risk of vegetation
encroachment into the MVCD.
42
Southern California
Edison Company
Yes
SCE agrees with the revisions to R7, but notes the some minor edits to the
text are still needed.
Response: Thank you for your comments. The SDT felt the language was appropriate.
43
MRO’s NERC
Standards Review
Subcommittee (nsrs)
Yes
The NSRS has issue with the word “may” (and its components along with the
associated bulleted points) and recommends that it is removed and placed in
the rational box.
66
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 5 Comment
Response: Thank you for your comments. The SDT believes the requirement as written is needed to insure
flexibility of work plan.
44
BC Hydro
Yes
The requirement as currently worded, seems to assume but does not
explicitly state that a utility must prepare and document an annual vegetation
work plan and document in some manner any modifications to that work
plan as they occur. The work plan change documentation should include any
risks of work deferral and mitigation plans to address those risks if there are
any.
Response: Thank you for your comments. Per the SDT, developing the annual work plan is an understood
requirement in order for the TO to complete the work plan. Thus, a requirement to develop the plan is not
needed. R3 specifies the processes, procedures and/or specifications that are utilized by a TO to prevent an
encroachment of the MVCD. This “Competency Based” requirement sets the core foundation that a TO will
utilize to develop their annual work plan.
The lack of a violation of R1 or R2 is the outcome of the ideal work plan. It is the responsibility of the TO to
manage the quality of the work plan and mitigate any risk to the system associated with modifications to the
work plan.
45
Tampa Electric
Company
Yes
These changes add greater clarity, as well as real world examples, to this
standard.
Response: Thank you for your comments.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
6. In response to comments received that requirement R1/R2 may not adequately protect the
transmission conductors under all conditions of sag and sway, the SDT drafted alternate language for
the industry to provide feedback. The SDT did not opt to incorporate this language into “Draft 4” until
further comment was solicited from industry. Which do you prefer? Please comment on your choice
in the comment box below:
“Alternate R1/R2. Each Transmission Owner shall manage the floor of its Active Transmission Line ROW in
accordance to one of the following at all times:
A) A fixed maximum vegetation height of 15 feet from the ground at the mid-half of the span and 20 feet
in the outside quarters of the span, or,
B) A calculated maximum vegetation height that is the difference between the minimum conductor height
at “max sag” minus MVCD minus cycle growth, or,
C) A calculated minimum vegetation to conductor clearance that is the sum of “max sag” in the span plus
MVCD plus cycle growth, or,
D) A value determined by the Transmission Owner to provide a separation between the conductor and the
vegetation that is comparable to options A, B, or C.
E) Any alternative approach that ensures no encroachment occurs within MVCD, considering the sag and
sway of the conductor throughout its operating range under rated conditions.
F) A value to provide a separation between the conductor and the vegetation that is the sum of MVCD,
and a value that considers the sag and sway of the conductor throughout its operating range under
rated conditions plus 10 feet.”
NOTE: The SDT suggests similar language as found in the posted draft for measures M1/M2 may be appropriate
with this Alternate R1/R2.
Summary Consideration:
Of 45 respondents, there are 4 abstentions (expressed no preference for Draft or Alternate), 16 (two of which
appear to be from the same company) are in agreement (that Alternate Language is preferred), and 25 are in
disagreement (that Alternate is preferable, liking Draft language better).
The major comment issue raised is:
1.
The only real issue raised in the comments by the 41 respondents that had a preference was that of the
style of Requirement language appropriate for an RBS standard. Both groups agreed that either the Draft or
Alternate language addressed the root requirement(s). In fact, respondents in both groups indicated that Option E
68
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
of the Alternate language was in essence the Draft language. (And of those in Alternate group that discussed the 6
options, E was the clear favorite, receiving five (5) mentions with A and C only receiving one (1).)
However, those that preferred the Alternate language cited that written in the form proposed by the
Alternate language, the Requirements R1/R2 would provide much more flexibility and two respondents even cited
that the Alternate allowed Transmission Owners to specify their own clearances.
For those voting for the Draft language (the majority), the most common reason cited was Draft language
was less prescriptive. The second most common reason cited was that the Alternate Language would be confusing.
And a couple commenters in this group opined that the Alternate language appeared to be “fill-in-the-blanks”
language.
The VM SDT consideration for the major comment issue is:
1.
Based on the “vote” the team will retain the Draft language. Also, Option E was cited most often by the
Alternate group as the most desirable of the options and is in fact essentially the Draft language. The SDT
was additionally swayed by the comments about confusion and fill-in-the-blanks as two overriding premises
behind the standards should be clarity and acceptance by FERC.
A minor comment issue is:
1.
Commenters offered several minor wording changes to the Draft language.
The VM SDT consideration for the minor comment issue is:
1.
The team has incorporated some of these minor wording changes and rejected others when the change was
found to introduce other problems.
Organization
1
Yes or No
Question 6 Comment
MWDSC
(METROPOLITAN
WATER
DISTRICT OF
SOUTHERN
CALIFORNIA)
69
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
2
Progress Energy
3
South Carolina
and Gas
4
Arizona Public
Service Company
Yes or No
Question 6 Comment
Neither version is acceptable ANSI-A300 part 7 should be included here.
Having set distances will give federal agencies the ability to minimize a
utilities TVMP.
Response: The SDT thanks you for your comments. The team appreciates your concern about federal agencies and
other landowners’ interpretation of the Requirement to impede vegetation management but is not swayed that the
language currently in the Draft version suffers from a set distance specification as you cited.
5
Bonneville Power
Administration
Alternate version of R1/R2
6
Central Maine
Power Company,
Iberdrola USA
Alternate version of R1/R2
7
PNM
Alternate version of R1/R2
8
GDS Associates
Alternate version of R1/R2
- E) seem more appropriate. The alternate R1/R2 standard requirements
shall reduce the number of possibilities and simplify the criteria towards
the design / operating conditions and additional standards ought to be
considered in concert with current stan
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft.
9
Allegheny Power
Alternate version of R1/R2
Allegheny Power prefers the alternate version.
The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many choices which
70
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
may simplify the application by Transmission Owners but is concerned that a majority of commenters find the
alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has decided to retain the
language in the current Draft.
10
PPL Electric
Utilities
Alternate version of R1/R2
Alternate C provides assurances that growth rates, maintenance cycle,
and max-sag are taken into consideration.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft because the SDT believes it already addresses the provisions
you state, i.e. growth rates, maintenance cycle, etc.
11
Hydro One
Alternate version of R1/R2
Alternate Version E would allow a Transmission Owner to use an
approach consistent with the current version of FAC-003 by defining a
minimum clearance distance and a vegetation management clearance
distance. This approach has met the objectives of FAC-003 since 2006.
Use of version E would change the standard from a prescriptive
approach to a Transmission Owner defined approach. In addition,
Alternate Version E is preferred as it allows for variations based on
differences in conductor heights, topography and other situations where
a set height is not necessarily required in all instances and allows for the
utility to determine the maximum heights of vegetation without
performing detailed calculations of what the maximum heights must be
along the various distances within each conductor span. If the utility is
tasked with managing the vegetation to ensure no encroachments into
the MVCD then it should be up to the individual utility how best to
determine its management strategies that incorporate the determination
of maximum vegetation heights in each section on its system.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft.
12
Northeast Power
Coordinating
Alternate version of R1/R2
Alternate Version E would allow a Transmission Owner to use an
approach consistent with the current version of FAC-003 by defining a
71
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Council
Question 6 Comment
minimum clearance distance and a vegetation management clearance
distance. This approach has met the objectives of FAC-003 since 2006.
Use of version E would change the standard from a prescriptive
approach to a Transmission Owner defined approach. In addition,
Alternate Version E is preferred as it allows for variations based on
differences in conductor heights, topography and other situations where
a set height is not necessarily required in all instances and allows for the
utility to determine the maximum heights of vegetation without
performing detailed calculations of what the maximum heights must be
along the various distances within each conductor span. If the utility is
tasked with managing the vegetation to ensure no encroachments into
the MVCD then it should be up to the individual utility how best to
determine its management strategies that incorporate the determination
of maximum vegetation heights in each section on its system.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft.
13
Idaho Power
Alternate version of R1/R2
Alternative R1/R2 allows the utility to maintain adequate clearances with
their preferred approach.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft.
14
FirstEnergy
Alternate version of R1/R2
Although we agree with the alternate version of R1/R2, we have the
following comments:1. We assume that R1 and R2 will be written similar
to the current proposal with regard to IROL (High VRF) and non-IROL
(Medium VRF) transmission lines, respectively. This should be clear after
changes have been made to the standard before the final ballot.2.
Although the SDT states that it "suggests similar language as found in
the posted draft for measures M1/M2 may be appropriate with this
alternate R1/R2", we are not clear how these measures will be written
and would like to see a draft of the measures so we can review and
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
comment.3. The alternate requirements appear to be "planning" in nature
instead of "real-time"; we assume the intention of the SDT was the latter.
Therefore the requirements should be revised with language that is "realtime" in nature.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft.
15
BGE Forestry
Management
Alternate version of R1/R2
BGE believes R1/R2 should contain language that ensures that
vegetation is manage taking into account sag and sway throughout the
conductors operating range as the alternate language above outlines.
The six options proposed allows the Transmission Owner the flexability
needed to manage the active ROW a varity of ways and at the same
time ensures the reliable operation the Bulk Electric System with respect
to vegetation.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft because the SDT believes it already addresses the provisions you
state, i.e. sag and sway.
16
Idaho Power
Company
Alternate version of R1/R2
I think this gives us more flexibility to maintain our clearances.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft.
17
Northeast Utilities
Alternate version of R1/R2
Option E above is preferred as it allows for variations based on
differences in conductor heights, topography and other situations where
a set height is not necessarily required in all instances and allows for the
utility to determine the maximum heights of vegetation without
73
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
performing detailed calculations of what the maximum heights must be
along the various distances within each conductor span. If the utility is
tasked with managing the vegetation to ensure no encroachments into
the MVCD then it should be up to the individual utility how best to
determine its management strategies that incorporate the determination
of maximum vegetation heights in each section on its system.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft.
18
Consumers
Energy Company
Alternate version of R1/R2
Prefer Alternative A
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft.
19
Kansas City
Power & Light
Alternate version of R1/R2
Prefer Alternative E from the list above. Please clarify the meaning of
sway in Alternative E. Is that wind blowout?
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft. Sway is synonymous with wind blowout in Alternative E. Please
refer to the Technical Reference document for further clarification on this issue.
20
Southern
California Edison
Company
Alternate version of R1/R2
SCE prefers the operational flexibility provided by the alternate version of
R1/R2. We also note that dating back to development of FAC-003-1 and
related comment periods, Transmission Owners have repeatedly stated
that a “one-size-fits-all” TVMP is not viable or reasonable.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
74
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore, the team has
decided to retain the language in the current Draft. The SDT completely agrees with your comment about the ‘onesize-fits-all’ issue. The SDT has struggled with the proper wording that would allow each Transmission Owner the
flexibility necessary to minimize the risk of vegetation outages while adapting to their unique vegetation challenges
in a cost-effective-to-consumers manner. The SDT would encourage you, in future comment periods, to offer
specific wording that will address the deficiencies you identified and what persuaded you to choose the Alternate
version of R1/R2 as the preferred version.
21
Ameren
Draft 4 version of R1/R2
22
Duke Energy
Draft 4 version of R1/R2
23
Exelon
Draft 4 version of R1/R2
24
Great River
Energy
Draft 4 version of R1/R2
25
ITC Transmission
Draft 4 version of R1/R2
26
MidAmerican
Energy
Draft 4 version of R1/R2
27
Pepco Holdings,
Inc - Affiliates
Draft 4 version of R1/R2
28
Tri-State
Generation &
Transmission
Draft 4 version of R1/R2
29
Xcel Energy
Draft 4 version of R1/R2
Any of the alternate versions would amplify or create issues between
land owners and Transmission Owners and are contrary to concepts of
Integrated Vegetation Management, in particular, best management
practices.
Response: The SDT thanks you for your comments. Based on the industry support for the Draft 4 language, the SDT
75
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
has opted to retain the language in the current draft, in part because of the confusion you cited.
30
American
Transmission
Company
Draft 4 version of R1/R2
ATC feels that Draft 4 Version of R1/R2 is the preferred version. The
Alternate version is too prescriptive and has little flexability.
Response: The SDT thanks you for your comments. Based on the industry support for the Draft 4 language, the SDT
has opted to retain the language in the current draft; in part because of the prescriptive nature of the Alternate
versions that you mentioned as well as it being noted as confusing.
31
CenterPoint
Energy
Draft 4 version of R1/R2
CenterPoint Energy does not believe a performance based requirement
should be this prescriptive. However, if the majority of industry
commenters agree with the SDT’s approach, CenterPoint Energy has
several concerns. The terminology, “operating within Rating and Rated
Electrical Operating Conditions” is sufficiently definitive. There is no
need to be more prescriptive. Alternate R1/R2 (E) is already similar to
the Draft 4 wording. Of the two alternative, we recommend keeping the
Draft 4 wording as is; however, we recommend moving the applicability
of transmission line ratings to the Applicability section of the Standard as
“4.5 Other: The Standard does not apply to any occurrence, nonoccurrence, or other set of circumstances that are beyond the Rating and
Rated Electrical Operating Conditions of the Facilities defined in 4.2.”
These conditions should be applicable to all elements and requirements
of the Standard just as the force majeure statement does.
Response: The SDT thanks you for your comments. Based on the industry support for the Draft 4 language, the SDT
has opted to retain the language in the current draft, in part because of the prescriptive nature you mentioned as
well as it being noted as confusing. The SDT has considered your excellent suggestion about the Applicability
Section. However, after extensive discussion, the SDT opted not to add the language in the Applicability Section as
the NERC framework for Applicability Sections seems to guide against it.
32
Consolidated
Edison Company
of New York Inc
Draft 4 version of R1/R2
Consolidated Edison Company of New York, Inc prefers the Draft 4
version. The wording in the VSLs should be modified for both
Requirements to include the phrase 'manage vegetation'. The phrase
'manage vegetation' requires a utility to take specific action to prevent
encroachments/outages.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
Response: The SDT thanks you for your comments. The SDT has considered your excellent suggestion about the
VSLs and decided to change the Requirements in the manner you describe.
33
Entergy Services
Draft 4 version of R1/R2
Draft 4 is acceptable, but if alternate language is chosen, it should be
similar to option E, keeping the determination simple and with as few
variables for interpretation as necessary.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which could have simplified the application by Transmission Owners but is concerned that a majority of
commenters find the alternate language confusing and potentially to be fill-in-the-blanks. Therefore the team has
decided to retain the language in the current draft.
34
Western
Electricity
Coordinating
Council
Draft 4 version of R1/R2
Draft 4 should be sufficient. If industry believes MVCD is not adequate
then the tables for MVCD should be modified to account for sag and
sway.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which could have simplified the application by Transmission Owners but is concerned that a majority of
commenters find the Alternate language confusing and potentially to be fill-in-the-blanks. Therefore the team has
decided to retain the language in the current draft. The SDT is convinced that the technically defensible MVCD is
adequate but appreciates the helpful suggestion nonetheless.
35
Manitoba Hydro
Draft 4 version of R1/R2
I would suggest adding verbage to the draft 4 version to explicitly include
the sag and sway of the conductor to the concept of "operating within
rating and electrical operating condition”
Response: The SDT thanks you for your comments. Based on the support for the Draft 4 language, the SDT has
opted to retain the language in the current draft, in part because of the prescriptive nature you mentioned as well as
it being noted as confusing. The SDT has considered your thoughtful and helpful suggestion about the explicit
language which could be added to the Requirement to make it stand-alone and not rely on the Technical Reference
document. The SDT, however, decided not to add the suggested verbiage because the team felt that the Rationale
Box addressed this issue and the Requirement, if modified, would become somewhat confusing.
36
MRO’s NERC
Standards Review
Draft 4 version of R1/R2
It is the NSRS’s opinion that that the requirement as currently written in
version 4 is consistent with the intent of a standard; i.e. stating what is
77
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Subcommittee
(nsrs)
Question 6 Comment
required as opposed to stating how to achieve what is required.
Response: The SDT thanks you for your comments. Based on the support for the Draft 4 language, the SDT has
opted to retain the language in the current draft, in part because of the prescriptive nature of the alternate that you
cited, as well as it being noted as confusing.
37
NERC Staff
Draft 4 version of R1/R2
NERC staff supports the Draft 4 version. The six options listed in the
alternative version of R1/R2 do not seem manageable from a utility
perspective. But while staff prefers the existing language, it continues to
emphasize that fall-ins from outside the ROW can impact the line and
need to be taken into consideration.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offered many
choices which may simplify the application by Transmission Owners but is concerned that a majority of
commenters, including you, find the alternate language confusing and some even cite that it may potentially be fillin-the-blanks. Therefore, the team has decided to retain the language in the current draft. Although the SDT
understands that fall ins from off-ROW trees can negatively impact the lines and a sound TVMP would include a
program to address these potential issues, it is not appropriate that off-ROW trees be included in a NERC Standard.
This is mainly because a utility does not have the rights to remove private trees and the process to acquire rights to
remove these trees is quite arduous and costly.
38
Orange and
Rockland Utilities,
Inc.
Draft 4 version of R1/R2
Orange and Rockland Utilities, Inc prefers the Draft 4 version. The
wording in the VSLs should be modified for both Requirements to include
the phrase 'manage vegetation.' The phrase 'manage vegetation'
requires a utility to take specific action to prevent
encroachments/outages.
Response: The SDT thanks you for your comments. The SDT has considered your excellent suggestion about the
VSLs and decided to change the Requirements in the manner you describe.
39
Tampa Electric
Company
Draft 4 version of R1/R2
Quite frankly, the alternatives listed above, or for that matter any other
vegetation managment options, should be establised by the utility. The
goals in R1 & R2 are very clear. The alternatives listed above will create
a double or triple standard of vegetation clearance for each different
type of Transmission construction.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
Response: The SDT thanks you for your comments. Based on the support for the Draft 4 language, the SDT has
opted to retain the language in the current draft, in part because of the confusion you mentioned.
40
Dominion
Draft 4 version of R1/R2
The alternate language proposed above suggests that methodologies
typically incorporated into processes, procedures, or specifications (as
required by R3) should also be included into performance-based
requirements R1 and R2. The incorporation of this language into R1 and
R2 would change these requirements from performance-based
requirements to hybrid performance/competency-based
requirements.The intent of R1 and R2 is to define a failure to prevent
encroachment into the MVCD. Ensuring that a TO’s processes,
procedures, or specifications demonstrate adequate means of protecting
conductors falls under R3, which incorporates transmission conductor
and vegetation dynamics and interrelationships. Therefore,
methodologies employed to manage the floor of active transmission
ROW should be incorporated into the documentation required by R3 and
proof that vegetation was managed in accordance with processes,
procedures, or specifications to prevent encroachment into the MVCD
will be demonstrated by compliance with R1 and R2.
Response: The SDT thanks you for your comments. Based on the support for the Draft 4 language, the SDT has
opted to retain the language in the current draft, in part because it was less prescriptive and more performancebased as you mentioned.
41
FPL Corporate
Compliance
Draft 4 version of R1/R2
The alternative is a fill in the blanks requirement.
Response: The SDT thanks you for your comments. The SDT recognizes that the alternate language offers many
choices which could have simplified the application by Transmission Owners but is concerned that a majority of
commenters find the Alternate language confusing and, as you cite, potentially to be fill-in-the-blanks.
42
BC Hydro
Draft 4 version of R1/R2
The alternatives above are too prescriptive. A utility should set a
preferred maintenance distance (i.e. clearance 1 in FAC-003-1) as
routine expectation and outline mitigation strategies as required in areas
where clearance 1 distances cannot be met to ensure that MVCD
distances are not encroached upon. Given the various line design
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
standards, it is the utility that must define those clearances and margins
of error based on engineering standards and the types of vegetation and
growth rates present in their operating area.
Response: The SDT thanks you for your comments. Based on the support for the Draft 4 language, the SDT has
opted to retain the language in the current draft, in part because it was less prescriptive as you cited.
43
Western Area
Power
Administration
Draft 4 version of R1/R2
The current language of Draft 4 is the most flexible and offers industry
the best opportunity for executing a cost effective and efficient program.
Response: The SDT thanks you for your comments. The SDT has struggled with wording to try to allow each
Transmission Owner the flexibility necessary to minimize the risk of vegetation outages while adapting to their
unique vegetation challenges in a cost-effective-to-consumers manner. Based on the support for the Draft 4
language, the SDT has opted to retain the language in the current draft, because the SDT believes it achieves the
goal you cited.
44
The United
Illuminating
Company
Draft 4 version of R1/R2
UI prefers the draft language because we believe the intent of R1/R2 is
to capture the actual occurrence of a vegetation related interruption or
encroachment of vegetaion into the MVCD based on actual conditions.
Response: The SDT thanks you for your comments. Based on the support for the Draft 4 language, the SDT has
opted to retain the language in the current draft. As you describe, this language captures the true intent of the
Requirements in the least confusing and prescriptive manner, as confirmed by other comments received.
45
Southern
Company
Transmission
Draft 4 version of R1/R2
We feel the alternative language is too confusing. Does a utility choose
one option from the list and expect it to cover all situations, or can the
utility pick one option from the list and apply that option to one span, and
then another option for the next span. The proposed alternate verbiage
makes no distinction as to when options can or cannot be utilized. The
language in Draft 4 seems to cover the various scenarios a utility will
face in its vegetation management program while giving the utility the
flexibility necessary to address these situations in an appropriate
manner.
Response: The SDT thanks you for your comments. Based on the support for the Draft 4 language, the SDT has
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 6 Comment
opted to retain the language in the current draft, in part because of the confusion you cited.
81
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
7. The drafting team and NERC staff disagree on an appropriate set of VSLs for Requirements R1 and R2
and the Standards Committee has directed that both sets of VSLs be posted for stakeholder
comments. Which set of proposed VSLs best supports NERC’s VSL Criteria?
Summary Consideration:
Of 45 respondents, 6 chose neither set of VSLs, 8 disagreed with the SDT, and 31 agreed with the SDT.
Among those who disagreed with the SDT the major comment issues raised are:
1.
VSLs are too low and they do not seem to differentiate between various levels of compliance. Commenter is
concerned that the difference between an encroachment that leads to an outage and one that does not is
based on nothing but luck.
2.
The NERC staff set requires a higher degree of accountability.
The VM SDT considerations for the major comment issues are:
1.
The VM SDT proposed a set of four VSLs to reflect the wide range of non-compliances to these
requirements. The NERC staff on the other hand view the outcomes as narrow.
The comment that SDT VSLs are “too low” lacks context. The commenter does not offer a frame of reference
in rendering its opinion of “too low”.
The comment about luck is without basis. The SDT asserts that vegetation related outages are directly
related to the encroachment mechanism, i.e., how vegetation contacts conductors.
The differing perspectives do not appear to be reconcilable. The VM SDT believes its VSL assignments follow
the NERC VSL Guidelines and are technically valid.
2.
The VM SDT believes the VSLs are precisely set to reflect the degree of accountability that best matches the
level of non-compliance. Grow-in’s are classified in the highest level of violation severity precisely because
it is indicative of the lowest quality of performance and therefore the entity must be held to the highest
degree of accountability in that case.
Some minor comment issues are:
1.
Criteria will be probably best represented by a mix of the two VSLs.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
2.
Neither set is correct.
The VM SDT considerations for the minor comment issues are:
1.
The VM SDT proposed a set of four VSLs to reflect the wide range of non-compliances to these
requirements. The NERC staff on the other hand view the outcomes as very narrow. The differing
perspectives do not appear to be reconcilable through a hybrid approach as you suggested.
2.
The VM SDT believes its VSL assignments follow the NERC VSL Guidelines and are technically valid.
Organization
1
MWDSC
(METROPOLITAN
WATER
DISTRICT OF
SOUTHERN
CALIFORNIA)
2
Progress Energy
3
Western
Electricity
Coordinating
Council
4
GDS Associates
Yes or No
Question 7 Comment
Criteria will be probably best represented by a mix of the two VSLs
as follows:- Keep the Lower and Moderate VSLs from SDT with both
absent Sustained Outage. Add the fall-in as specific encroachment to
the Lower VSL and grow-in as specific encroachment to the
Moderate VSL- Keep the High / Severe VSLs from NERC
Response: Thank you for your comment. The VM SDT proposed a set of four VSLs to reflect the wide range of noncompliances to these requirements. The NERC staff on the other hand view the outcomes as very narrow. The
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
differing perspectives do not appear to be reconcilable through a hybrid approach as you suggested.
5
Pepco Holdings,
Inc - Affiliates
Neither set is correct. The SDT proposed VSLs do not identify
encroachment into the MVCD of a line not in an IROL or Major
WECC transfer path, and the NERC Staff proposed VSLs do not do
not identify encroachment into the MVCD of a line that is in an IROL
or Major WECC transfer path
Response: Thank you for your comment. Measures M1 & M2 along with The Rationale boxes for R1 & R2 can be used
to understand what is meant by the MVCD. The Rational Box States:
“The MVCD is a calculated minimum distance stated in feet (meters) to prevent spark-over between conductors and
vegetation, for various altitudes and operating voltages. The distances in Table 2 were derived using a proven
transmission design method.”
6
CenterPoint
Energy
Neither. However, we recommend that High or Severe violations be
based only on Sustained Outages experienced and the reliability
importance of the transmission line. Any process or procedure based
requirement, if kept within the Standard, should have a Lower or
Moderate designation based on the utilities intent or capability to
comply with the Requirement.
Response: Thank you for your comment. The VM SDT proposed a set of four VSLs to reflect the wide range of noncompliances to these requirements. The NERC staff on the other hand view the outcomes as very narrow. The
differing perspectives do not appear to be reconcilable. Your suggestion is appreciated, however the VM SDT
believes its VSL assignments follow the NERC VSL Guidelines and are technically valid.
7
Consumers
Energy Company
VSLs proposed by NERC staff
8
Idaho Power
Company
VSLs proposed by NERC staff
9
FPL Corporate
Compliance
VSLs proposed by NERC staff
Again the drafting team is trying to control the terms of a requirement
by using the compliance elements. FPL agrees there is a direct link
between vegetation growing in to conductors from below has a direct
correlation to cascading events and fall-in and blow-in outages are no
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
more incidental than a cross arm failure to a cascading event. These
components should be handled in the requirements and not in the
compliance element.
Response: Thank you for your comment. The VM SDT proposed a set of four VSLs to reflect the wide range of noncompliances to these requirements. The NERC staff on the other hand view the outcomes as very narrow. The
differing perspectives do not appear to be reconcilable. The VM SDT believes its VSL assignments follow the NERC
VSL Guidelines and are technically valid.
10
Dominion
VSLs proposed by NERC staff
As all parts of R1/R2 seem to contribute equally to the intent of the
requirement - shall manage vegetation to prevent encroachment that
could result in a Sustained Outage - NERC’s proposed VSLs best
address noncompliance with the requirements.
Response: Thank you for your comment. The VM SDT proposed a set of four VSLs to reflect the wide range of noncompliances to these requirements. The NERC staff on the other hand view the outcomes as very narrow. The
differing perspectives do not appear to be reconcilable. The VM SDT believes its VSL assignments follow the NERC
VSL Guidelines and are technically valid.
11
NERC Staff
VSLs proposed by NERC staff
NERC staff supports the VSLs proposed by NERC staff. The SDT’s
VSLs are too low, and they do not seem to differentiate between
various levels of compliance. Still, staff is concerned that the
difference between an encroachment that leads to an outage and
one that does not is based on nothing but luck.
Response: Thank you for your comment. The VM SDT proposed a set of four VSLs to reflect the wide range of noncompliances to these requirements. The NERC staff on the other hand view the outcomes as very narrow.
The comment that SDT VSLs are “too low” lacks context. The commenter does not offer a frame of reference in
rendering its opinion of “too low”.
The comment about luck is without basis. The MVCD distances are conservative and it is quite possible to be well
within the MVCD and not have a flashover or an outage. This is based on physics, not “luck”. Prudent inspection
frequencies and a good imminent threat notification process are 2 things that could prevent encroachments from
becoming an outage. Stating that it is only dependent on luck does not give proper credit to prudent operations.
The SDT has revised R1 and R2 to clarify that the level of maintenance is the primary focus of this requirement that
must be attained to be compliant. The VM SDT feels these changes will ensure congruence between the requirements
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
and the VSL.
12
Arizona Public
Service Company
VSLs proposed by NERC staff
Requires a higher degree of accountability as it should be.
Response: Thank you for your comment. The VM SDT proposed a set of four VSLs to reflect the wide range of noncompliances to these requirements. The VM SDT believes the VSLs are precisely set to reflect the degree of
accountability that best matches the level of non-compliance. A grow-in is classified in the highest level of violation
severity precisely because it is indicative of the lowest quality of performance. Therefore, the entity must be held to
the highest degree of accountability for any maintenance failure that leads to a grow-in. The VM SDT believes its VSL
assignments follow the NERC VSL Guidelines and are technically valid.
13
Idaho Power
VSLs proposed by NERC staff
Seems like there should be a lesser severity level for violations for
R3-R7.
Response: Thank you for your comment. This question asks for feedback on the VSLs assigned to R1 and R2.
14
The United
Illuminating
Company
VSLs proposed by NERC staff
United Illuminating agrees with NERC Staff that the Requirement is
to prevent encroachment of any kind. Differentiating between fall-in
and grow-in is of no consequence to the intent of the requirement.
Response: Thank you for your comment. Please refer to the SDT response to NERC on this question.
15
Allegheny Power
VSLs proposed by the VM SDT
16
Ameren
VSLs proposed by the VM SDT
17
BGE Forestry
Management
VSLs proposed by the VM SDT
18
Bonneville Power
Administration
VSLs proposed by the VM SDT
19
Duke Energy
VSLs proposed by the VM SDT
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
20
Exelon
VSLs proposed by the VM SDT
21
ITC Transmission
VSLs proposed by the VM SDT
22
Manitoba Hydro
VSLs proposed by the VM SDT
23
MidAmerican
Energy
VSLs proposed by the VM SDT
24
MRO’s NERC
Standards Review
Subcommittee
(nsrs)
VSLs proposed by the VM SDT
25
Northeast Utilities
VSLs proposed by the VM SDT
26
PPL Electric
Utilities
VSLs proposed by the VM SDT
27
South Carolina
and Gas
VSLs proposed by the VM SDT
28
Tri-State
Generation &
Transmission
VSLs proposed by the VM SDT
29
Xcel Energy
VSLs proposed by the VM SDT
30
Central Maine
Power Company,
Iberdrola USA
VSLs proposed by the VM SDT
Question 7 Comment
Agrees with SDT that violation risk factors must be ranked in
accordance with impact on the bulk delivery system.
Response: Thank you for your comment.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
31
Organization
Yes or No
Question 7 Comment
Kansas City
Power & Light
VSLs proposed by the VM SDT
Although the Drafting Team is favored here, it makes little sense in
the NERC Staff VSL to have an encroachment with no sustained
outage as a HIGH VSL. No compromise of the real-time reliability of
the bulk electric system occurred. How could that be a HIGH? If it is
determined to use the VSLs proposed by NERC Staff, it is
recommended to change the HIGH VSL to LOWER.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
32
American
Transmission
Company
VSLs proposed by the VM SDT
ATC believes the VSLs proposed by the VM SDT best supports the
NERC’s VSL Criteria. The NERC Staff VSLs do not allow for Lower
or Moderate VSLs which recognizes significant value as nearly
meeting the intent of the requirement. Furthermore, it does not allow
for encroachment where absent a sustained outage. Every
encroachment in real time would not go directly to a “High” VSL
where performance has limited value.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
33
FirstEnergy
VSLs proposed by the VM SDT
FE supports the VSL proposed by the SDT. We believe these have
been developed in accordance with the FERC approved VSL
guidelines and represent the appropriate violation levels for situations
of varying probabilities. History has proven the grow-ins are the
biggest cause of vegetation contact issues, and fall-ins and blowing
together vegetation are very hard to predict and control and should
be at lower violation levels. Although we believe that an
encroachment into the MVCD that causes no system disturbance
should not be penalized if an entity takes immediate action to restore
the minimum clearance, the assignment of a Lower VSL is
appropriate. We believe that the NERC staff opinion that this situation
warrants a High VSL does not demonstrate thorough rationalization
because it fails to consider the consequences that would place a
severe monetary penalty on an entity for a situation that did not
cause a fault, outage, or cascade of the BES.Furthermore, it is clear
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
from the bullet points under R1 and R2 of the proposed standard
language that the SDT intended that an encroachment with a
sustained outage is different than and encroachment without a
sustained outage otherwise they would not have specified the
bulleted situations in detail. Had the SDT intended for there to be
only two violation severity levels they would have only specified two
bullet items: an encroachment with a sustained outage and an
encroachment without a sustained outage. The requirements are the
only tools the drafting team has to specify its intent in this area and
the approach they used is reasonable to provide these levels of
differentiation.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
34
Great River
Energy
VSLs proposed by the VM SDT
GRE prefers the Drafting Team’s VSLs over the VSLs written by the
NERC staff. The VSLs that were written by the SDT appear to be
clearer and less subjective as opposed to the VSLs that were written
by NERC staff. The VSLs written by the NERC staff came across as
being less clear and more subjective.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
35
Southern
California Edison
Company
VSLs proposed by the VM SDT
SCE agrees with the SDT's rationale and proposals for VSL Criteria.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
36
Tampa Electric
Company
VSLs proposed by the VM SDT
Tampa Electric agrees with the SDT statement ... “For example, not
all encroachments lead to Sustained Outages.” As such, we agree, a
lower level of VSL is appropriate. Tampa Electric also agrees with
this statement “ Moreover, there is an operational differentiation
between a fall-in, blow-together or grow-in event. “Recommend the
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
team examine the analytical rational for the following statements so
as to better explain and clarify this issue to NERC. “A fall-in has
never been known to cause a cascading outage. Therefore the team
feels that a Lower VSL is appropriate. A blowing-together-caused
fault is somewhat more egregious than a fall-in, as it has the potential
for re-occurring and is therefore assigned a Higher VSL.”
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
37
PNM
VSLs proposed by the VM SDT
The expectation is for perfection or zero encroachments at all times.
It would be cost prohibitive to maintain the system under those rules.
PNM recommends the VM SDT VSL’s.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
38
BC Hydro
VSLs proposed by the VM SDT
The NERC staff recommendation is too restrictive and does not seem
realistic in an operational sense. We do not agree that the standard
should apply to outages from vegetation falling into the conductor
from within the active transmission right of way. This normally would
not occur except during storm events that would be excluded from
this standard. It is operationally difficult to know precisely where the
edge of the right of way is in all situations and under all conditions.
Further, in clearing some sections to this degree, the utility could end
up destabilizing what is currently a stable, windfirm edge and pose
higher security risks to the transmission system from destabilizing the
vegetation through excessive clearing. So this gets down to
semantics of how a utility might define their active right of way
corridor relative to the legal statutory right of way edge. The risk of
fall into outages needs to be managed but as currently defined this is
too absolute a requirement. Fall-into outage risks need to be
mitigated but they have not been a key element of any cascading
failure and are hard to prevent. Even if a right of way were cleared
sufficiently wide to avoid a fall-into outage, there is always a risk of
branches being blown into the conductors from sailing during higher
winds (e.g. Douglas-fir branches have excellent airborne gliding
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 7 Comment
abilities). The greatest risk is from grow-into outages or from
conductors and vegetation being blown into one another within the
active right of way. Therefore, we prefer the VSLs set by the VM
standard development team.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
39
Consolidated
Edison Company
of New York Inc
VSLs proposed by the VM SDT
The wording in the VM STD VSLs should be modified to include
whether or not the TO managed any vegetation on that particular
line. A more severe VSL should be assigned to any encroachment or
sustained outage that was caused as a result of a TO not performing
any vegetation management activities on that line. For example, if
vegetation management activities were completed on 80% or 90% of
the line and additional work was in progress on the remainder of the
line but an encroachement or sustained outage occurred on the
spans that were scheduled to be done as part of the annual plan, the
TO should be held accountable for this but at a lower severity level.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
40
Hydro One
VSLs proposed by the VM SDT
The wording in the VM STD VSLs should be modified to include
whether or not the TO managed any vegetation on that particular
line. A more severe VSL should be assigned to any encroachment or
sustained outage that was caused as a result of a TO not performing
any vegetation management activities on that line. For example, if
vegetation management activities were completed on 80% or 90% of
the line and additional work was in progress on the remainder of the
line, but an encroachment or sustained outage occurred on the spans
that were scheduled to be done as part of the annual plan, the TO
should be held accountable for this but at a lower severity level.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
41
Northeast Power
Coordinating
Council
Yes or No
Question 7 Comment
VSLs proposed by the VM SDT
The wording in the VM STD VSLs should be modified to include
whether or not the TO managed any vegetation on that particular
line. A more severe VSL should be assigned to any encroachment or
sustained outage that was caused as a result of a TO not performing
any vegetation management activities on that line. For example, if
vegetation management activities were completed on 80% or 90% of
the line and additional work was in progress on the remainder of the
line, but an encroachment or sustained outage occurred on the spans
that were scheduled to be done as part of the annual plan, the TO
should be held accountable for this but at a lower severity level.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
42
Orange and
Rockland Utilities,
Inc.
VSLs proposed by the VM SDT
The wording in the VM STD VSLs should be modified to include
whether or not the TO managed any vegetation on that particular
line. A more severe VSL should be assigned to any encroachment or
sustained outage that was caused as a result of a TO not performing
any vegetation management activities on that line. For example, if
vegetation management activities were completed on 80% or 90% of
the line and additional work was in progress on the remainder of the
line but an encroachement or sustained outage occurred on the
spans that were scheduled to be done as part of the annual plan, the
TO should be held accountable for this but at a lower severity level.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
43
Entergy Services
VSLs proposed by the VM SDT
This gives the option to activate and follow the Imminent Threat
Process if a breach of the MVCD is located and reported for isolated
events absent a sustained outage. It gives the TO the opportunity to
mitigate the issue when it is identified and corrected prior to
experiencing an outage..
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
44
Organization
Yes or No
Western Area
Power
Administration
VSLs proposed by the VM SDT
Question 7 Comment
Unlike a “grow-in”, a “fall-in” or “blow-in” has never caused or
contributed to a cascading outage. Further, the “zero tolerance”
approach of this standard remains impractical and unreasonable.
The gradated indicators of program performance associated with a
“fall-in”, “blow-in” and “grow-in” offer some measure of
reasonableness to the requirement.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
45
Southern
Company
Transmission
VSLs proposed by the VM SDT
We support the SDT version of the VSLs. The version proposed by
staff does not recognize the objective of FAC-003-2 which clearly
states, “To improve the reliability of the electric Transmission system
by preventing those outages that could lead to Cascading.” If a fall-in
occurs in an afternoon thunder storm and investigation reveals the
tree was on the right-of-way by one or two feet, staffs VSLs would
treat this outage with the same severity as an outage where a fully
loaded line in a heat wave sagged into unmaintained brush growing
directly beneath the conductor. The first case would rarely, if ever,
lead to cascading. The second case could easily lead to cascading.
Staff’s VSLs seem to indicate a desire to “gold plate’ the system to
insure 100% reliability, which will never be achieved absent of
unlimited resources and with total disregard to cost.
Response: Thank you for your comment. The VM SDT believes its VSL assignments follow the NERC VSL Guidelines
and are technically valid.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
8. Is there anything that you have not addressed above regarding the draft FAC-003-2 Transmission
Vegetation Management standard or the Technical Reference Document? If yes, please provide what
you believe should be changed, added or deleted and the rationale for your proposal.
Summary Consideration:
Of the 45 respondents, 29 provided a comment. In general, there were no common themes and as such each
comment was responded to individually. Of some note, two comments were especially lengthy and their wellconsidered responses are found below.
Organization
Yes or No
1
Great River Energy
2
Allegheny Power
No
3
Central Maine Power
Company, Iberdrola
USA
No
4
Consumers Energy
Company
No
5
Duke Energy
No
6
Exelon
No
7
Manitoba Hydro
No
8
Northeast Utilities
No
9
Pepco Holdings, Inc Affiliates
No
10
PNM
No
Question 8 Comment
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
11
PPL Electric Utilities
No
12
South Carolina and
Gas
No
13
Tri-State Generation
& Transmission
No
14
Western Area Power
Administration
No
15
Western Electricity
Coordinating Council
No
16
Tampa Electric
Company
No
No additional comments
17
GDS Associates
Yes
- Effective Dates. Clarify effective dates in paragraphs 2 and 3. This should
only be applicable to Canada as Standard are not mandatory and
enforceable in the US unless further approved by FERC.- Exceptions.
Regional Differences must be approved just li
Response: The SDT thanks you for your response. NERC staff will review the effective date section and
modify as necessary.
18
Progress Energy
Yes
1) On p. 3 of the redline, the table of Effective Dates is struck out, but the key
(listed as 1, 2, 3 below the table: “1. First calendar day...”) remains but now
the numbers 1, 2, and 3 no longer refer to the table of Effective Dates as the
table has been struck. 2) The first paragraph under “Exceptions” could be
reworded to be clearer. As currently proposed, it states lines below 200kV
become subject to the standard 12 months after the lines are designated as
being subject to the standard, which is somewhat circular. We propose
instead:”A line operated below 200kV becomes subject to this standard 12
months after the date the Planning Coordinator or WECC initially designates
the line as an element of an IROL or as a Major WECC transfer path.”3)
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
Applicability Section 4.2.4 says the standard does not apply to Facilities
located in the fenced area of a switchyard. However, p. 8 in Section 5
Background says the standard does not apply to underground or submarine
lines or line sections inside a station boundary. Two things should be
addressed to make these consistent: “Facilities” is a NERC-defined term that
includes more than just lines, and includes lines, generators, compensators,
transformers, etc. Also, is the “station boundary” always defined by the
fenced area? Any potential conflict due to this inconsistency should be
resolved.4) In the redline of Draft 4, in R5 and M5, the word “interim” is struck
through. However, the Rationale box says “....the intent is for the
Transmission Owner to put interim measures in place...” The use of “interim”
should be consistent between R5, M5 and the Rationale box.5) R6 requires
the TO to perform Vegetation Inspections “at least once per calendar year”.
There could potentially be future interpretation requests that question
whether “once per calendar year” means performance sometime during each
year (i.e. 2010, 2011, etc.), or whether no more than 365 calendar days can
elapse between inspections. The first interpretation could allow up to almost
2 years to elapse between inspections even when doing it “once per calendar
year”. This should be clarified.
Response: The SDT thanks you for your response. NERC staff will review the effective date section and
modify as necessary. Thank you for the wording, but overall industry consensus does not dictate a verbiage
change.
Regarding station boundaries and underground lines, overall industry consensus is that line-based
vegetation programs do not apply inside the station boundary. The SDT believes that “fence” is the best
overall term for a station boundary.
As to the use of “interim”, the Rationale intends to provide clarifying text and there is no imperative that its
language should be identical to the requirement verbiage. The SDT believes that the Rationale language
properly conveys the intent.
Regarding the inspection frequency, the SDT added an 18 month clause.
19
CenterPoint Energy
Yes
1. CenterPoint Energy believes the proposed FAC-003-2 is not a performancebased standard, despite being labeled as such, because it remains too
focused on processes and procedures. CenterPoint Energy fails to see
much difference in the approach from the current Standard.
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
CenterPoint Energy believes a performance based requirement would
provide performance criteria that an entity would be measured against. An
example of a performance based requirement would be the following:
R1. “Each Transmission Owner shall manage vegetation to prevent
encroachment that results in no more than one (1) Sustained Outage
per XXX circuit miles of applicable lines within any twelve (12) month
period.”
M1. Each Transmission Owner has evidence that it had in no more than
one (1) Sustained Outage per XXX circuit miles of applicable lines within
any twelve (12) month period. Examples of acceptable forms of
evidence may include dated reports of vegetation-related Sustained
Outages or dated attestations as to no vegetation-related Sustained
Outages have occurred.
However, if the majority of industry commenters agree with the SDT’s
approach, CenterPoint Energy has the following additional concerns:
2. The phrases “active transmission line ROW” and “Active Transmission Line
ROW” are no longer considered defined terms and should be deleted from
the Standard along with footnote 2, the Compliance Section for Periodic
Data Submittal as well as the Guidelines and Technical Basis. As found
throughout the Standard, the phrase should be replaced with the common
terms utilized in the Guidelines and Technical Basis section, “Transmission
Owner’s transmission ROW as defined by easement, fee simple, or other
legal rights”.
3. In the Background section fall-ins are characterized as “statistically
intermittent” and “these types of events are highly unlikely to cause largescale grid failures”. We agree and therefore recommend that fall-ins be
excluded from the Requirements R1, R2, and Periodic Data Submittal of
outages.
4. R4 should be deleted. R4 is related to processes and procedures and
should be combined into R3. The result of not following the notification
process or procedure is that a Sustained Outage may occur that would be
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Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
captured by M1 and M2. The process and procedure would be measured
by M3.
5. R5 and M5 contain the ambiguous phrase, “where a transmission line is put
at risk due to the constraint”. This phrase should be replaced with the more
specific terminology in R1 and R2 as, “where a transmission line cannot
perform within its Rating and Rated Electrical Operating Conditions due to
the constraint” or as in R3 as “where a transmission line will be subjected to
an encroachment into the MVCD due to the constraint”.
6. For R6, the detailed rationale and studies used for the determination of the
required one year inspection cycle should be included in the Guidelines and
Technical Basis. The explanation provided in the Rationale that it is “based
upon average growth rates across North America and on common utility
practice” are unfounded and arbitrary without a specific reference to a North
American study.
7. R7 contains the ambiguous phrase, “provided they do not put the
transmission system at risk of a vegetation encroachment”. This phrase
should be replaced with the more specific terminology in the Rationale for
R7 and Requirement R3 as “provided they do not allow encroachment of
vegetation into the MVCD.”
8. Just as the force majeure statement was moved to the Applicability section
of the Standard, the exception for applicability beyond the Rating and Rated
Electrical Operating Conditions should be included in the Applicability
section as well. Currently, it is only included in R1, R2, and R3. It should be
made clear that the other Requirements and Measurements ARE NOT
applicable in situations beyond the Rating and Rated Electrical Operating
Conditions. This is already discussed in the Guidelines and Technical Basis
but not evident within the Standard.
9. The Periodic Data Submittal should be clarified to as to the specific
conditions under which Sustained Outages are reported. The Applicability
section includes the force majeure; however, other exclusions are not so
evident. We recommend the wording be changed to include all applicable
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exclusions for added clarity.
We recommend the following wording: “The Transmission Owner will submit
a quarterly report to its Regional Entity, or Regional Entity’s designee,
identifying the Sustained Outages caused by vegetation, as defined in the
categories below, of transmission lines operating within Rating and Rated
Operating Conditions as determined by the Transmission Owner, exclusive
of the force majeure conditions in Section 4.4, that include, as a minimum,
the following.”
Also, the within the Categories listed, the phrases “active transmission line
ROW” should be deleted and replaced with “Transmission Owner’s
transmission ROW as defined by easement, fee simple, or other legal
rights”. This places the determination of the width of the ROW for
determination of fall-in violations clearly on the Transmission Owner and the
within the limits of its legal rights to control the vegetation that has fallen into
the line under R1 and R2 causing the submittal of a reportable sustained
outage.
10. The Guidelines and Technical Basis and the Technical Reference with the
Gallet Equation should be combined into one document as a supplement to
the Standard to avoid duplication in wording and misinterpretation of
context.
11. We agree that the Rationale test boxes should be deleted from the Standard
and applicable explanatory text be included within the Guidelines and
Technical Basis.
12. The Guidelines and Technical Basis should include the background and
basis for 4.2.4 that excludes the Standard from applying to fenced
substations.
13. The Guidelines and Technical Basis should contain more specific examples
of violations of the Requirements and highlight specific exceptions related to
vegetation related outages, especially fall-ins and force majeure exclusions.
14. The language in R6 refers to inspecting “transmission lines” and Table 1 for
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R6 refers to inspecting “ROW”. Both areas should use consistent
terminology.
15. In the Guidelines and Technical Basis section for R6, the reference to the
VSL calculation units and the example units should be consistent-the
example should use “circuit miles”, not just “miles”.
16. In general, the proposed FAC-003-2 has gone FAR beyond what was
contemplated by the Commission in FERC Order 693 and equates to a total
re-writing of the Standard for no apparent reason. The Commission's
determination dealt with the following areas:
(1) applicability;
(2) inspection cycles; and
(3) minimum clearances on National Forest Service lands.
For instance in Paragraph 729, the Commission states, “As proposed in the
NOPR, the Commission approves Reliability Standard FAC-003-1 with no
proposed modification on the issue of clearances. The Commission
reaffirms its interpretation that FAC-003-1 requires sufficient clearances to
prevent outages due to vegetation management practices under all
applicable conditions....” Rewriting the minimum clearances introduced a
new set of confusing definitions, and further burdens the Transmission
Owners with new documentation requirements with little if any benefit when
compared to the Clearance 2 concept in the existing Standard.
A preferred approach should be to incorporate the following few items into
the existing Standard FAC-003-1:
(1) the RC versus the RRO;
(2) the designation of a specific inspection frequency;
(3) the Gallet equation; and
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(4) the applicability to National Forest Service lands.
Response:
1) The SDT thanks you for your responses. The standard is intended to be a Results-based standard and
includes requirements that are risk-based, competency-based and performance-based. The SDT and
NERC staff feels that it represents a significant departure from previous versions. The SDT has
considered “per-mile”-based metrics, but believes that FERC will not approve such a metric due to
statutory constraints and its stated criteria for approval of a standard.
2) Based on your comment and others, the SDT has revised the definition of ROW in the NERC Glossary
and removed Table 3.
3) While the SDT agrees that fall-ins are statistically intermittent, the fall-ins from inside the ROW are under
the control of the TO and represent an erosion of reliability.
4) The SDT agrees that there is some logic in your proposal, but the SDT feels that all TOs should have a
procedure that results in a defense-in-depth strategy as is in the current draft.
5) R5 applies in the longer-term Operations Planning time horizon, whereas R1 and R2 apply in real time.
On the other hand, R3 is a competency-type of requirement that applies in the Long-Term Planning Time
Horizon.
6) The SDT posed the question of inspection frequency to the overall industry in an earlier posting and
received general consensus that a one-year interval would be appropriate but did add an 18 month
clause.
7) R7 addresses shorter-term risks, whereas the language in R3 is about the prevention of encroachments
in the wider long-term horizon.
8) The SDT has considered your suggestion about the applicability section; however, after extensive
consideration, the SDT opted not to add the language you suggested since the NERC framework for the
Applicability section guides against it.
9) Thank you. The SDT agrees and hereby adds “. . . except as excluded in Footnote 2” before “that
includes.” Regarding your suggestion on active TLROW, the SDT changed the definition of ROW in the
NERC Glossary.
10) The issue of combining these documents will be addressed by NERC as the results-based standard-
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making procedural document is finalized.
11) The final resolution of this issue will be addressed by NERC as the results-based standard-making
procedural document is finalized.
12) The SDT believes that industry generally supports the exclusion of substations from applicability of the
standard, and does not believe that every clause or portion of the Standard needs an explanation in the
Guidelines and Technical Basis.
13) The team does not feel that extensive examples, especially of violations, have a place in the Standard.
14) You have pointed out a conflict in nomenclature between two portions of the standard. The team will
resolve the conflict.
15) As mentioned in both M6 and the VSL table for R6, the TO may choose its unit of measure.
16) The SDT considered the SAR and FERC Order 693 directives together with the imperative that reliability
not suffer with the revised standard, and feels that it has improved the Standard accordingly.
20
Kansas City Power &
Light
Yes
1. Part R4.3, “Enforcement, under Section 4, “Applicability”, is confusing as
to why it is needed. What is the intended purpose of this part? It is clear that
each Requirement, Measure, VRF and VSL when adopted by the NERC
BOT and FERC become mandatory and enforceable on the declared
effective date(s). There is no need for Part R4.3 to reinforce the compliance
enforcement dictated by the established NERC Rules of Procedure.2.
Requirement R4: The requirement is clear to notify the appropriate control
center regarding conditions that might cause a fault on a transmission facility.
The requirement should be clear, this for the Transmission Owners
applicable lines and recommend the SDT modify the language in R4 to that
end. In addition, there is no action other than notification in regards to this
operating condition. Highly recommend the SDT consider adding language
to take “immediate actions” to remedy the vegetation condition and remove
the threat.3. Requirements R5 & R7 are not clear in that they are for the
Transmission Owners applicable lines. This has been a common theme
throughout this Standard and by the omission of this language, it is not clear
that the intended scope of the requirements do not go beyond the applicable
lines.
Response:
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1. Thank you for your comment. NERC staff will address this concern.
2. The SDT feels that the applicability of lines is sufficiently clear in R4. However, it is not appropriate for
this Standard to specify any particular action for the TOP to take; this is the realm of TOP-006.
3. The SDT feels that the applicability of lines is sufficiently clear in R5 and R6.
21
American
Transmission
Company
Yes
1.) Rationale boxes associated with R1, R2 and R3 within the standard
include reference Tables and Figures in the “Guidelines and Technical Basis”
without specifying where they are located. ATC recommends inserting this
information as applicable.2.) ATC raises a previous draft concern on
including Rationale Boxes plus Guidelines and Technical Basis as part of the
NERC Reliability Standard. ATC recommends that the SDT either remove
these sections or make them separate from the formal standard to eliminate
any risk that these may be construed as requirements. An alternative
method is to very clearly identify which parts of the standard are subject to
compliance and considered mandatory and which are not considered
requirements and are only for guidance in meeting the requirements. 3.)
ATC believes the Measurements are well written and provide guidance on
acceptable compliance evidence related to the requirement.4.) Measurement
M2 related to R2 states that outages related to encroachments have records
confirming no Real-Time observations of any MVCD encroachments. ATC
feels this would be hard to prove as a negative. It could require one to show
every single patrol or inspection has documentation stating no real time
encroachments were observed.5.) Editorial Comment on Draft SDT VSLs for
R2: To clarify the statements made for the Moderate, High and Severe
VSLs. please add the verbiage, “into the MVCD” after “The TO had an
encroachment.......”
Response:
1) The formatting of these Rationale boxes is not set and will be addressed by NERC as the results-based
standard-making procedural document is finalized.
2) This issue will be addressed by NERC as the results-based standard-making procedural document is
finalized.
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3) Thank you for your comments.
4) As stated in the Measure, an attestation serves as adequate evidence.
5) Thank you for noticing this oversight. It will be corrected.
22
MRO’s NERC
Standards Review
Subcommittee (nsrs)
Yes
1.) The NSRS notices that a previous draft concern on including Rationale
Boxes plus Guidelines and Technical Basis as part of the NERC Reliability
Standard. The NSRS recommends that the SDT either remove these
sections or make them separate from the formal standard to eliminate any
risk that these may be construed as requirements. An alternative method is
to very clearly identify which parts of the standard are subject to compliance
and considered mandatory and which are not considered requirements and
are only for guidance in meeting the requirements. Such as; State within in
the text that this information “Is not subject to enforcement”. 2.) The NSRS
believes the Measurements are well written and provide guidance on
acceptable compliance evidence related to the requirement.3.) Measurement
M2 related to R2 states that outages related to encroachments have records
confirming no Real-Time observations of any MVCD encroachments. The
NSRS feels this would be hard to prove as a negative. It could require one to
show every single patrol or inspection has documentation stating no real time
encroachments were observed.4.) Editorial Comment on Draft SDT VSLs for
R2: To clarify the statements made for the Moderate, High and Severe
VSLs. please add the verbiage, “into the MVCD” after “The TO had an
encroachment.......”
Response:
1. This issue will be addressed by NERC as the results-based standard-making procedural document is
finalized.
2. Thank you for your comments.
3. As stated in the Measure, an attestation serves as adequate evidence.
4. Thank you for noticing this oversight. It will be corrected.
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BGE Forestry
Management
Yes
4.2.4 States that the Standard is not applicable to “...to Facilities .... located
inside the fenced area of a switchyard, station or substation”. This implies
that anything within the fenced area of a switchyard, substation or power
plant does not fall within the jurisdiction of FAC-003-2. Some fenced in areas
could be very large and susceptible to vegetation encroachments issues.
Suggest reference to “inside the fence” be removed.Disagree with R6. Inspection Frequency. Very prescriptive. Please consider allowing TO’s to
select an annual frequency that best fits their requirements, such as calendar
year, every growing season, every non-growing season, etc. BGE currently
defines their inspection frequency as annually during the non-growing
season, October 1 to May 1. BGE believes inspecting during the dormant
season is a best practice due to the ability of the inspector to identify
vegetation defects, especially off the ROW, which could be hidden during the
growing season due to foliage, canopy cover, etc. Also, if a utility elects to
leverage an advance technology, such as LiDAR, it provides the most
effective results when LiDAR is utilize during the growing season, therefore
allowing the results of the advance technology to enhance the fall to spring
inspection cycle. Table 1 - Time Horizons, Violation Risk Factors, and
Violation Severity Levels The VSL’s for R7 all include “the Transmission
Owner failed to complete.....% of its annual work plan (including
modifications if any)”. This is not clear to BGE. R7. allows plans to be
modified due to changing conditions, for example ROW maintenance could
be deferred to the following year due to mutual assistance agreements if the
deferment does not violate the encroachment within the MVCD. The VSL
implies this is a violation since the “modification” deferred a certain
percentage of the planned worked to the following year, therefore 100% of
the planned worked wasn’t completed. If the modification was excluded, than
100% of the planned work would have been completed.
Response:
1. Regarding station boundaries, overall industry consensus is that line-based vegetation programs do not
apply inside the station boundary. The SDT believes that “fence” is the best overall term for a station
boundary.
2. While the SDT lauds BGE’s approach, it feels that a calendar year basis affords sufficient flexibility for
BGE and other TOs to schedule their inspections.
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3. The Standard suggests that the TO will begin with an original plan which may then be modified; it is
implicit that measurements of plan completion are against the modified plan, not against the original
plan.
24
MidAmerican Energy
Yes
Any references to "observed in real time" should be removed. Vegetation
contacts must be verified and references to real time are inappropriate. This
causes difficulties in proving a negative in real time.
Response: The SDT believes that the commenter has misinterpreted the requirement. It is not necessary for
the TO to continuously observe; rather, a violation can only be reported if observed in real time.
25
NERC Staff
Yes
Effective Dates
•
•
•
The first item should be re-written to “First calendar day of the
first calendar quarter one year after the date of the order
approving the standard from applicable regulatory authorities
where such explicit approval is required.”
The second item is not needed and should be removed.
The third item is okay but the phrase “where explicit regulatory
approval is not required” should be removed.
Exceptions
•
Identifying a critical line and then waiting 12 months to
perform vegetation management is counter to the risk
avoidance strategy that the standard is attempting to
accomplish. In effect, this standard permits an entity to
identify a major WECC path or an IROL just prior to peak
season and then not complete any vegetation management
activities until just before the next season 12 months later.
This is wholly inappropriate. The Planning Coordinator will
identify these lines sufficiently far in advance that the 12month window will prevent encroachments
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•
•
Using the phrase “an element of an IROL” seems confusing
because “Element” is a term defined in the glossary. Further,
IROL is an identified limit, not a physical component. This
should be reworded to say “a facility that is identified to be
part of an interface or path impacting an IROL.” This is also
seen in R1 and R2 and needs to be adjusted there as well. The
industry has reviewed this language and has found it to be
sufficiently clear.
For newly acquired assets, the 12 month window may be
appropriate, but there needs to be a much nearer term
inspection undertaken to identify “risky” vegetation.
Definition
•
•
The modified definition assumes the ROW is maintained, which
may not be the case (for instance, if a newly acquired asset
has not yet been acted upon). An entity could interpret the
new definition to indicate that the new owner cannot be
performing an initial vegetation inspection if the ROW has not
yet been maintained. The phrase “maintained transmission
line” should be changed to “applicable transmission line.”
The inclusion of the phrase “which may be combined with a
general line inspection” is unnecessary and should be
removed. In fact, the current definition does not restrict
combining the inspection with other field visits, while in the
proposed definition that vegetation inspection can only be
combined with a general line inspection.
Objectives (Section 3)
• NERC staff is concerned that the purpose states “that could
lead to Cascading.” This qualifier limits the purpose of the
standard, which should be to prevent vegetation-related
outages. The more outages there are, the less the overall
system reliability; it does not necessarily have to lead to
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•
Cascading to be significant and represent a reasonable risk to
the BES.
The term “maintain” might be better than “improve.”
Applicability (Section 4)
• 4.1 Functional Entities
• Noticeably absent from the standard is coverage for
transmission facilities that connect generators to the
interconnected bulk power system. As such, the team should
add Generator Owners to the applicability and include such
language that was proposed by the ad hoc team: transmission
facilities that connect generators to the bulk power system that
exceed two spans from the fence-line of the generating plant;
coupled with the previous discussion, this provides complete
coverage for all transmission facilities and switchyards and
substations. This is what is needed to ensure no gaps in
vegetation management coverage.
• 4.2 Facilities
o The identification of critical facilities herein does not
recognize the overarching criteria that are being
developed in support of the PRC-023 order, and in some
respects, in response to Order 693 directives to define
the criteria for “critical facilities.” The FAC-003-2 SDT
should work in conjunction with the PRC-023 team,
which is establishing a set of criteria for identifying
critical facilities such that the outcome across all NERC
standards is consistent.
• “Transmission line” should be capitalized as a NERC-defined
term.
o
4.2.4: This exclusion seems strange. It would appear
that there are no expectations for vegetation
management in switchyards, which is unacceptable.
We should be able to develop language that requires
that a Transmission Owner or Generator Owner
maintain vegetation within fenced areas of the
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switchyard, station, or substation to the same
clearances as one does for the ROWs, without
necessarily obligating them to an annual cycle of
inspection or management.
o
Requirement R4
•
“Qualified personnel" should be defined. In the Rationale,
some examples are listed, but who else counts as “qualified
field personnel”? This was intended to be an incomplete partial
list.
• “At any moment” is an unnecessary qualifier and should be
removed (same for M4).
• With respect to the phrase “intentional time delay,” intent is a
tricky thing to prove. Most standards set clear timelines which
kick in regardless of intent, because it diminishes reliability to
base a standard on intent. The SDT should consider doing so
here.
Requirement R5
• NERC staff is confused by the overall purpose of this
requirement. It appears to be a defense to a possible violation
for failure to perform some planned vegetation work, but it
flips it around and makes it a requirement. A better approach
would be to just deal with this in addressing the
mitigating/aggravating factors under a violation of R1 and R2.
This concept is already part (R1.4) of the existing in-force
FERC-approved FAC-003-1, but has been renamed to avoid
conflict with terminology in the current NERC compliance
guidelines.
• The team should be more specific with respect to expectations
for “corrective action.” There needs to be an expectation that
the corrective action needs to maintain an equivalent level of
performance consistent with the intent of the vegetation
management program. This could include, for example re-
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•
rating lines to reduce max sag until the condition is rectified,
enhanced inspection cycles to monitor conditions, etc. It would
be useful to define a metric for the success of corrective
actions.
The team should be clearer on what constitutes a “constraint.”
Is it only legal constraints? One interpretation could be
resource constraints, which would certainly not be appropriate
in this context. The phrase “due to constraints” is also used in
the Rationale section. In this context, “constraint” appears to
mean congestion on a transmission line. This seems very
different from being “constrained from performing planned
vegetation work.” In fact, the existence of congestion on a line
does not necessarily create risk. We would not want entities to
make the economic determination that they will put off
required vegetation work because it would cost too much in
energy sales profits.
Requirement R6
• It would appear necessary to require the use of the inspection
information to guide or modify program development as is
identified in the Rationale box accompanying the requirement.
This is referred to in R7 but is not identified as an expectation
from R6.
• What are "all applicable transmission lines"? Are those lines
covered by both R1 and R2? Clarify this.
•
“Once per calendar year" requires more guidance. Would two
inspections on 12/31/2010 and 1/1/2011 satisfy this
requirement? Shouldn't there be a requirement to space these
inspections out? Recommend: once per calendar year with no
more than 15 months between inspections.
•
The last sentence of R6’s Rationale states that “Transmission
Owners should consider local and environmental factors that
could warrant more frequent inspection.” But the way the
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requirement is written, there is no basis for requiring anything
more frequent than once per calendar year. If the intent is to
have stricter timelines for different registered entities, then the
standard would need to be revised.
Compliance
• Additional Compliance Information
o Categories of Sustained Outages
Category 3 (Fall-ins from outside the ROW)
should be reinstated. Even if it is not required by
the standards, Category 3 reporting should be
kept. The SDT believes that the current NERC
TADS process captures such information
adequately.
There is currently a public bulletin to encourage
Transmission Owners to report Category 1 and 2
outages within 48 hours. The SDT should
consider adding this as a requirement and
including it in the new standard as such. The
SDT has considered your suggestion and
believes that the recognized requirement to
promptly self-report any potential violations is
sufficient.
VSLs
• The VSL for R3 should be shifted to an approach that simply
counts the missing elements: Thanks for your comments. The
SDT has modified the VSLs for R3.
o lower = missing one element
o moderate = missing two elements
o high= missing three elements
o severe = not having documents
• The VSL for R4 uses the phrase “vegetation threat,” which
needs to either be conformed to the text of the drafting team
or defined. This VSL also uses the phrase “intentional delay” A
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•
•
•
truly intentional delay should be labeled as severe, not just
high. (And as already stated, intent is a very tricky thing to
prove.) In the context of the requirement, Measure and VSL,
the term “vegetation threat” is self-evident. Refer to the SDT’s
earlier reply regariding “intentional delay”.
For the VSL for R5, there may be ways to differentiate
violations based on whether the entity identified appropriate
corrective actions (versus missing obvious alternatives),
attempted corrective actions but failed, considered alternative
corrective action, etc. The SDT has considered this but has not
identified a good means of differentiation. Additionally,
industry stakeholders have not offered any means of
differentiation. The SDT would welcome a proposal.
For the VSL for R6, the SDT should differentiate between the
criticality of different lines. At the very least, a failure to
inspect R1 lines should be a more severe violation than a
failure to inspect R2 lines. The risk to the system is properly
addressed by the VRFs, not by the VSLs.
The VSL for R7 should perhaps be differentiated based on
whether the incomplete work related to critical versus noncritical or less critical lines (i.e., R1 lines vs. R2 lines). The risk
to the system is properly addressed by the VRFs, not by the
VSLs.
Guidelines and Technical Basis
• R1/R2
o “If an investigation of a fault by a qualified person
confirms that a vegetation encroachment within the
MVCD occurred, then it shall be considered a Real-time
observation”: This is an important statement and
should be included as part of the requirement itself. The
SDT feels that this is really more of a “Measure” issue
than a “Requirement” issue, and is adequately captured
in M1.
• R3
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o
o
•
With respect to the phrase “an adequate transmission
vegetation management program,” the standard talks
about factors to consider, but the requirement does not
include any provisions on which to base a determination
of adequacy. NERC staff believes it should. With NERC’s
movement to the results-based standard-making
techniques, this is an outstanding issue that can best be
resolved once RBS techniques are firmly established.
The guideline states, “This approach provides the basis
for evaluating the intent, allocation of appropriate
resources and the competency of the Transmission
Owner in managing vegetation,” but nothing in the
requirements actually provide explicitly for such
evaluations. The SDT asserts that with the totality of
R3, M3 and associated VSLs, it is possible for the
auditor to assess the TO’s intent, competency, etc.
R4
o
o
o
“Cellular service or two-way radio disabled” should not
be considered an acceptable unintentional delay. This
seems to be within the entity’s control: there may be a
difference between whether the cell service problems
are due to network problems as opposed to the entity
failing to charge the phone or pay the bill. The SDT has
considered the comments, but believes the verbiage is
adequate.
“Remote field locations” should not be considered an
acceptable unintentional delay. This is not entirely
beyond the registered entity's control. There may be a
difference between a work site that is isolated from
radio or cellular networks versus the fact that the
employee simply left the radio in the truck. The SDT
has considered the comments, but believes the
verbiage is adequate.
“Vegetation-related conditions that warrant a response”
should be defined in the standard. Qualified personnel
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o
o
o
•
are ab;le to assess the conditions as called for in the
Requirement.
It is not clear to NERC staff that a lineman or an
arborist is capable of completing “an assessment of the
possible sag or movement of the conductor” out in the
field in real time. However, if this is the expectation, it
should be written into the requirements. The SDT
believes it is necessary to rely on field personnel for
routine decisions in the field, and that it is impractical
and unworkable for engineering or survey teams to
examine every questionable site. The SDT has
considered the comments, but believes the verbiage is
adequate.
The fourth paragraph states that the “Transmission
Owner has the responsibility to ensure the proper
communication…” Earlier in this section, however, it
says that the condition of the communication system is
not considered to be intentional delay. This
inconsistency needs to be addressed. This sentence
should also include a requirement for correcting the
vegetation encroachment. The SDT agrees with your
observation and will clarify the wording to indicate
communication “processes” between field personnel and
control centers are the issue being addressed.
The phrase “minutes or hours” is used in the final
sentence of the fourth paragraph of this sentence. This
detail should be written more clearly and written into
the standards. Is 24 hours still hours? What about 48
hours? The SDT has conceived of cases where a 10hour or more delay may be perfectly acceptable, but
others where a 10- or 20-minute delay is inexcusable.
The SDT believes that no rigid timeline is appropriate.
R6
o
With respect to the following sentence, beginning with
“Therefore it is expected,” NERC staff is concerned that
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nothing in the requirement actually makes this
expectation enforceable. It would be best to require
each TO that experiences a vegetation related sustained
outage to investigate the outage and make revisions to
its TVMP if the investigation shows that the growth
rates of vegetation under the TO’s control do not match
those anticipated in the TVMP. The primary definition of
“expected” is “looking forward to a probably
occurrence”, not a “required activity,” and so the SDT
believes that the verbiage is appropriate.
•
R7
o
o
The second paragraph states that “recent line
inspections may identify unanticipated high priority
work.” But the fifth bullet in R7 does not indicate that
the higher priority work was identified in a recent line
inspection. R7 should be revised to make that caveat
clear. The SDT suggests that it is unnecessary to state
that the TO will use all information available to it
(including inspection results) in identifying
unanticipated high-priority work.
The second paragraph references “Modifications to the
annual work plan.” Presumably, these modifications
would not excuse compliance with R1, R2, and R6. That
should be made clearer in the requirements. Thank you
for the comments.
Table 3
• None of the requirements actually reference this table. That
should be modified. Thank you. The Table will be removed.
•
Response:
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Effective Dates
The SDT assumes that NERC staff will correct implementation timetable conflicts.
Exceptions
The SDT considered such language, but ultimately determined that it was unnecessary, partly because the
response to “hot-spot”-type conditions is not part of this standard.
Definition
•
•
Thank you for your excellent comments. The SDT has made changes to meet this concern.
Previous overwhelming industry comments have dictated the need for the SDT to clarify this language
as it exists in the current draft. The current definition offers no restrictions that the vegetation restriction
may only be combined with a general line inspection.
Objectives (Section 3)
• The Purpose as currently stated reflects broad industry consensus that earlier Purpose statements were
over-reaching.
• The Purpose as currently stated reflects broad industry consensus.
Applicability (Section 4)
• Re: generators - There is a NERC GO/TO team established to address this issue.
• Re: critical facilities - While the SDT is aware of the interest in FERC to consolidate tests or criteria for
so-called “critical” facilities, NERC leadership have indicated to FERC staff its commitment to separate
efforts for use by PRC-023 and this standard.
• Re: capitalizing Transmission Line - The SDT agrees and thanks you for your comments.
• Re: 4.2.4 - Wide industry consensus is that line-based vegetation programs should not apply inside the
station boundary. Also, as previously mentioned, another NERC team is examining the TO/GO issue.
Requirement R4
• Re: qualified personnel - The SDT changed the language to confirmation by the Transmission
Operator.
• Re: “At any moment” - The SDT believes that “at any moment” is a necessary but sufficient qualifier.
• Re: “intentional time delay,” - The SDT has considered this. FERC has already approved other
standards with the same language.
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Requirement R5
• Re: corrective action - Past and recent industry comments indicate little confusion on this portion of
the Standard.
• Re: constraints - Past and recent industry comments indicate little confusion on this portion of the
Standard.
Requirement R6
• Re: inspection information - The SDT suggests that it is unnecessary to state that the TO will use all
information available to it (including inspection results) in developing its annual plan.
• Re: “all applicable transmission lines” - Please refer to section 4 (“Applicability”) of the draft.
• Re: calendar year - The SDT posed the question of inspection frequency to the overall industry in an
earlier posting and received general consensus that a one-year interval would be appropriate.
• Re: Rationale - The SDT does not intend that stricter timelines be rigidly defined or employed.
Compliance
• Re: Category 3 (Fall-ins from outside the ROW) - The SDT added this back in.
• Re: Public bulletin - The SDT has considered your suggestion and believes that the recognized
requirement to promptly self-report any potential violations is sufficient.
VSLs
•
•
•
•
•
Re: VSL for R3 - The SDT has modified the VSLs for R3.
Re: VSL for R4 - In the context of the requirement, Measure and VSL, the term “vegetation threat” is selfevident. Refer to the SDT’s earlier reply regarding “intentional delay”.
Re: VSL for R5 - The SDT has considered this but has not identified a good means of differentiation.
Additionally, industry stakeholders have not offered any means of differentiation. The SDT would
welcome a proposal.
Re: VSL for R6 - The risk to the system is properly addressed by the VRFs, not by the VSLs.
Re: VSL for R7 - The risk to the system is properly addressed by the VRFs, not by the VSLs.
Guidelines and Technical Basis
• Re: R1/R2 - The SDT feels that this is really more of a “Measure” issue than a “Requirement” issue, and
is adequately captured in M1.
• Re: R3 –
o With NERC’s movement to the results-based standard-making techniques, this is an outstanding
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Question 8 Comment
issue that can best be resolved once RBS techniques are firmly established.
The SDT asserts that with the totality of R3, M3 and associated VSLs, it is possible for the
auditor to assess the TO’s intent, competency, etc.
Re: R4 o Re: “Cellular service or two-way radio disabled” - The SDT has considered the comments, but
believes the verbiage is adequate.
o Re: “Remote field locations” - The SDT has considered the comments, but believes the verbiage
is adequate.
o Re: “Vegetation-related conditions that warrant a response” - Qualified personnel are able to
assess the conditions as called for in the Requirement.
o Re: “assessment of the possible sag or movement of the conductor” out in the field - The SDT
believes it is necessary to rely on field personnel for routine decisions in the field, and that it is
impractical and unworkable for engineering or survey teams to examine every questionable site.
The SDT has considered the comments, but believes the verbiage is adequate.
o Re: The fourth paragraph - The SDT agrees with your observation and will clarify the wording to
indicate communication “processes” between field personnel and control centers are the issue
being addressed.
o Re: The phrase “minutes or hours” - The SDT has conceived of cases where a 10-hour or more
delay may be perfectly acceptable, but others where a 10- or 20-minute delay is inexcusable. The
SDT believes that no rigid timeline is appropriate.
Re: R6 o Re: sentence beginning with “Therefore it is expected,” - The primary definition of “expected” is
“looking forward to a probable occurrence”, not a “required activity,” and so the SDT believes
that the verbiage is appropriate.
Re: R7 o Re: The second paragraph - The SDT suggests that it is unnecessary to state that the TO will use
all information available to it (including inspection results) in identifying unanticipated highpriority work.
o Re: The second paragraph references “Modifications to the annual work plan.” - Thank you for
the comments.
o
•
•
•
Table 3
• Thank you. Table 3 has been removed.
26
FirstEnergy
Yes
FE has the following additional comments:1. In the SDT consideration of
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Question 8 Comment
comments from Draft 3, it was indicated that "The subcommittee will ask that
NERC's legal department write a statement for addition to each standard to
clarify which parts/elements of the standard are mandatory and enforceable
and which are provided only as information". We would appreciate this
statement be placed into the standard before the final ballot so stakeholders
have an opportunity to review and comment on the wording.2. We cannot
comment on the Technical Reference Document since the latest draft was
not posted for review. Does NERC intend to post this at a later time? If so,
we ask that NERC give the industry enough time to adequately review the
document so that we can provide quality feedback.3. In the Guidelines and
Technical Basis Section, in the first paragraph of Requirement R5, second
sentence, the word "temporarily" should be removed since it was removed
from the requirement.
Response:
The SDT thanks you for your comments.
1) The NERC legal department has been contacted to provide a statement to clarify which parts/elements
of a standard are mandatory and enforceable and which are provided only as information. This
statement is nearing finalization and when completed will be posted as a separate document when the
next draft of FAC-003-2 is posted.
2) The Technical Reference Document is not a mandatory and enforceable document but your feedback is
definitely appreciated once the document is finalized. The Technical Reference will be updated during
the next ballot which will start during early August. The SDT will finalize the Technical Reference
document at the August meeting in Toronto, ON which is scheduled from 8/17-8/19/10 and will post for
comment.
The word ‘temporarily’ has been removed from the Guidelines and Technical Basis as requested. Thank you
for your comment.
27
Ameren
Yes
Funding Adjustments (increase or decrease) - need more description to imply
only when planned vegetation work is “over and above”.
Response: Thank you for your comment. The SDT believes your observation and question is the same as
voiced in Question 5. As stated in the SDT’s response to Ameren’s Question 5, we reviewed the Funding
Adjustment example for R7 and feels this is a valid reason for modifying the Annual Plan keeping in mind
that a modification must not place the transmission system at risk of vegetation encroachment into the
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Yes
Hydro One wants to thank the SDT for the effort that has gone into
developing this proposed revision to FAC-003. Overall the new version is
consistent with FERC Order 693 and will be a straightforward, workable, and
auditable standard. One item requiring clarification and change is the Active
ROW definition. The recent addition of a centerline distance to edge of
Active ROW is not acceptable. In many areas design standards allow a
smaller ROW width with no compromise to “cleared width” or tree related
reliability of the line. The SDT needs to address this issue. In R5, the phrase
'where a transmission line is put at potential risk due to the constraint' should
be better defined. This is vague and could lead to inconsistent practices
between utilities. All undesirable species on the full width of the ROW are
defined as 'potential risks to the transmission line' regardless of height or
location at the time of vegetation management. Interim corrective action
should only be required when the potential risk is approaching the imminent
threat classification.
MVCD.
28
Hydro One
Response: The SDT thanks you for your response. Your objection to our attempt to define a minimum width
of the Active Transmission Right of Way was very similar to many other commenters. The SDT has
subsequently revised the definition of ROW.
The issue you mention with R5 and “potential risk to the system” is understandable. The SDT changed this.
29
Idaho Power
Company
Yes
I would like to see something more from NERC to clear the way for utilities to
do vegetation management on federal lands that will allow timely vegetation
management without delays from these federal entities.
Response:
Thank you for your comments. This Standard places requirements on the Transmission Owners, not on
landowners. There is no legal mechanism for this Standard to take rights from property owners and assign
them to the Transmission Owner. There is joint UAA/EEI Task Force that is working on an MOU with the
Federal Agencies to address these issues which are outside the purview of NERC Reliability Standards.
30
Idaho Power
Yes
I'd like to see language or NERC support to encourage federal agencies to
expedite vegetation management maintenance requests and minimize the
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Question 8 Comment
barriers to perform work on federal lands.
Response:
Thank you for your comments. This Standard places requirements on the Transmission Owners, not on
landowners. There is no legal mechanism for this Standard to take rights from property owners and assign
them to the Transmission Owner. There is joint UAA/EEI Task Force that is working on an MOU with the
Federal Agencies to address these issues which are outside the purview of NERC Reliability Standards.
31
Dominion
Yes
In R4 and M4, the phrase "without any intentional time delay" has been
added. We recommend removing this language from the requirement as it is
not possible to measure intent.
Response:
Thank you for your comment. Please refer to the SDT response to NERC staff above regarding R4.
32
Consolidated Edison
Company of New
York Inc
Yes
In R5, the SDT should better define the phrase 'where a transmission line is
put at potential risk due to the constraint.' This is rather vague and could lead
to inconsistent practices between utilities. Con Edison defines all undesirable
species on the full width of the ROW as 'potential risks to the transmission
line' regardless of height or location at the time of vegetation management.
Interim corrective action should only be required when the potential risk is
approaching the imminent threat classification.
Response:
The SDT thanks you for your comments. As described in the Technical Reference document (See Page 30),
R5 is not intended to address situations where the transmission line is not at potential risk, meaning risk of a
Sustained Outage, and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on non-threatening, low
growth vegetation but agree to the use of mechanical clearing. In this case the Transmission Owner is not
under any immediate time constraint for achieving the management objective, can easily reschedule work
using an alternate approach, and therefore does not need to take interim corrective action. However, in
situations where transmission line reliability is potentially at risk due to a constraint, the Transmission
Owner is required to take an interim corrective action to mitigate the potential risk to the transmission line.
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33
Orange and Rockland
Utilities, Inc.
Yes or No
Question 8 Comment
Yes
In R5, the SDT should better define the phrase 'where a transmission line is
put at potential risk due to the constraint.' This is rather vague and could lead
to inconsistent practices between utilities. Orange and Rockland Utilities, Inc.
defines all undesirable species on the full width of the ROW as 'potential
risks to the transmission line' regardless of height or location at the time of
vegetation management. Interim corrective action should only be required
when the potential risk is approaching the imminent threat classification.
Response: The SDT thanks you for your comments. As described in the Technical Reference document (See
Page 30), R5 is not intended to address situations where the transmission line is not at potential risk,
meaning risk of a Sustained Outage, and the work event can be rescheduled or re-planned using an alternate
work methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the Transmission
Owner is not under any immediate time constraint for achieving the management objective, can easily
reschedule work using an alternate approach, and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint, the
Transmission Owner is required to take an interim corrective action to mitigate the potential risk to the
transmission line.
34
Entergy Services
Yes
ITEMS of concern listed below:ITEM 1: Page 13 of the Standard Draft 4
under Add'l Compliance Information - Periodic Data Submittal......Clarify if
Immediate Reporting is expected for outages in Outage Categories 1A, 1B,
2, or 4........or if Quarterly Reporting is all that is expected. It does not
specifically say that IMMEDIATE Reporting is Required for any outage type.
It is assumed that IMMEDIATE reporting is required for some outages, but is
unclear.ITEM 2: Agree that text boxes being used for additional clarity is a
benefit if used in a correct and clear manner, but it needs to be specifically
stated in the document that the text boxes are to be used for reference only,
we will not be required to specifically follow the language in the rationale, and
that and each utility should specify their own exact process for addressing
each Requirement.ITEM 3: Language should be added to the Guideline and
Technical Basis Section to clarify or re-state that this section that this section
is for assisting entities in understanding how to comply with the standard but
does not contain mandatory actions/activities.ITEM 4: Please clarify defining
factors that constitute "wind shear or fresh gale" as referenced in Section 4.4
Other. This is a very unclear interpretation and will most likely be interpreted
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differently by all involved if not specified.
Response: Thank you for your comments.
ITEM 1: There is no requirement in this Standard for immediate reporting of any vegetation outage to the TO’s
RE. The TO’s RE may require more frequent reporting or immediate reporting of any vegetation related outage.
There may be other standards that apply to any transmission line outage that require immediate notification to
the RE, NERC FERC, FBI, DOT and/or DOE. The SDT has considered your suggestion and believes that the
recognized requirement to promptly self-report any potential violations is sufficient.
ITEM 2: The Rationale boxes are intended to provide clarity and foundation behind each requirement. They are
not a part of the requirement and are not sanctionable, as such. You are correct that every TO is required to
structure its TVMP to comply with the standard as vegetation conditions exist. The NERC legal department has
been contacted to provide a statement to clarify which parts/elements of a standard are mandatory and
enforceable and which are provided only as information. This statement is nearing finalization and when
completed will be posted as a separate document when the next draft of FAC-003-2 is posted.
ITEM 3: The Guideline and Technical Reference paper Disclaimer on Page 6 of the document clearly states that
the supporting document is supplemental to the reliability standard FAC-003-2 – Transmission Vegetation
Management and does not contain mandatory requirements subject to compliance review.
ITEM 4: Wind Shear and Fresh Gale are defined terms by the National Oceanic Atmospheric Administration
(NOAA). Fresh gale is defined as straight line winds of between 39-46 mph. Wind Shear according to NOAA is a
complicated formula that no one will ever use. Wind Shear definition according to NOAA Glossary is “The rate
at which wind velocity changes from point to point in a given direction (as, vertically). The shear can be speed
shear (where speed changes between the two points, but not direction_, direction shear (where direction
changes between the two points, but not speed) or a combination of the two.
35
Northeast Power
Coordinating Council
Yes
NPCC wants to thank the SDT for the effort that has gone into developing
this proposed revision to FAC-003. Overall the new version is consistent
with FERC Order 693 and will be a straightforward, workable, and auditable
standard. One item requiring clarification and change is the Active ROW
definition. The recent addition of a centerline distance to edge of Active
ROW is not acceptable. In many areas design standards allow a smaller
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Question 8 Comment
ROW width with no compromise to “cleared width” or tree related reliability of
the line. The SDT needs to address this issue. In R5, the phrase 'where a
transmission line is put at potential risk due to the constraint' should be better
defined. This is vague and could lead to inconsistent practices between
utilities. All undesirable species on the full width of the ROW are defined as
'potential risks to the transmission line' regardless of height or location at the
time of vegetation management. Interim corrective action should only be
required when the potential risk is approaching the imminent threat
classification.
Response: The SDT thanks you for your response. Your objection to our attempt to define a minimum width
of the Active Transmission Right of Way was very similar to many other commenters. The SDT has revised
the definition of ROW.
The issue you mention with R5 and “potential risk to the system” is understandable. The SDT amended the
language.
36
Arizona Public
Service Company
Yes
Qualifications needs to be put back in the standard. There needs to be a
clearance 1 requirement.
Response: Thank you for your comments. Training and qualifications are best addressed in the NERC PER
standards. Additionally please refer to the SDT response to question 8, comment 42, regarding the issue of
Clearance 1.
37
Xcel Energy
Yes
R1 & R2 states that “types of encroachments include:” - is the way this is
worded intended to imply there can be other types of encroachments that are
not listed? If not, then rephrase the leading sentence to be definitive and
indicate that the types are the only categories to be considered. We suggest
that the wording from the prior draft, i.e., “ . . . limited to”.MCVD should be a
defined term in the glossary, not in a “Rationale” box.R1 “1” should Real-time
be capitalized to reflect the glossary definition? The term is used as “real
time”, “Real time” and “Real Time” throughout the standard. This seems to
be just a drafting issue, but the same term should be used consistently. Need
to establish somewhere that the entity defines what constitutes a “qualified”
person. Further, some portions of the standard use the term “qualified
person” (e.g., see M1) and others reference “qualified field personnel” (e.g.,
see the Rational Box near M3). It seems that all references should be to
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“qualified field personnel.”R1 & R2 are duplicative. It appears the only
reason for the separation is so that different VRFs can be assigned. Why not
just have 1 requirement and indicate that the VRF is High for one set of lines
and Med for others?In general, the “Rationale” boxes force the requirement
language into a difficult to read format.R5/M5 - the measures identified do
not constitute “corrective actions”, they merely identify documentation that
work was attempted. Corrective actions should be “actions”, such as
establish an increased monitoring plan, re-rating of the line, removal from
service, etc.R6 - Xcel Energy still believes the requirement in R6 that
mandates an annual inspection is too onerous and is at odds with the resultsbased approach of these revisions. Xcel Energy urges the retention of the
provision in the existing standard that allows the Transmission Owner to set
the frequency of inspection. In some areas of the country, annual
inspections may not be adequate. Yet in other areas, a longer inspection
frequency may be perfectly reasonable and practical. Our point is that
inspection frequency should not be treated as if it were “one size fits all”. If
treated this way, we feel this could pose a risk to reliability and is not likely to
be cost-effective. The Transmission Owner should be allowed some
flexibility. However, if the drafting team disagrees and determines that an
annual inspection is to be mandated, Xcel Energy believes that an exception
to the annual inspection is appropriate when a non-subjective advanced
technology such as LIDAR is utilized to achieve actual clearance distances.
This places the Transmission Owner in a situation where it can rationally
determine that the objectively measured distances result in a situation where
an inspection need not be performed within the next year. It is suggested
that R6 be revised to read as follows: Each Transmission Owner shall
perform a Vegetation Inspection of all applicable transmission lines at least
once per calendar year, unless the Transmission Owner, based on a nonsubjective advanced technology, such as LIDAR, determines that a longer
inspection period is appropriate.The Effective Dates section is confusing exactly when would this standard be in effect? It lists 3 approvals...do all
three have to be met or just one?The reference to Major WECC transfer
paths in the requirements introduces a weak element. The WECC major
path designation and elements that comprise those paths should be
controlled through a robust process and easily available to WECC members.
Currently, there are some concerns around that process in general.NERC’s
concerns regarding reporting vegetation related outages within 48 hours
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should be addressed or clarified in the Compliance section. (i.e., incorporate
or indicate that this supersedes that recommendation). Ref: Public Notice NERC Compliance Process #2008 - 001
Response: Thank you for your comments. The yellow highlighting refers to commenter issues. The SDT
response follows.
R1 & R2 states that “types of encroachments include:”: To address your concern, there are only (4) types of
failure- to- manage types of encroachment as defined in R1 and R2 as it relates to compliance with FAC-0032. The SDT appreciates your perspective but believes the requirement as written is clear to the point of only
four encroachment types.
MCVD should be a defined term in the glossary, not in a “Rationale”: This term refers to a Table of values
that is clearly defined within the standard itself.
The term is used as “real time”, “Real time” and “Real Time” throughout the standard. : Thanks for
identifying this inconsistency and the SDT will review and address as appropriate.
Need to establish somewhere that the entity defines what constitutes a “qualified” person.: This was
replaced with confirmed by the Transmission Owner.
Further, some portions of the standard use the term “qualified person” (e.g., see M1) and others reference
“qualified field personnel” (e.g., see the Rational Box near M3).: Thanks for recognizing this inconsistency.
The term “qualified” was replaced with confirmed by the Transmission Owner.
R1 & R2 are duplicative. It appears the only reason for the separation is so that different VRFs can be
assigned. Why not just have 1 requirement and indicate that the VRF is High for one set of lines and Med for
others?: The SDT is following the VSL and VRF Guidelines which required us to designate two requirements
since the VRFs are different for the applicable lines in the two requirements.
R5/M5 - the measures identified do not constitute “corrective actions”, they merely identify documentation
that work was attempted.: The measures in R5 are evidence that appropriate corrective action was taken by
the TO. Trying to identify very specific actions would be prescriptive in nature and difficult to cover a broad
spectrum of potential corrective actions.
R6 that mandates an annual inspection is too onerous and is at odds with the results-based approach of
these revisions: As stated in previous comment responses, the SDT was directed by Order 693 to set a
minimum inspection criteria and the SDT feels that an annual inspection is a reasonable minimum frequency.
Effective Dates section is confusing - exactly when would this standard be in effect? The SDT has revised
the effective date language for clarity. Please refer to change in revised draft.
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WECC major path designation and elements that comprise those paths should be controlled through a
robust process and easily available to WECC members. Currently, there are some concerns around that
process in general. : This is an issue that needs to be directed to WECC rather than the SDT.
48 hours should be addressed or clarified in the Compliance section. (i.e., incorporate or indicate that this
supersedes that recommendation). Ref: Public Notice - NERC Compliance Process #2008 – 001: This Public
Notice is a requirement for a Regional Entity to report to NERC.
38
BC Hydro
Yes
1. R4 - There will likely be issues of definition over what constitutes an
“intentional delay” in notification. The time for reasonable reporting
needs to be quantified.
2. The standard references Tables 2 and 3 but there is no Table 1 in the
document. This is confusing and should be renumbered. This is likely a
carry over from an earlier draft where a Table 1 has been renamed or
dropped.
3. As noted earlier in Q1, table 3 is poorly developed and should be
revisited.C
4. How does one objectively measure compliance to MVCD distances?
Use of LiDAR technology, laser rangefinders, etc. should be used and
evidence of potential violations should be empirical and not based solely
on subjective observations, even if they are performed by “qualified
personnel”.
5. The technical document should include a glossary of all the acronyms
used throughout the document as it has some excessive jargon and
does not always read smoothly, especially compared to FAC-003The use of explanation boxes is helpful.
Response:
1
2
3
The SDT debated a set time limit. The team could not find a time that would fit all situations. Intentional
would apply if a TO withheld notification after having confirmed that risk conditions exist.
The standard has been revised
The SDT thanks you for your comments. Based on your comment and others, the SDT has revised the
definition of ROW.
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5
6
39
Yes or No
Question 8 Comment
The determination of a potential violation should employ any technology available
SDT has defined unusual terms not found within the industry.
Thank you
The United
Illuminating Company
Yes
R4:In R4 the phrase: without any intentional time delay, is a concern. There
is a time line between identification and reporting of an imminent hazard that
represents the minimal time required to complete this Requirement. Any
situation where the time between observation and reporting is greater than
this minimal time line indicates a time delay occurred. It will be left to the
compliance enforcement authority to determine if this delay was intentional or
not. It is not proper for the test to be based on Intentional versus NonIntentional. Using other synonyms such as reasonable, expeditious, prompt,
immediate or without hesitation all introduce a qualitative not a quantitative
attribute to the measurement. The Supplemental Reference for R4 indicates
that the imminent threat requirement is measured in minutes or hours; again
no guidance for enforcement. R4 would be improved with an explicit time
requirement of 6 hours between observation and report. This is measurable
and clear.R4 should be: Each Transmission Owner shall notify the control
center holding switching authority for the associated transmission line no
more than 6 hours of a qualified personnel confirm the existence of a
vegetation condition that is likely to cause a Fault at any moment.Other
commenter’s will argue that 6 hours is arbitrary or unduly prescriptive. I
believe it is in line with the Supplemental Reference and adds clarity to the
enforcement process.M4 becomes Each Transmission Owner that has a
vegetation condition likely to cause a Fault at any moment, as confirmed by
qualified personnel, will have evidence that it notified the control center
holding switching authority for the associated transmission line within 6 hours
of observation.The Transmission Owner can use the inspection as evidence
of the time of observation.Effective Dates: The effective dates in the
implementation Plan is in a different form then UI was expecting. Effective
Date 1 UI has no comment.Effective date number 2 implies that if the BOT
approves the standard and FERC takes no action (neither approves,
remands or withholds approval of the standard) then the standard will
become effective in one year. This seems to create the possibility of an
effective standard without enforceability.Effective Date number 3 implies that
regardless of any action by FERC the standard will become effective at least
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Question 8 Comment
one year following BOT approval. Again this creates an effective standard
without enforceability. Also the use of “at least one year” does not add any
clarity to when the Standard would be effective any way.
Response:
Thank you for your comments. The SDT considered a fixed time as you offer. We rejected that alternative as
the situations under which conditions are found that can cause a Fault at any moment vary widely based on
the terrain, weather and available transportation and communication methods. This Requirement is directing
the TO to communicate the condition as soon as the above mentioned constraints will allow.
We have addressed your concerns by revising the effective date language.
40
FPL Corporate
Compliance
Yes
R5 as written is vague. It leads to confusion in interpretation. FPL
recommends the following wording.R5. The Transmission Owner shall certify
each corridor or line section that it meets the standards it set forth under R3
until the next planned management cycle when it is completed. If a location
in known to not meet the criteria defined under R3, a mitigation plan must be
in place to prevent a violation of R1 or R2.R1 and R2 are too inclusive. They
equate vegetation growing in to conductors from below the same as
vegetation falling or blowing into the conductors from within the Active ROW.
There is no evidence that a cascading event has ever been caused by the
latter two events. This standard should concentrate on vegetation growing
from below the conductor. Suggested wording of R1 and R2 is as follows.R1.
Each Transmission Owner shall manage vegetation to prevent encroachment
into the Minimum Vegetation Clearance Distance (MVCD) as shown in Table
2 from within the active ROW on of any line identified as an element of an
Interconnection Reliability Operating Limit (IROL) or Major Western Electricity
Coordinating Council (WECC) transfer path (operating within Rating and
Rated Electrical Operating Conditions). Encroachments are determined by:
1. An encroachment, observed in real time, 4. An encroachment due to a
grow-in from below the conductor in the active ROW that caused a Fault.R1.
Each Transmission Owner shall manage vegetation to prevent encroachment
into the Minimum Vegetation Clearance Distance (MVCD) as shown in Table
2 from within the active ROW on of any line that is not an element of an
Interconnection Reliability Operating Limit (IROL) or Major Western Electricity
Coordinating Council (WECC) transfer path (operating within Rating and
Rated Electrical Operating Conditions). Encroachments are determined by:
129
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
1. An encroachment, observed in real time, 4. An encroachment due to a
grow-in from below the conductor in the active ROW that caused a Fault.
Response: The STD recognizes that defining any risk is subjective. Removing the term does not change the
fact that each TO must determine the risk and respond accordingly.
The SDT has placed reference to the different severity of the respective violations into R1 and R2. Both
NERC and FERC are on record that fall-in and blow-in interruptions place sufficient risk to the system that
they should be part of the standard.
41
MWDSC
(METROPOLITAN
WATER DISTRICT
OF SOUTHERN
CALIFORNIA)
Yes
Requirement R4.uses the phrase "notify the control center holding switching
authority for the associated transmission line" when a vegetation condition is
confirmed which is likely to cause a Fault. Switching jurisdiction may be
assigned to a manned substation located closer to a line rather than a
remote 24/7 manned control center. However, the switching substation will
notify its control center. The control center may need to notify and coordinate
with its Balancing Authority or neighboring control centers. Suggest
changing the phrase as follows: "notify the appropriate control center(s)for
the associated transmission line"
Response: The SDT thanks you for your comments. The example you provided in your comment is in
compliance with the Requirement as written. The local procedure developed by a Transmission Owner may
involve multiple notification steps but, as long as the proper operating personnel holding switching authority
for that associated line is notified without any intentional delay, the Requirement is met. Due to multiple
variations in utility notification procedures across North America, the SDT has decided to retain the existing
language in the current draft.
42
Southern California
Edison Company
Yes
SCE questions the need for including the “Guidelines and Technical Basis”
section within the body of the standard and is also curious as to the criteria
used in developing new Table 3.SCE finds this Draft (4) to be the best work
product thus far, and commends the SDT for its efforts and continued
dedication to crafting a best-in-class standard.
Response: The SDT thanks you for your comment. The ‘Guidelines and Technical Basis” is part of the
format change with a “results based” standard. The idea is to bring some of the technical reference
documentation into the Standard. This will hopefully make the entire Standard a more complete document
and will reduce the need to have both the Standard and the Technical Reference Document in hand.
130
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
Table 3 was an attempt to define a “minimum width” of the Active Transmission Right of Way. This table,
along with the footnote, has been removed from the Standard. The definition of Right of Way has been
changed in the Glossary.
43
Bonneville Power
Administration
Yes
The basis of managing vegetation to MVCD in Table 2 (essentially withstand
distances) will likely prove problematic. BPA believes NERC should develop
an additional table that calls out minimum "buffers" based on attributes such
as line voltage, line rating etc. This table should be a companion to Table 2.
It is NERC's responsibility to regulate and we believe that they should do so.
In this case, the loss of flexibility for the owners is not necessarily a bad
thing.
Response: The SDT thanks you for your comments. As described in the Background Section of the
Standard, FAC-003-2 is being drafted utilizing a Results Based Standard approach. One component of this
type of Standard is that requirements within a standard are not too prescriptive allowing for flexibility. An
additional Table would be considered overly prescriptive and in direct conflict with our guidance. It is the
Transmission Owner’s responsibility to identify the ‘buffers’ that you mention, not NERC. Since conditions
vary significantly across North America, maintaining this specific buffer distance may not be feasible for all
utilities.
44
Southern Company
Transmission
Yes
The NERC Glossary of Terms provides a definition for Flashover. The
Rationale boxes for R1 and R2 use the term “spark-over”. This is
inconsistent with other references in the Standard. Note that the term
Flashover is used in footnote No.4. Please resolve the inconsistency
between these terms.We are concerned FAC-003-2 is being developed
under a zero tolerance philosophy, while other NERC standards do not adopt
a zero tolerance philosophy. Industry performance under FAC-003-1
indicates the standard is working and that industry is responding to ensure
reliability of the electric Transmission system.We would like to thank the SDT
for the work they have put into developing the proposed draft.
Response:
The SDT thanks you for your response. The technically correct term for the electric discharge through air is
“spark-over”. In the Technical Reference Document this term is used. The technical definition of “flashover” refers to the electric discharge over the surface of insulation when the “withstand” of the air is less
than the “withstand” of the insulation and the insulator “flashes over”.
131
Consideration of Comments on Draft 4 of FAC-003-2 — Project 2007-07
Organization
Yes or No
Question 8 Comment
However, the commonly used term in industry for both phenomena is “flash over”. The NERC Glossary
definition has actually rolled the technical definition of both terms together into one definition.
The SDT has decided to use the term “flash-over” in all sections of the Standard except for the derivation of
the Gallet equations in the appendix of the Technical Reference Document. Hopefully this will alleviate any
confusion.
The SDT recognizes that the current version of the Standard is zero tolerance and believes it is compelled to
write the new version it that way. FERC staff and NERC assert that a revised standard cannot result in less
reliability than the one it replaces, and, their belief is the current Standard is zero tolerance.
45
ITC Transmission
Yes
We were beginning to except Version 3 to the standard but with the addition
of “Table 3, Minimum Distance from the Centerline of the Circuit to the edge
of the active transmission line ROW” is totally unacceptable. This entire
reference should be stricken from the standard. ITC can not support this
table #3 and Version 4 is unacceptable.
Response: The SDT thanks you for your comments. Based on your comment and others, the SDT has revised
the definition of ROW in the NERC Glossary.
132
FAC-003-2 — Transmission Vegetation Management
S ta n d a rd De ve lo p m e n t Tim e lin e
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. SC approved SAR for initial posting (January 11, 2007).
2. SAR posted for comment (January 15–February 14, 2007).
3. SAR posted for comment (April 10–May 9, 2007).
4. SC authorized moving the SAR forward to standard development (June 27, 2007).
5. First draft of proposed standard posted (October 27, 2008-November 25, 2008)).
6. Second draft of revised standard posted (September 10, 20-October 24, 2009).
7. Third draft of revised standard posted (March 1, 2010-March 31, 2010).
8. Forth draft of revised standard posted (June 17, 2010-July 17, 2010).
Proposed Action Plan and Description of Current Draft
This is the third posting of the proposed revisions to the standard in accordance with ResultsBased Criteria and the fifth draft overall.
Future Development Plan
Anticipated Actions
Recirculation ballot of standards.
Anticipated Date
January 2011
Receive BOT approval
February 2011
Draft 5: January 27, 2011
1
FAC-003-2 — Transmission Vegetation Management
Effe c tive Da te s
First calendar day of the first calendar quarter one year after the date of the order approving
the standard from applicable regulatory authorities where such explicit approval is required.
Exceptions:
A line operated below 200kV, designated by the Planning Coordinator as an element of
an IROL or as a Major WECC transfer path, becomes subject to this standard 12
months after the date the Planning Coordinator or WECC initially designates the line as
being subject to this standard.
An existing transmission line operated at 200kV or higher that is newly acquired by an
asset owner and was not previously subject to this standard, becomes subject to this
standard 12 months after the acquisition date of the line.
Draft 5: January 27, 2011
2
FAC-003-2 — Transmission Vegetation Management
Ve rs io n His to ry
Version
1
Date
TBA
Action
1. Added “Standard Development
Roadmap.”
Change Tracking
01/20/06
2. Changed “60” to “Sixty” in section
A, 5.2.
3. Added “Proposed Effective Date:
April 7, 2006” to footer.
4. Added “Draft 3: November 17,
2005” to footer.
1
2
April 4, 2007
Draft 5: January 27, 2011
Regulatory Approval — Effective Date
New
3
FAC-003-2 — Transmission Vegetation Management
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary. When this standard has received ballot approval, the text
boxes will be moved to the Guideline and Technical Basis Section.
Right-of-Way (ROW)
The current glossary definition of this NERC
The corridor of land under a transmission line(s)
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in Paragraph 734 of FERC Order 693.
corridor is established by engineering or
construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in
effect when the line was built. The ROW width in no case exceeds the Transmission Owner’s
legal rights but may be less based on the aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the Transmission Owner’s control
that are likely to pose a hazard to the line(s) prior to
the next planned maintenance or inspection. This
may be combined with a general line inspection.
Draft 5: December 17, 2010
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
4
FAC-003-2 — Transmission Vegetation Management
In tro d u c tio n
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-2
3. Objectives:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1. Functional Entities:
Transmission Owners
4.2. Facilities: Defined below (referred to as “applicable lines”), including but not limited
to those that cross lands owned by federal 1, state, provincial, public, private, or tribal
entities:
4.2.1.
Overhead transmission lines operated at 200kV or higher.
4.2.2.
Overhead transmission lines operated below 200kV having been identified as
included in the definition of an Interconnection Reliability Operating Limit
(IROL) under NERC Standard FAC-014 by the Planning Coordinator.
4.2.3.
Overhead transmission lines
operated below 200 kV having
been identified as included in the
definition of one of the Major
WECC Transfer Paths in the Bulk
Electric System.
4.2.4.
This standard applies to overhead
transmission lines identified above
(4.2.1 through 4.2.3) located
outside the fenced area of the
switchyard, station or substation
and any portion of the span of the
transmission line that is crossing
the substation fence.
4.3. Enforcement: The reliability obligations of
the applicable entities and facilities are
1
Rationale
-The areas excluded in 4.2.4 were excluded based
on comments from industry for reasons summarized
as follows: 1) There is a very low risk from
vegetation in this area. Based on an informal
survey, no TOs reported such an event. 2)
Substations, switchyards, and stations have many
inspection and maintenance activities that are
necessary for reliability. Those existing process
manage the threat. As such, the formal steps in this
standard are not well suited for this environment. 3)
The standard was written for Transmission Owners.
Rolling the excluded areas into this standard will
bring GO and DP into the standard, even though
NERC has an initiative in place to address this
bigger registry issue. 4) Specifically addressing the
areas where the standard applies or doesn’t makes
the standard stronger as it relates to clarity.
EPAct 2005 section 1211c: “Access approvals by Federal agencies”.
Draft 5: December 17, 2010
5
FAC-003-2 — Transmission Vegetation Management
contained within the technical requirements of this standard. [Straw proposal]
5. Background:
This NERC Vegetation Management Standard (“Standard”) uses a defense-in-depth
approach to improve the reliability of the electric Transmission System by preventing those
vegetation related outages that could lead to Cascading. This Standard is not intended to
address non-preventable outages such as those due to vegetation fall-ins or blow-ins from
outside the Right-of-Way, vandalism, human activities and acts of nature. Operating
experience indicates that trees that have grown out of specification have contributed to
Cascading, especially under heavy electrical loading conditions.
With a defense-in-depth strategy, this Standard utilizes three types of requirements to provide
layers of protection to prevent vegetation related outages that could lead to Cascading:
a)
Performance-based — defines a particular reliability objective or outcome to be
achieved.
b)
Risk-based — preventive requirements to reduce the risks of failure to acceptable
tolerance levels.
c)
Competency-based — defines a minimum capability an entity needs to have to
demonstrate it is able to perform its designated reliability functions.
The defense-in-depth strategy for reliability standards development recognizes that each
requirement in a NERC reliability standard has a role in preventing system failures, and that
these roles are complementary and reinforcing. Reliability standards should not be viewed as
a body of unrelated requirements, but rather should be viewed as part of a portfolio of
requirements designed to achieve an overall defense-in-depth strategy and comport with the
quality objectives of a reliability standard. For this Standard, the requirements have been
developed as follows:
•
Performance-based: Requirements 1 and 2
•
Competency-based: Requirement 3
•
Risk-based: Requirements 4, 5, 6 and 7
Thus the various requirements associated with a successful vegetation program could be
viewed as using R1, R2 and R3 as first levels of defense; while R4 could be a subsequent or
final level of defense. R6 depending on the particular vegetation approach may be either an
initial defense barrier or a final defense barrier.
Major outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations.
Adherence to the Standard requirements for applicable lines on any kind of land or easement,
whether they are Federal Lands, state or provincial lands, public or private lands, franchises,
Draft 5: December 17, 2010
6
FAC-003-2 — Transmission Vegetation Management
easements or lands owned in fee, will reduce and manage this risk. For the purpose of the
Standard the term “public lands” includes municipal lands, village lands, city lands, and a
host of other governmental entities.
This Standard addresses vegetation management along applicable overhead lines and does
not apply to underground lines, submarine lines or to line sections inside an electric station
boundary.
This Standard focuses on transmission lines to prevent those vegetation related outages that
could lead to Cascading. It is not intended to prevent customer outages due to tree contact
with lower voltage distribution system lines. For example, localized customer service might
be disrupted if vegetation were to make contact with a 69kV transmission line supplying
power to a 12kV distribution station. However, this Standard is not written to address such
isolated situations which have little impact on the overall electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses an
increased outage risk, especially when numerous transmission lines are operating at or near
their Rating. This can present a significant risk of multiple line failures and Cascading.
Conversely, most other outage causes (such as trees falling into lines, lightning, animals,
motor vehicles, etc.) are statistically intermittent. These events are not any more likely to
occur during heavy system loads than any other time. There is no cause-effect relationship
which creates the probability of simultaneous occurrence of other such events. Therefore
these types of events are highly unlikely to cause large-scale grid failures. Thus, this
Standard’s emphasis is on vegetation grow-ins.
Draft 5: December 17, 2010
7
FAC-003-2 — Transmission Vegetation Management
Re q u ire m e n ts a n d Me a s u re s
R1. Each Transmission Owner shall manage
Rationale
vegetation to prevent encroachments of the
The MVCD is a calculated minimum
types shown below, into the Minimum
distance stated in feet (meters) to prevent
Vegetation Clearance Distance (MVCD) of
flash-over between conductors and
any of its applicable line(s) identified as an
vegetation, for various altitudes and
element of an Interconnection Reliability
operating voltages. The distances in Table 2
Operating Limit (IROL) in the planning
were derived using a proven transmission
horizon by the Planning Coordinator; or Major
design method. The types of failure to
Western Electricity Coordinating Council
manage vegetation are listed in order of
(WECC) transfer path(s); operating within its
increasing degrees of severity in nonRating and all Rated Electrical Operating
compliant performance as it relates to a
Conditions. 2
failure of a TO’s vegetation maintenance
1. An encroachment into the MVCD as
program since the encroachments listed
shown in FAC-003-Table 2, observed in
require different and increasing levels of
Real-time, absent a Sustained Outage,
skills and knowledge and thus constitute a
2. An encroachment due to a fall-in from
logical progression of how well, or poorly, a
inside the Right-of-Way (ROW) that
TO manages vegetation relative to this
caused a vegetation-related Sustained
Requirement.
Outage,
3. An encroachment due to blowing together
of applicable lines and vegetation located inside the ROW that caused a vegetationrelated Sustained Outage,
4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage.
[VRF – High] [Time Horizon – Real-time]
M1. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-time observations of any MVCD encroachments.
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation
encroachment within the MVCD has occurred from vegetation within the ROW, this
shall be considered the equivalent of a Real-time observation.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. (R1)
2
This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to
this reliability standard, including natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, wind
shear, fresh gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice
storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree,
arboricultural activities or horticultural or agricultural activities, or removal or digging of vegetation. Nothing in this
footnote should be construed to limit the Transmission Owner’s right to exercise its full legal rights on the ROW.
Draft 5: December 17, 2010
8
FAC-003-2 — Transmission Vegetation Management
R2. Each Transmission Owner shall manage
vegetation to prevent encroachments of the
types shown below, into the MVCD of any of
its applicable line(s) that is not an element of
an IROL; or Major WECC transfer path;
operating within its Rating and all Rated
Electrical Operating Conditions.2
1. An encroachment into the MVCD as
shown in FAC-003-Table 2, observed in
Real-time, absent a Sustained Outage,
2. An encroachment due to a fall-in from
inside the ROW that caused a vegetationrelated Sustained Outage,
3. An encroachment due to blowing together
of applicable lines and vegetation located
inside the ROW that caused a vegetationrelated Sustained Outage,
4. An encroachment due to a grow-in that
caused a vegetation-related Sustained
Outage.
[VRF – Medium] [Time Horizon – Real-time]
Rationale
The MVCD is a calculated minimum
distance stated in feet (meters) to prevent
flash-over between conductors and
vegetation, for various altitudes and
operating voltages. The distances in Table 2
were derived using a proven transmission
design method. The types of failure to
manage vegetation are listed in order of
increasing degrees of severity in noncompliant performance as it relates to a
failure of a TO’s vegetation maintenance
program since the encroachments listed
require different and increasing levels of
skills and knowledge and thus constitute a
logical progression of how well, or poorly,
a TO manages vegetation relative to this
Requirement.
M2. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R2. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-time observations of any MVCD encroachments.
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation
encroachment within the MVCD has occurred from vegetation within the ROW, this
shall be considered the equivalent of a Real-time observation.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. (R2)
Draft 5: December 17, 2010
9
FAC-003-2 — Transmission Vegetation Management
R3. Each Transmission Owner shall have
Rationale
documented maintenance strategies or
The documentation provides a basis for
procedures or processes or specifications it
evaluating the competency of the
uses to prevent the encroachment of
Transmission Owner’s vegetation program.
vegetation into the MVCD of its applicable
There may be many acceptable approaches
transmission lines that include(s) the
to maintain clearances. Any approach must
following:
demonstrate that the Transmission Owner
3.1 Accounts for the movement of
avoids vegetation-to-wire conflicts under all
applicable transmission line conductors
Rated Electrical Operating Conditions. See
under their Facility Rating and all Rated
Figure 1 for an illustration of possible
Electrical Operating Conditions;
conductor locations.
3.2 Accounts for the inter-relationships
between vegetation growth rates,
vegetation control methods, and inspection frequency.
[VRF – Lower] [Time Horizon – Long Term Planning]
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the Transmission Owner can prevent encroachment into the MVCD
considering the factors identified in the requirement. (R3)
R4. Each Transmission Owner, without any
intentional time delay, shall notify the
control center holding switching authority
for the associated applicable transmission
line when the Transmission Owner has
confirmed the existence of a vegetation
condition that is likely to cause a Fault at
any moment.
Rationale
To ensure expeditious communication between
the Transmission Owner and the control center
when a critical situation is confirmed.
[VRF – Medium] [Time Horizon – Real-time]
M4. Each Transmission Owner that has a confirmed vegetation condition likely to cause a
Fault at any moment will have evidence that it notified the control center holding
switching authority for the associated transmission line without any intentional time
delay. Examples of evidence may include control center logs, voice recordings,
switching orders, clearance orders and subsequent work orders. (R4)
Draft 5: December 17, 2010
10
FAC-003-2 — Transmission Vegetation Management
R5. When a Transmission Owner is constrained
from performing vegetation work, and the
constraint may lead to a vegetation
encroachment into the MVCD of its
applicable transmission lines prior to the
implementation of the next annual work plan
then the Transmission Owner shall take
corrective action to ensure continued
vegetation management to prevent
encroachments.
[VRF – Medium] [Time Horizon – Operations
Planning]
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
Transmission Owner from performing
planned vegetation maintenance work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the Transmission Owner to put interim
measures in place, rather than do nothing.
The corrective action process is intended to
address situations where a planned work
methodology cannot be performed but an
alternate work methodology can be used.
M5. Each Transmission Owner has evidence
of the corrective action taken for each constraint where an applicable transmission
line was put at potential risk. Examples of acceptable forms of evidence may include
initially-planned work orders, documentation of constraints from landowners, court
orders, inspection records of increased monitoring, documentation of the de-rating of
lines, revised work orders, invoices, and evidence that a line was de-energized. (R5)
R6. Each Transmission Owner shall perform a
Vegetation Inspection of 100% of its
applicable transmission lines (measured in
units of choice - circuit, pole line, line miles or
kilometers, etc.) at least once per calendar
year and with no more than 18 months
between inspections on the same ROW. 3
[VRF – Medium] [Time Horizon – Operations
Planning]
M6. Each Transmission Owner has evidence
that it conducted Vegetation Inspections
of the transmission line ROW for all
applicable transmission lines at least
once per calendar year but with no more
than 18 months between inspections on
the same ROW. Examples of acceptable
Rationale
Inspections are used by Transmission
Owners to assess the condition of the entire
ROW. The information from the assessment
can be used to determine risk, determine
future work and evaluate recentlycompleted work. This requirement sets a
minimum Vegetation Inspection frequency
of once per calendar year but with no more
than 18 months between inspections on the
same ROW. Based upon average growth
rates across North America and on common
utility practice, this minimum frequency is
reasonable. Transmission Owners should
consider local and environmental factors
that could warrant more frequent
inspections.
3
When the Transmission Owner is prevented from performing a Vegetation Inspection within the timeframe in R6
due to a natural disaster, the TO is granted a time extension that is equivalent to the duration of the time the TO was
prevented from performing the Vegetation Inspection.
Draft 5: December 17, 2010
11
FAC-003-2 — Transmission Vegetation Management
forms of evidence may include completed and dated work orders, dated invoices, or
dated inspection records. (R6)
R7. Each Transmission Owner shall complete
Rationale
100% of its annual vegetation work plan to
This requirement sets the expectation that
ensure no vegetation encroachments occur
the work identified in the annual work plan
within the MVCD. Modifications to the work
will be completed as planned. An annual
plan in response to changing conditions or to
vegetation work plan allows for work to be
findings from vegetation inspections may be
modified for changing conditions, taking
made (provided they do not put the
into consideration anticipated growth of
transmission system at risk of a vegetation
vegetation and all other environmental
encroachment) and must be documented. The
factors, provided that the changes do not
percent completed calculation is based on the
violate the encroachment within the MVCD.
number of units actually completed divided by
the number of units in the final amended plan
(measured in units of choice - circuit, pole line, line miles or kilometers, etc.) Examples of
reasons for modification to annual plan may include:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of a Transmission Owner 4
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
[VRF – Medium] [Time Horizon – Operations Planning]
M7. Each Transmission Owner has evidence that it completed its annual vegetation work
plan. Examples of acceptable forms of evidence may include a copy of the completed annual
work plan (including modifications if any), dated work orders, dated invoices, or dated
inspection records. (R7)
4
Circumstances that are beyond the control of a Transmission Owner include but are not limited to natural disasters
such as earthquakes, fires, tornados, hurricanes, landslides, major storms as defined either by the TO or an
applicable regulatory body, ice storms, and floods; arboricultural, horticultural or agricultural activities.
Draft 5: December 17, 2010
12
FAC-003-2 — Transmission Vegetation Management
Co m p lia n c e
Compliance Enforcement Authority
•
Regional Entity
Compliance Monitoring and Enforcement Processes:
•
•
•
•
•
•
•
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
Periodic Data Submittals
Evidence Retention
The Transmission Owner retains data or evidence to show compliance with Requirements
R1, R2, R3, R5, R6 and R7, Measures M1, M2, M3, M5, M6 and M7 for three calendar years
unless directed by its Compliance Enforcement Authority to retain specific evidence for a
longer period of time as part of an investigation.
The Transmission Owner retains data or evidence to show compliance with Requirement R4,
Measure M4 for most recent 12 months of operator logs or most recent 3 months of voice
recordings or transcripts of voice recordings, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an investigation.
If a Transmission Owner is found non-compliant, it shall keep information related to the noncompliance until found compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all requested
and submitted subsequent audit records.
Additional Compliance Information
Periodic Data Submittal: The Transmission Owner will submit a quarterly report to its
Regional Entity, or the Regional Entity’s designee, identifying all Sustained Outages of
applicable transmission lines determined by the Transmission Owner to have been caused by
vegetation, except as excluded in footnote 2, which includes as a minimum, the following:
o The name of the circuit(s), the date, time and duration of the outage; the voltage
of the circuit; a description of the cause of the outage; the category associated
with the Sustained Outage; other pertinent comments; and any countermeasures
taken by the Transmission Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation growing into
applicable transmission lines, that are identified as an element of an IROL or
Major WECC Transfer Path, by vegetation inside and/or outside of the ROW;
Draft 5: December 17, 2010
13
FAC-003-2 — Transmission Vegetation Management
o Category 1B — Grow-ins: Sustained Outages caused by vegetation growing into
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, by vegetation inside and/or outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines that are identified as an element of an IROL or
Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by vegetation and
applicable transmission lines that are identified as an element of an IROL or
Major WECC Transfer Path, blowing together from within the ROW.
o Category 4B — Blowing together: Sustained Outages caused by vegetation and
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, blowing together from within the ROW.
The Regional Entity will report the outage information provided by Transmission Owners, as
per the above, quarterly to NERC, as well as any actions taken by the Regional Entity as a
result of any of the reported Sustained Outages.
Draft 5: December 17, 2010
14
FAC-003-2 — Transmission Vegetation Management
Tim e Ho rizo n s , Vio la tio n Ris k Fa c to rs , a n d Vio la tio n S e ve rity Le ve ls
Table 1
R#
R1
R2
R3
Time
Horizon
Real-time
Real-time
Long-Term
Planning
VRF
Violation Severity Level
Lower
Moderate
High
Severe
The Transmission Owner had an
encroachment into the MVCD due to a
fall-in from inside the ROW that
caused a vegetation-related Sustained
Outage.
The Transmission Owner had
an encroachment into the
MVCD due to blowing
together of applicable lines
and vegetation located inside
the ROW that caused a
vegetation-related Sustained
Outage.
The Transmission Owner had an
encroachment into the MVCD
due to a grow-in that caused a
vegetation-related Sustained
Outage.
High
The
Transmission
Owner had an
encroachment
into the
MVCD
observed in
Real-time,
absent a
Sustained
Outage.
The Transmission Owner had an
encroachment into the MVCD due to a
fall-in from inside the ROW that
caused a vegetation-related Sustained
Outage.
The Transmission Owner had
an encroachment into the
MVCD due to blowing
together of applicable lines
and vegetation located inside
the ROW that caused a
vegetation-related Sustained
Outage.
The Transmission Owner had an
encroachment into the MVCD
due to a grow-in that caused a
vegetation-related Sustained
Outage.
Medium
The
Transmission
Owner had an
encroachment
into the
MVCD
observed in
Real-time,
absent a
Sustained
Outage.
The Transmission Owner has
maintenance strategies or documented
procedures or processes or
specifications but has not accounted for
the inter-relationships between
The Transmission Owner has
maintenance strategies or
documented procedures or
processes or specifications
but has not accounted for the
The Transmission Owner does
not have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent the
Lower
Draft 5: December 17, 2010
15
FAC-003-2 — Transmission Vegetation Management
vegetation growth rates, vegetation
control methods, and inspection
frequency, for the Transmission
Owner’s applicable lines.
R4
R5
R6
Real-time
Operations
Planning
Operations
Planning
Medium
movement of transmission
line conductors under their
Rating and all Rated
Electrical Operating
Conditions, for the
Transmission Owner’s
applicable lines.
encroachment of vegetation into
the MVCD, for the Transmission
Owner’s applicable lines.
The Transmission Owner
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
transmission line, but there
was intentional delay in that
notification.
The Transmission Owner
experienced a confirmed
vegetation threat and did not
notify the control center holding
switching authority for that
transmission line.
The Transmission Owner did not
take corrective action when it
was constrained from performing
planned vegetation work where a
transmission line was put at
potential risk.
Medium
Medium
The
Transmission
Owner failed
to inspect 5%
or less of its
applicable
transmission
lines
(measured in
units of
choice circuit, pole
line, line
miles or
Draft 5: December 17, 2010
The Transmission Owner failed to
inspect more than 5% up to and
including 10% of its applicable
transmission lines (measured in units
of choice - circuit, pole line, line miles
or kilometers, etc.).
The Transmission Owner
failed to inspect more than
10% up to and including 15%
of its applicable transmission
lines (measured in units of
choice - circuit, pole line, line
miles or kilometers, etc.).
16
The Transmission Owner failed
to inspect more than 15% of its
applicable transmission lines
(measured in units of choice circuit, pole line, line miles or
kilometers, etc.).
FAC-003-2 — Transmission Vegetation Management
kilometers,
etc.)
R7
Operations
Planning
Medium
The
Transmission
Owner failed
to complete
up to 5% of
its annual
vegetation
work plan
(including
modifications
if any).
Draft 5: December 17, 2010
The Transmission Owner failed to
complete more than 5% and up to 10%
of its annual vegetation work plan
(including modifications if any).
The Transmission Owner
failed to complete more than
10% and up to 15% of its
annual vegetation work plan
(including modifications if
any).
17
The Transmission Owner failed
to complete more than 15% of its
annual vegetation work plan
(including modifications if any).
FAC-003-2 — Transmission Vegetation Management
Va ria n c e s
None.
In te rp re ta tio n s
None.
Draft 5: December 17, 2010
18
FAC-003-2 — Transmission Vegetation Management
Guideline and Technical Basis
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the prevention of vegetation encroachments within a minimum distance of
transmission lines. Content-wise, R1 and R2 are the same requirements; however, they apply to
different Facilities. Both R1 and R2 require each Transmission Owner to manage vegetation to
prevent encroachment within the Minimum Vegetation Clearance Distance (“MVCD”) of
transmission lines. R1 is applicable to lines “identified as an element of an Interconnection
Reliability Operating Limit (IROL) or Major Western Electricity Coordinating Council (WECC)
transfer path (operating within Rating and Rated Electrical Operating Conditions) to avoid a
Sustained Outage”. R2 applies to all other applicable lines that are not an element of an IROL or
Major WECC Transfer Path.
The separation of applicability (between R1 and R2) recognizes that an encroachment into the
MVCD of an IROL or Major WECC Transfer Path transmission line is a greater risk to the
electric transmission system. Applicable lines that are not an element of an IROL or Major
WECC Transfer Path are required to be clear of vegetation but these lines are comparatively less
operationally significant. As a reflection of this difference in risk impact, the Violation Risk
Factors (VRFs) are assigned as High for R1 and Medium for R2.
These requirements (R1 and R2) state that if vegetation encroaches within the distances in Table
1 in Appendix 1 of this supplemental Transmission Vegetation Management Standard FAC-0032 Technical Reference document, it is in violation of the standard. Table 2 tabulates the distances
necessary to prevent spark-over based on the Gallet equations as described more fully in
Appendix 1 below.
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating
(potentially in violation of other standards), the occurrence of a clearance encroachment may
occur. For example, emergency actions taken by a Transmission Operator or Reliability
Coordinator to protect an Interconnection may cause the transmission line to sag more and come
closer to vegetation, potentially causing an outage. Such vegetation-related outages are not a
violation of these requirements.
Evidence of violation of Requirement R1 and R2 include real-time observation of a vegetation
encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related encroachment
resulting in a Sustained Outage due to a fall-in from inside the ROW, or a vegetation-related
encroachment resulting in a Sustained Outage due to blowing together of applicable lines and
vegetation located inside the ROW, or a vegetation-related encroachment resulting in a Sustained
Outage due to a grow-in. If an investigation of a Fault by a Transmission Owner confirms that a
vegetation encroachment within the MVCD occurred, then it shall be considered the equivalent
of a Real-time observation.
With this approach, the VSLs were defined such that they directly correlate to the severity of a
failure of a Transmission Owner to manage vegetation and to the corresponding performance
level of the Transmission Owner’s vegetation program’s ability to meet the goal of “preventing a
Sustained Outage that could lead to Cascading.” Thus violation severity increases with a
Transmission Owner’s inability to meet this goal and its potential of leading to a Cascading
Draft 5: December 17, 2010
19
FAC-003-2 — Transmission Vegetation Management
event. The additional benefits of such a combination are that it simplifies the standard and clearly
defines performance for compliance. A performance-based requirement of this nature will
promote high quality, cost effective vegetation management programs that will deliver the
overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For
example, a limb may only partially break and intermittently contact a conductor. Such events are
considered to be a single vegetation-related Sustained Outage under the Standard where the
Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will prevent transmission outages.
Requirement R3:
Requirement R3 is a competency based requirement concerned with the maintenance strategies,
procedures, processes, or specifications, a Transmission Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the
Transmission Owner uses to plan and perform vegetation work to prevent transmission Sustained
Outages and minimize risk to the Transmission System. The approach provides the basis for
evaluating the intent, allocation of appropriate resources and the competency of the Transmission
Owner in managing vegetation. There are many acceptable approaches to manage vegetation
and avoid Sustained Outages. However, the Transmission Owner must be able to state what its
approach is and how it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach a
Transmission Owner chooses to use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the Transmission Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing as a reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figure 1 below.
Draft 5: December 17, 2010
20
FAC-003-2 — Transmission Vegetation Management
Figure 1
Cross-section view of a single conductor at a given point along the span showing six possible
conductor positions due to movement resulting from thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the
Transmission Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4
involves the notification of potentially threatening vegetation conditions, without any intentional
delay, to the control center holding switching authority for that specific transmission line.
Examples of acceptable unintentional delays may include communication system problems (for
example, cellular service or two-way radio disabled), crews located in remote field locations
with no communication access, delays due to severe weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of a Transmission Owner’s employee who personally identifies such a threat in the
field. Confirmation could also be made by sending out an employee to evaluate a situation
reported by a landowner.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an assessment
of the possible sag or movement of the conductor while operating between no-load conditions
and its rating.
The Transmission Owner has the responsibility to ensure the proper communication between
field personnel and the control center to allow the control center to take the appropriate action
until the vegetation threat is relieved. Appropriate actions may include a temporary reduction in
the line loading, switching the line out of service, or positioning the system in recognition of the
increasing risk of outage on that circuit. The notification of the threat should be communicated in
terms of minutes or hours as opposed to a longer time frame for corrective action plans (see R5).
Draft 5: December 17, 2010
21
FAC-003-2 — Transmission Vegetation Management
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some Transmission Owners may have a danger tree identification
program that identifies trees for removal with the potential to fall near the line. These trees
would not require notification to the control center unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
Transmission Owner for the mitigation of Sustained Outage risk when temporarily constrained
from performing vegetation maintenance. The intent of this requirement is to deal with situations
that prevent the Transmission Owner from performing planned vegetation management work
and, as a result, have the potential to put the transmission line at risk. Constraints to performing
vegetation maintenance work as planned could result from legal injunctions filed by property
owners, the discovery of easement stipulations which limit the Transmission Owner’s rights, or
other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
Transmission Owner is not under any immediate time constraint for achieving the management
objective, can easily reschedule work using an alternate approach, and therefore does not need to
take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the Transmission Owner is required to take an interim corrective action to mitigate the potential
risk to the transmission line. A wide range of actions can be taken to address various situations.
General considerations include:
•
•
•
•
•
Identifying locations where the Transmission Owner is constrained from performing
planned vegetation maintenance work which potentially leaves the transmission line
at risk.
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for each location.
In developing the specific action to mitigate the potential risk to the transmission line
the Transmission Owner could consider location specific measures such as modifying
the inspection and/or maintenance intervals. Where a legal constraint would not allow
any vegetation work, the interim corrective action could include limiting the loading
on the transmission line.
The Transmission Owner should document and track the specific corrective action
taken at each location. This location may be indicated as one span, one tree or a
combination of spans on one property where the constraint is considered to be
temporary.
Draft 5: December 17, 2010
22
FAC-003-2 — Transmission Vegetation Management
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections that fits general industry practice. In addition, the fact that Vegetation
Inspections can be performed in conjunction with general line inspections further facilitates a
Transmission Owner’s ability to meet this requirement. However, the Transmission Owner may
determine that more frequent inspections are needed to maintain reliability levels, dependent
upon such factors as anticipated growth rates of the local vegetation, length of the growing
season for the geographical area, limited ROW width, and rainfall amounts. Therefore it is
expected that some transmission lines may be designated with a higher frequency of inspections.
The VSL for Requirement R6 has VSL categories ranked by the percentage of the required ROW
inspections completed. To calculate the percentage of inspection completion, the Transmission
Owner may choose units such as: line miles or kilometers, circuit miles or kilometers, pole line
miles, ROW miles, etc.
For example, when a Transmission Owner operates 2,000 miles of 230 kV transmission lines this
Transmission Owner will be responsible for inspecting all 2,000 miles of 230 kV transmission
lines at least once during the calendar year. If one of the included lines was 100 miles long, and
if it was not inspected during the year, then the amount failed to inspect would be 100/2000 =
0.05 or 5%. The “Low VSL” for R6 would apply in this example.
Requirement R7:
R7 is a risk-based requirement. The Transmission Owner is required to implement an annual
work plan for vegetation management to accomplish the purpose of this standard. Modifications
to the work plan in response to changing conditions or to findings from vegetation inspections
may be made and documented provided they do not put the transmission system at risk. The
annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a
“line-by-line” detailed description of all work to be performed. It is only intended to require that
the Transmission Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation into
the MVCD.
The ability to modify the work plan allows the Transmission Owner to change priorities or
treatment methodologies during the year as conditions or situations dictate. For example recent
line inspections may identify unanticipated high priority work, weather conditions (drought)
could make herbicide application ineffective during the plan year, or a major storm could require
redirecting local resources away from planned maintenance. This situation may also include
complying with mutual assistance agreements by moving resources off the Transmission
Owner’s system to work on another system. Any of these examples could result in acceptable
deferrals or additions to the annual work plan. Modifications to the annual work plan must
always ensure the reliability of the electric Transmission system.
In general, the vegetation management maintenance approach should use the full extent of the
Transmission Owner’s easement, fee simple and other legal rights allowed. A comprehensive
approach that exercises the full extent of legal rights on the ROW is superior to incremental
Draft 5: December 17, 2010
23
FAC-003-2 — Transmission Vegetation Management
management in the long term because it reduces the overall potential for encroachments, and it
ensures that future planned work and future planned inspection cycles are sufficient.
When developing the annual work plan the Transmission Owner should allow time for
procedural requirements to obtain permits to work on federal, state, provincial, public, tribal
lands. In some cases the lead time for obtaining permits may necessitate preparing work plans
more than a year prior to work start dates. Transmission Owners may also need to consider those
special landowner requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the Transmission
Owner, evidence of successful annual work plan execution could consist of signed-off work
orders, signed contracts, printouts from work management systems, spreadsheets of planned
versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence
may include photographs, and walk-through reports.
Draft 5: December 17, 2010
24
FAC-003-2 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD)
5
For Alternating Current Voltages
( AC )
Nominal
System
Voltage
(kV)
( AC )
Maximum
System
Voltage
(kV)
765
800
500
550
345
362
230
242
161*
169
138*
145
115*
121
88*
100
69*
72
MVCD
feet
(meters)
sea level
8.06ft
(2.46m)
5.06ft
(1.54m)
3.12ft
(0.95m)
2.97ft
(0.91m)
2ft
(0.61m)
1.7ft
(0.52m)
1.41ft
(0.43m)
1.15ft
(0.35m)
0.82ft
(0.25m)
MVCD
feet
(meters)
3,000ft
(914.4m)
MVCD
feet
(meters)
4,000ft
(1219.2m)
MVCD
feet
(meters)
5,000ft
(1524m)
MVCD
feet
(meters)
6,000ft
(1828.8m)
8.89ft
(2.71m)
5.66ft
(1.73m)
3.53ft
(1.08m)
3.36ft
(1.02m)
2.28ft
(0.69m)
1.94ft
(0.59m)
1.61ft
(0.49m)
1.32ft
(0.40m)
0.94ft
(0.29m)
9.17ft
(2.80m)
5.86ft
(1.79m)
3.67ft
(1.12m)
3.49ft
(1.06m)
2.38ft
(0.73m)
2.03ft
(0.62m)
1.68ft
(0.51m)
1.38ft
(0.42m)
0.99ft
(0.30m)
9.45ft
(2.88m)
6.07ft
(1.85m)
3.82ft
(1.16m)
3.63ft
(1.11m)
2.48ft
(0.76m)
2.12ft
(0.65m)
1.75ft
(0.53m)
1.44ft
(0.44m)
1.03ft
(0.31m)
9.73ft
(2.97m)
6.28ft
(1.91m)
3.97ft
(1.21m)
3.78ft
(1.15m)
2.58ft
(0.79m)
2.21ft
(0.67m)
1.83ft
(0.56m)
1.5ft
(0.46m)
1.08ft
(0.33m)
MVCD
feet
(meters)
7,000ft
(2133.6m)
MVCD
feet
(meters)
8,000ft
(2438.4m)
MVCD
feet
(meters)
9,000ft
(2743.2m)
MVCD
feet
(meters)
10,000ft
(3048m)
MVCD
feet
(meters)
11,000ft
(3352.8m)
10.01ft
(3.05m)
6.49ft
(1.98m)
4.12ft
(1.26m)
3.92ft
(1.19m)
2.69ft
(0.82m)
2.3ft
(0.70m)
1.91ft
(0.58m)
1.57ft
(0.48m)
1.13ft
(0.34m)
10.29ft
(3.14m)
6.7ft
(2.04m)
4.27ft
(1.30m)
4.07ft
(1.24m)
2.8ft
(0.85m)
2.4ft
(0.73m)
1.99ft
(0.61m)
1.64ft
(0.50m)
1.18ft
(0.36m)
10.57ft
(3.22m)
6.92ft
(2.11m)
4.43ft
(1.35m)
4.22ft
(1.29m)
2.91ft
(0.89m)
2.49ft
(0.76m)
2.07ft
(0.63m)
1.71ft
(0.52m)
1.23ft
(0.37m)
10.85ft
(3.31m)
7.13ft
(2.17m)
4.58ft
(1.40m)
4.37ft
(1.33m)
3.03ft
(0.92m)
2.59ft
(0.79m)
2.16ft
(0.66m)
1.78ft
(0.54m)
1.28ft
(0.39m)
11.13ft
(3.39m)
7.35ft
(2.24m)
4.74ft
(1.44m)
4.53ft
(1.38m)
3.14ft
(0.96m)
2.7ft
(0.82m)
2.25ft
(0.69m)
1.86ft
(0.57m)
1.34ft
(0.41m)
* Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above).
5
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially
greater distances will be achieved at time of vegetation maintenance.
Draft 5: December 17, 2010
25
FAC-003-2 — Transmission Vegetation Management
Table 2 (cont.) — Minimum Vegetation Clearance Distances (MVCD)
For Direct Current Voltages
sea level
MVCD feet
(meters)
3,000ft
(914.4m)
Alt.
MVCD feet
(meters)
4,000ft
(1219.2m)
Alt.
MVCD feet
(meters)
5,000ft
(1524m)
Alt.
MVCD feet
(meters)
6,000ft
(1828.8m)
Alt.
MVCD
feet
(meters)
7,000ft
(2133.6m)
Alt.
MVCD
feet
(meters)
(8,000ft
(2438.4m)
Alt.
MVCD
feet
(meters)
9,000ft
(2743.2m)
Alt.
MVCD
feet
(meters)
10,000ft
(3048m)
Alt.
MVCD
feet
(meters)
11,000ft
(3352.8m)
Alt.
±750
13.92ft
(4.24m)
15.07ft
(4.59m)
15.45ft
(4.71m)
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.9ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
±600
10.07ft
(3.07m)
11.04ft
(3.36m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
(13.54ft
4.13m)
±500
7.89ft
(2.40m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
±400
4.78ft
(1.46m)
5.35ft
(1.63m)
5.55ft
(1.69m)
5.75ft
(1.75m)
5.95ft
(1.81m)
6.15ft
(1.87m)
6.36ft
(1.94m)
6.57ft
(2.00m)
6.77ft
(2.06m)
6.98ft
(2.13m)
±250
3.43ft
(1.05m)
4.02ft
(1.23m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5ft
(1.52m)
5.17ft
(1.58m)
( DC )
Nominal Pole
to Ground
Voltage
(kV)
MVCD feet
(meters)
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a misapplication. The SDT consulted specialists
who advised that the Gallet Equation would be a technically justified method. The explanation of why the Gallet approach is more
appropriate is explained in the paragraphs below.
The drafting team sought a method of establishing minimum clearance distances that uses realistic weather conditions and realistic
maximum transient over-voltages factors for in-service transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to conductor distances in FAC-003-1:
Draft 5: December 17, 2010
26
FAC-003-2 — Transmission Vegetation Management
•
•
•
avoid the problem associated with referring to tables in another standard (IEEE-516-2003)
transmission lines operate in non-laboratory environments (wet conditions)
transient over-voltage factors are lower for in-service transmission lines than for inadvertently re-energized transmission lines
with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in IEEE 516-2003 to determine the
minimum distance between a transmission line conductor and vegetation. The equations and methods provided in IEEE 516 were
developed by an IEEE Task Force in 1968 from test data provided by thirteen independent laboratories. The distances provided in
IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap, or in other words, dry laboratory conditions.
Consequently, the validity of using these distances in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the minimum clearance distances. Table 5
could be used if the Transmission Owner knew the maximum transient over-voltage factor for its system. Otherwise, Table 7 would
have to be used. Table 7 represented minimum air insulation distances under the worst possible case for transient over-voltage factors.
These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV
phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for concern in this
particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is inadvertently re-energized immediately after the
line is de-energized and a trapped charge is still present. The intent of FAC-003 is to keep a transmission line that is in service from
becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst case
transient overvoltage assumptions are not appropriate for this application. Rather, the appropriate over voltage values are those that
occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are
negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 per unit. This value is a conservative estimate of the transient overvoltage that is created at the point of application (e.g. a substation) by switching a capacitor bank without pre-insertion devices (e.g.
closing resistors). At voltage levels where capacitor banks are not very common (e.g. 362 kV), the maximum transient over-voltage of
an in-service ac line are created by fault initiation on adjacent ac lines and shunt reactor bank switching. These transient voltages are
usually 1.5 per unit or less.
Draft 5: December 17, 2010
27
FAC-003-2 — Transmission Vegetation Management
Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order
to be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient
over-voltage factor of 2.0 per unit for transmission lines operated at 242 kV and below is considered to be a realistic maximum in this
application. Likewise, for ac transmission lines operated at 362 kV and above a transient over-voltage factor of 1.4 per unit is
considered a realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These equations are used for computing the
required strike distances for proper transmission line insulation coordination. They were developed for both wet and dry applications
and can be used with any value of transient over-voltage factor. The Gallet Equation also can take into account various air gap
geometries. This approach was used to design the first 500 kV and 765 kV lines in North America [1].
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical spark-over distances
computed using the Gallet wet equations, for each of the nominal voltage classes and identical transient over-voltage factors, the
Gallet equations yield a more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are not vastly different when the same
transient overvoltage factors are used; the “wet” equations will consistently produce slightly larger distances than the IEEE 516
equations when the same transient overvoltage is used. While the IEEE 516 equations were only developed for dry conditions the
Gallet equations have provisions to calculate spark-over distances for both wet and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live vegetation, there are no spark-over formulas
currently derived expressly for vegetation to conductor minimum distances. Therefore the SDT chose a proven method that has been
used in other EHV applications. The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage
Factor that is consistent with the absence of trapped charges on an in-service transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the Gallet equations using various
transient overvoltage values.
Draft 5: December 17, 2010
28
FAC-003-2 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations
vs.
IEEE 516-2003 MAID distances
using various transient over-voltage factors
Table 5
( AC )
Nom System
Voltage (kV)
( AC )
Max System
Voltage (kV)
Transient
Over-voltage
Factor (T)
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
765
500
345
230
115
800
550
362
242
121
1.4
1.4
1.4
2.0
2.0
8.89
5.65
3.52
3.35
1.6
IEEE 516
MAID (ft)
@ Alt. 3000 feet
8.65
4.92
3.13
2.8
1.4
Table 5
(historical maximums)
( AC )
Nom System
Voltage (kV)
( AC )
Max System
Voltage (kV)
Transient
Over-voltage
Factor (T)
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
765
500
345
230
115
800
550
362
242
121
2.0
2.4
3.0
3.0
3.0
14.36
11.0
8.55
5.28
2.46
Draft 5: December 17, 2010
IEEE 516
MAID (ft)
@ Alt. 3000 feet
13.95
10.07
7.47
4.2
2.1
29
FAC-003-2 — Transmission Vegetation Management
Table 7
( AC )
Nom System
Voltage (kV)
( AC )
Max System
Voltage (kV)
Transient
Over-voltage
Factor (T)
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
765
500
345
230
115
800
550
362
242
121
2.5
3.0
3.5
3.5
3.5
20.25
15.02
10.42
6.32
2.90
Draft 5: December 17, 2010
IEEE 516
MAID (ft)
@ Alt. 3000 feet
20.4
14.7
9.44
5.14
2.45
30
FAC-003-2 — Transmission Vegetation Management
S ta n d a rd De ve lo p m e n t Tim e lin e
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. SC approved SAR for initial posting (January 11, 2007).
2. SAR posted for comment (January 15–February 14, 2007).
3. SAR posted for comment (April 10–May 9, 2007).
4. SC authorized moving the SAR forward to standard development (June 27, 2007).
5. First draft of proposed standard posted (October 27, 2008-November 25, 2008)).
6. Second draft of revised standard posted (September 10, 20-October 24, 2009).
7. Third draft of revised standard posted (March 1, 2010-March 31, 2010).
8. Forth draft of revised standard posted (June 17, 2010-July 17, 2010).
Proposed Action Plan and Description of Current Draft
This is the secondthird posting of the proposed revisions to the standard in accordance with
Results-Based Criteria and the fifth draft overall.
Future Development Plan
Anticipated Actions
Drafting team considers comments, makes conforming changes, and
requests SC approval to proceed to formal comment and ballot.
Anticipated Date
June –July 2010
Recirculation ballot of standards.
July-August
2010January 2011
August
2010February 2011
Receive BOT approval
Draft 4: June 16, 20105: January 27, 2011
1
FAC-003-2 — Transmission Vegetation Management
Effe c tive Da te s
1. First calendar day of the first calendar quarter one year after the date of the order
approving the standard from applicable regulatory authorityauthorities where such
explicit approval for all requirements
2. First calendar day of the first calendar quarter one year following Board of Trustees
adoption unless governmental authority withholds approval
First calendar day of the first calendar quarter that is at least one year following Board of
Trustees adoptionrequired.
Exceptions:
A line operated below 200kV, designated by the Planning Coordinator as an element of
an IROL or as a Major WECC transfer path, becomes subject to this standard 12
months after the date the Planning Coordinator or WECC initially designates the
linesline as being subject to this standard.
An existing transmission line operated at 200kV or higher that is newly acquired by an
asset owner and was not previously subject to this standard, becomes subject to this
standard 12 months after the acquisition date of the line.
Draft 4: June 16, 20105: January 27, 2011
2
FAC-003-2 — Transmission Vegetation Management
Ve rs io n His to ry
Version
1
Date
TBA
Action
1. Added “Standard Development
Roadmap.”
Change Tracking
01/20/06
2. Changed “60” to “Sixty” in section
A, 5.2.
3. Added “Proposed Effective Date:
April 7, 2006” to footer.
4. Added “Draft 3: November 17,
2005” to footer.
1
2
April 4, 2007
Draft 4: June 16, 2010
Regulatory Approval — Effective Date
New
3
FAC-003-2 — Transmission Vegetation Management
De fin itio n s o f Te rm s Us e d in S ta n d a rd
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary. When this standard has received ballot approval, the text
boxes will be moved to the Guideline and Technical Basis Section.
The current glossary definition of this NERC term is
Right-of-Way (ROW)
modified
to allow
both maintenance
and
The current
glossary
definitioninspections
of this NERC
The corridor of land under a transmission line(s)
vegetation inspections to be performed concurrently.
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in
Paragraph
734
FERC Order
693.The
Current
definition
of of
Vegetation
Inspection:
corridor is established by engineering or
systematic
examination
of
a
transmission
corridor to
construction standards as documented in either
document vegetation conditions.
construction documents, pre-2007 vegetation
maintenance records, or by the blowout standard in
effect when the line was built. The ROW width in
no case exceeds the Transmission Owner’s legal rights but may be less based on the
aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a maintained transmission line Rightof-Way whichRight-of-Way and those vegetation
conditions under the Transmission Owner’s control
that are likely to pose a hazard to the line(s) prior to
the next planned maintenance or inspection. This
may be combined with a general line inspection.
Draft 4: June 165: December 17, 2010
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
4
FAC-003-2 — Transmission Vegetation Management
In tro d u c tio n
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-2
3. Objectives:
To improve the reliability of the maintain a reliable electric transmission
system by using a defense-in-depth strategy to manage vegetation located
on transmission rights of way (ROW) and minimize encroachments from
vegetation located adjacent to the ROW, thus preventing the risk of those
vegetation-related outages that could lead to Cascading.
4. Applicability
4.1. Functional Entities:
Transmission Owners
4.2. Facilities: Defined below, (referred to as “applicable lines”), including but not limited
to those that cross lands owned by federal 1, state, provincial, public, private, or tribal
entities:
4.2.1.
Overhead transmission lines operated at 200kV or higher.
4.2.2.
Overhead transmission lines operated below 200kV having been identified as
included in the definition of an Interconnection Reliability Operating Limit
(IROL) under NERC Standard FAC-014 by the Planning Coordinator.
4.2.3.
Overhead transmission lines
operated below 200 kV having
been identified as included in the
definition of one of the Major
WECC Transfer Paths in the Bulk
Electric System.
4.2.4.
This standard does not
applyapplies to Facilitiesoverhead
transmission lines identified above
(4.2.1 through 4.2.3) located
inoutside the fenced area of athe
switchyard, station or substation
and any portion of the span of the
transmission line that is crossing
the substation fence.
4.3. Enforcement: The reliability obligations of
1
Rationale
-The areas excluded in 4.2.4 were excluded based
on comments from industry for reasons summarized
as follows: 1) There is a very low risk from
vegetation in this area. Based on an informal
survey, no TOs reported such an event. 2)
Substations, switchyards, and stations have many
inspection and maintenance activities that are
necessary for reliability. Those existing process
manage the threat. As such, the formal steps in this
standard are not well suited for this environment. 3)
The standard was written for Transmission Owners.
Rolling the excluded areas into this standard will
bring GO and DP into the standard, even though
NERC has an initiative in place to address this
bigger registry issue. 4) Specifically addressing the
areas where the standard applies or doesn’t makes
the standard stronger as it relates to clarity.
EPAct 2005 section 1211c: “Access approvals by Federal agencies”.
Draft 4: June 165: December 17, 2010
5
FAC-003-2 — Transmission Vegetation Management
the applicable entities and facilities are contained within the technical requirements of
this standard. [Straw proposal]
4.4. Other:
This Standard does not apply to any occurrence, non-occurrence, or other set of
circumstances that are beyond the control of a Transmission Owner subject to this
reliability standard, including acts of God, flood, drought, earthquake, major storms,
fire, hurricane, tornado, landslides, ice storms, vehicle contact with tree, human activity
involving: removal of, installation of, or digging around vegetation, animals severing
trees, lightning, epidemic, strike, war, riot, civil disturbance, sabotage, vandalism,
terrorism, wind shear, or fresh gale (or higher wind speed) that restricts or prevents
performance to comply with this reliability standard’s requirements. Nothing in this
section should be construed to limit the Transmission Owner’s right to exercise its full
legal rights on the active transmission line ROW2.
5. Background:
This NERC Vegetation Management Standard (“Standard”) uses a defense-in-depth
approach to improve the reliability of the electric Transmission System by preventing those
vegetation related outages that could lead to Cascading. This Standard is not intended to
address non-preventable outages such as those due to vegetation fall-ins or blow-ins from
outside the Active Transmission Line Right-of-Way, vandalism, human activities and acts of
nature. Operating experience indicates that trees that have grown out of specification have
contributed to Cascading, especially under heavy electrical loading conditions.
With a defense-in-depth strategy, this Standard utilizes three types of requirements to provide
layers of protection to prevent vegetation related outages that could lead to Cascading:
a)
Performance-based — defines a particular reliability objective or outcome to be
achieved.
b)
Risk-based — preventive requirements to reduce the risks of failure to acceptable
tolerance levels.
c)
Competency-based — defines a minimum capability an entity needs to have to
demonstrate it is able to perform its designated reliability functions.
The defense-in-depth strategy for reliability standards development recognizes that each
requirement in a NERC reliability standard has a role in preventing system failures, and that
these roles are complementary and reinforcing. Reliability standards should not be viewed as
a body of unrelated requirements, but rather should be viewed as part of a portfolio of
requirements designed to achieve an overall defense-in-depth strategy and comport with the
quality objectives of a reliability standard. For this Standard, the requirements have been
developed as follows:
2
A strip or corridor of land that is occupied by active transmission facilities. This corridor does not include the parts
of the Right-of-Way that are unused or intended for other facilities. However, it is not to be less than the width of
the easement itself unless the easement exceeds distances as shown in Table 3 for various voltage classes.
Draft 4: June 165: December 17, 2010
6
FAC-003-2 — Transmission Vegetation Management
•
Performance-based: Requirements 1 and 2
•
Competency-based: Requirement 3
•
Risk-based: Requirements 4, 5, 6 and 7
Thus the various requirements associated with a successful vegetation program could be
viewed as using R1, R2 and R3 as first levels of defense; while R4 could be a subsequent or
final level of defense. R6 depending on the particular vegetation approach may be either an
initial defense barrier or a final defense barrier.
Major outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations.
Adherence to the Standard requirements for applicable lines on any kind of land or easement,
whether they are Federal Lands, state or provincial lands, public or private lands, franchises,
easements or lands owned in fee, will reduce and manage this risk. For the purpose of the
Standard the term “public lands” includes municipal lands, village lands, city lands, and a
host of other governmental entities.
This Standard addresses vegetation management along applicable overhead lines and does
not apply to underground lines, submarine lines or to line sections inside an electric station
boundary.
This Standard focuses on transmission lines to prevent those vegetation related outages that
could lead to Cascading. It is not intended to prevent customer outages due to tree contact
with lower voltage distribution system lines. For example, localized customer service might
be disrupted if vegetation were to make contact with a 69kV transmission line supplying
power to a 12kV distribution station. However, this Standard is not written to address such
isolated situations which have little impact on the overall electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses an
increased outage risk, especially when numerous transmission lines are operating at or near
their Rating. This can present a significant risk of multiple line failures and Cascading.
Conversely, most other outage causes (such as trees falling into lines, lightning, animals,
motor vehicles, etc.) are statistically intermittent. These events are not any more likely to
occur during heavy system loads than any other time. There is no cause-effect relationship
which creates the probability of simultaneous occurrence of other such events. Therefore
these types of events are highly unlikely to cause large-scale grid failures. Thus, this
Standard’s emphasis is on vegetation grow-ins.
Draft 4: June 165: December 17, 2010
7
FAC-003-2 — Transmission Vegetation Management
Re q u ire m e n ts a n d Me a s u re s
R1. Each Transmission Owner shall manage
Rationale
vegetation to prevent encroachment that could
The MVCD is a calculated minimum
result in a Sustained Outageencroachments of
distance stated in feet (meters) to prevent
the types shown below, into the Minimum
sparkflash-over between conductors and
Vegetation Clearance Distance (MVCD) of
vegetation, for various altitudes and
any of its applicable line(s) identified as an
operating voltages. The distances in Table 2
element of an Interconnection Reliability
were derived using a proven transmission
Operating Limit (IROL) in the planning
design method. The types of failure to
horizon by the Planning Coordinator; or Major
manage vegetation are listed in order of
Western Electricity Coordinating Council
increasing degrees of severity in non(WECC) transfer path ((s); operating within
compliant performance as it relates to a
its Rating and all Rated Electrical Operating
failure of a TO’s vegetation maintenance
3
Conditions). Types of encroachment include:.
program since the encroachments listed
1. An encroachment into the Minimum
require different and increasing levels of
Vegetation Clearance Distance (MVCD)
skills and knowledge and thus constitute a
MVCD as shown in FAC-003-Table 2,
logical progression of how well, or poorly, a
observed in Real-time, absent a Sustained
TO manages vegetation relative to this
Outage,
Requirement.
2. An encroachment due to a fall-in from
inside the active transmission line Rightof-Way (ROW) that caused a vegetation-related Sustained Outage,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the active transmission line ROW that caused a vegetation-related Sustained
Outage,
4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage.
[VRF – High] [Time Horizon – Real-time]
M1. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-time observations of any MVCD encroachments.
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation
encroachment within the MVCD has occurred from vegetation within the ROW, this
shall be considered the equivalent of a Real-time observation.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 243
This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to
this reliability standard, including natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, wind
shear, fresh gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice
storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree,
arboricultural activities or horticultural or agricultural activities, or removal or digging of vegetation. Nothing in this
footnote should be construed to limit the Transmission Owner’s right to exercise its full legal rights on the ROW.
Draft 4: June 165: December 17, 2010
8
FAC-003-2 — Transmission Vegetation Management
hour period. If an investigation of a Fault by a qualified person confirms that a
vegetation encroachment within the MVCD occurred, then it shall be considered a
Real-time observation. (R1)
Rationale
R2. Each Transmission Owner shall manage
The MVCD is a calculated minimum
vegetation to prevent encroachment that could
distance stated in feet (meters) to prevent
result in a Sustained Outage ofencroachments
flash-over between conductors and
of the types shown below, into the MVCD of
vegetation, for various altitudes and
any of its applicable linesline(s) that areis not
operating voltages. The distances in Table 2
elementsan element of an Interconnection
were derived using a proven transmission
Reliability Operating Limit (IROL); or
Rationale
design method. The types of failure to
Major Western Electricity Coordinating
The MVCD
a calculated
manageisvegetation
areminimum
listed in order of
Council (WECC) transfer path (;
distance
stated
in
feet
(meters)
to prevent
increasing degrees of severity
in nonoperating within its Rating and all Rated
spark-over
between
conductors
and
compliant
performance
as it
relates to a
Electrical Operating Conditions). Types
vegetation,
altitudes and
failurefor
of avarious
TO’s vegetation
maintenance
of encroachment include:.3
operating
voltages.
The
distances in Table
2
program
since
the
encroachments
listed
1. An encroachment into the Minimum
were require
deriveddifferent
using a proven
transmission
and increasing
levels of
Vegetation Clearance Distance
design
method.
skills
and knowledge and thus constitute a
(MVCD)MVCD as shown in FAClogical
progression of how well, or poorly,
003-Table 2, observed in Real-time,
a TO manages vegetation relative to this
absent a Sustained Outage,
Requirement.
2. An encroachment due to a fall-in from
inside the active transmission line ROW
that caused a vegetation-related Sustained
Outage,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the active transmission line ROW that caused a vegetation-related Sustained
Outage,
4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage.
[VRF – Medium] [Time Horizon – Real-time]
M2. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R2. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-time observations of any MVCD encroachments.
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation
encroachment within the MVCD has occurred from vegetation within the ROW, this
shall be considered the equivalent of a Real-time observation.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. If an investigation of a Fault by a qualified person confirms that a
vegetation encroachment within the MVCD occurred, then it shall be considered a
Real-time observation.(R2)
Draft 4: June 165: December 17, 2010
9
FAC-003-2 — Transmission Vegetation Management
Draft 4: June 165: December 17, 2010
10
FAC-003-2 — Transmission Vegetation Management
R3. Each Transmission Owner shall document
Rationale
the have documented maintenance strategies
The documentation provides a basis for
or procedures, or processes, or specifications
evaluating the competency of the
it uses to prevent the encroachment of
Transmission Owner’s vegetation program.
vegetation into the MVCD. Such
There may be many acceptable approaches
documentation will incorporate of its
to maintain clearances. Any approach must
applicable transmission lines that include(s)
demonstrate that the Transmission Owner
the following:
avoids vegetation-to-wire conflicts under all
3.1 Accounts for the dynamicsmovement of
Rated Electrical Operating Conditions. See
aapplicable transmission line
Figure 1 for an illustration of possible
conductor’s movement throughout its
conductor locations.
conductors under their Facility
Rationale
Rating and all Rated Electrical
Provide a basis for evaluation on the intent
Operating Conditions and;
and competency of the Transmission Owner
3.2 Accounts for the inter-relationships
in maintaining vegetation. There may be
between vegetation growth rates,
many acceptable approaches to maintain
vegetation control methods, and
clearances. However, the Transmission
inspection frequency, for the
Owner should be able to state what its
Transmission Owner’s applicable
approach is and how it conducts work to
lines..
maintain clearances. See Figure 1 for an
illustration of possible conductor locations.
[VRF – Lower] [Time Horizon – Long
Term Planning]
M3. The maintenance strategies or procedures, or processes, or specifications provided
demonstrate that the Transmission Owner can prevent encroachment into the MVCD
considering the factors identified in the requirement. (R3)
R4. Each Transmission Owner, without any
intentional time delay, shall notify the
control center holding switching authority
for the associated applicable transmission
line when qualified personnel confirmthe
Transmission Owner has confirmed the
existence of a vegetation condition that is
likely to cause a Fault at any moment.
Rationale
ToRationale
ensure expeditious communication
between
qualified
field personnel
and between
To ensure
expeditious
communication
proper
operating personnel
when
critical center
the Transmission
Owner and
thea control
situation
confirmed.
Qualified
field
when aiscritical
situation
is confirmed.
personnel may include lineworkers and
utility arborists.
[VRF – Medium] [Time Horizon – Real-time]
M4. Each Transmission Owner that has a confirmed vegetation condition likely to cause a
Fault at any moment, as confirmed by qualified personnel, will have evidence that it
notified the control center holding switching authority for the associated transmission
line without any intentional time delay. Examples of evidence may include control
Draft 4: June 165: December 17, 2010
11
FAC-003-2 — Transmission Vegetation Management
center logs, voice recordings, switching orders, clearance orders and subsequent work
orders. (R4)
Draft 4: June 165: December 17, 2010
12
FAC-003-2 — Transmission Vegetation Management
R5. EachWhen a Transmission Owner shall take
Rationale
corrective action when it is constrained from
Legal actions and other events may occur
performing planned vegetation work, where a
which result in constraints that prevent the
transmission line is put at potential risk due to
Transmission Owner from performing
and the constraint may lead to a vegetation
planned vegetation maintenance work.
encroachment into the MVCD of its
In cases where the transmission line is put at
applicable transmission lines prior to the
potential risk due to constraints, the intent is
implementation of the next annual work plan
for the Transmission Owner to put interim
then the Transmission Owner shall take
measures in place, rather than do nothing.
corrective action to ensure continued
The corrective action process is intended to
vegetation management to prevent
Rationale
address situations where a planned work
encroachments.
Legalmethodology
actions and other
may occur
cannotevents
be performed
but an
[VRF – Medium] [Time Horizon –
Operations Planning]
M5. Each Transmission Owner has
evidence of the corrective action
taken for each constraint where aan
applicable transmission line was put
at potential risk. Examples of
acceptable forms of evidence may
include initially-planned work
orders, documentation of constraints
from landowners, court orders,
inspection records of increased
monitoring, documentation of the
de-rating of lines, revised work
orders, invoices, and evidence that a
line was de-energized. (R5)
which
result inwork
constraints
that prevent
alternate
methodology
can bethe
used.
Transmission Owner from performing
planned vegetation maintenance work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the Transmission Owner to put interim
measures in place, rather than do nothing.
For example, in the 2003 NE blackout a
Transmission Owner was prevented by a
court order from performing planned work.
However, when the court order expired, the
TO failed to take action to maintain the
vegetation resulting in a sustained outage
that contributed to the cascade.
The corrective action process is not
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
Rationale
Inspections are used by Transmission
Owners to assess the condition of the entire
ROW. The information from the assessment
can be used to determine risk, determine
future work and evaluate recentlycompleted work. This requirement sets a
minimum Vegetation Inspection frequency
of once per calendar year. but with no more
than 18 months between inspections on the
4
When the Transmission Owner is prevented from performing a Vegetation
Inspection
within
the timeframe
in R6
same ROW.
Based
upon
average growth
due to a natural disaster, the TO is granted a time extension that is equivalent
to theNorth
duration
of the time
was
rates across
America
andtheonTOcommon
prevented from performing the Vegetation Inspection.
utility practice, this minimum frequency is
reasonable. Transmission Owners should
consider local and environmental factors
13
Draft 4: June 165: December 17, 2010
that could warrant more frequent
inspections.
R6. Each Transmission Owner shall perform a
Vegetation Inspection of all100% of its
applicable transmission lines (measured in
units of choice - circuit, pole line, line miles or
kilometers, etc.) at least once per calendar
year. and with no more than 18 months
between inspections on the same ROW. 4
FAC-003-2 — Transmission Vegetation Management
[VRF – Medium] [Time Horizon – Operations Planning]
[VRF – Medium] [Time Horizon – Operations Planning]
M6. Each Transmission Owner has evidence that it conducted Vegetation Inspections at
least once per calendar year of the transmission line ROW for all applicable
transmission lines at least once per calendar year but with no more than 18 months
between inspections on the same ROW. Examples of acceptable forms of evidence
may include completed and dated work orders, dated invoices, or dated inspection
records. (R6)
Rationale
R7. Each Transmission Owner shall complete the
Rationale
This
requirement sets the expectation
work in an100% of its annual vegetation
This
setsin
thethe
expectation
that
the requirement
work identified
annual that
work plan to ensure no vegetation
the
work
identified
in
the
annual
work plan
work plan will be completed as planned.
encroachments occur within the MVCD.
will
be
completed
as
planned.
An
annual
An annual vegetation work plan allows
Modifications to the work plan in response
plan allows
for work to be
forvegetation
work to bework
modified
for changing
to changing conditions or to findings from
modified taking
for changing
conditions, taking
conditions,
into consideration
vegetation inspections may be made and
into
consideration
anticipated
anticipated growth of vegetation growth
and all of
documented (provided they do not put the
vegetation
and all factors,
other environmental
other
environmental
provided
transmission system at risk of a vegetation
factors,
provided
thatviolate
the changes
that
the changes
do not
the do not
encroachment.) and must be documented.
violate
the
encroachment
within
encroachment within the MVCD. the MVCD.
The percent completed calculation is based
on the number of units actually completed
divided by the number of units in the final amended plan (measured in units of choice circuit, pole line, line miles or kilometers, etc.) Examples of reasons for modification to
annual plan may include:
•
•
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Major storms
Circumstances that are beyond the control of a Transmission Owner 5
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Funding adjustments (increase or decrease)
Emerging technologies
[VRF – Medium] [Time Horizon – Operations Planning]
5
Circumstances that are beyond the control of a Transmission Owner include but are not limited to natural disasters
such as earthquakes, fires, tornados, hurricanes, landslides, major storms as defined either by the TO or an
applicable regulatory body, ice storms, and floods; arboricultural, horticultural or agricultural activities.
Draft 4: June 165: December 17, 2010
14
FAC-003-2 — Transmission Vegetation Management
[VRF – Medium] [Time Horizon – Operations Planning]
M7. Each Transmission Owner has evidence that it completed its annual vegetation work
plan. Examples of acceptable forms of evidence may include a copy of the completed annual
work plan (including modifications if any), dated work orders, dated invoices, or dated
inspection records. (R7)
Draft 4: June 165: December 17, 2010
15
FAC-003-2 — Transmission Vegetation Management
Co m p lia n c e
Compliance Enforcement Authority
•
Regional Entity
Compliance Monitoring and Enforcement Processes:
•
•
•
•
•
•
•
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
Periodic Data Submittals
Evidence Retention
The Transmission Owner retains data or evidence ofto show compliance with Requirements
R1 through, R2, R3, R5, R6 and R7, Measures M1 through, M2, M3, M5, M6 and M7 for
three calendar years to show complianceunless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an investigation.
The Transmission Owner retains data or evidence to show compliance with Requirement R4,
Measure M4 for most recent 12 months of operator logs or most recent 3 months of voice
recordings or transcripts of voice recordings, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an investigation.
If a Transmission Owner is found non-compliant, it shall keep information related to the noncompliance until found compliant, or for the durationtime period specified above, whichever
is longer.
The Compliance Enforcement Authority shall keep the last audit records and all requested
and submitted subsequent audit records.
Additional Compliance Information
Periodic Data Submittal: The Transmission Owner will submit a quarterly report to its
Regional Entity, or the Regional Entity’s designee, identifying all Sustained Outages of
applicable transmission lines determined by the Transmission Owner to have been caused by
vegetation that, except as excluded in footnote 2, which includes, as a minimum, the
following:
o The name of the circuit(s), the date, time and duration of the outage; the voltage
of the circuit; a description of the cause of the outage; the category associated
with the Sustained Outage; other pertinent comments; and any countermeasures
taken by the Transmission Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation growing into
applicable transmission lines, that are identified as an element of an IROL or
Draft 4: June 165: December 17, 2010
16
FAC-003-2 — Transmission Vegetation Management
Major WECC Transfer Path, by vegetation inside and/or outside of the active
transmission line ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation growing into
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, by vegetation inside and/or outside of the active
transmission line ROW;
o Category 22A — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines that are identified as an element of an IROL or
Major WECC Transfer Path, from within the active transmission line ROW;
o Category6 4 2B — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by vegetation and
applicable transmission lines that are identified as an element of an IROL or
Major WECC Transfer Path, blowing together from within the active transmission
lineROW.
o Category 4B — Blowing together: Sustained Outages caused by vegetation and
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, blowing together from within the ROW.
The Regional Entity will report the outage information provided by Transmission Owners, as
per the above, quarterly to NERC, as well as any actions taken by the Regional Entity as a
result of any of the reported Sustained Outages.
6
Category 3 reporting is eliminated.
Draft 4: June 165: December 17, 2010
17
FAC-003-2 — Transmission Vegetation Management
Tim e Horizo ns , Viola tio n Ris k Fa c tors , a n d Viola tio n S e ve rity Le ve ls
At the request of the Standards Committee,
stakeholders are asked to review and comment on
the proposed VSLs for R1 and R2. Following the
comment period and nonbinding poll, only one set of
VSLs will move forward for R1 and R2.
Table 1
R#
Time
Horizon
R1SDT
Version
R1 Staff
Version
Real-time
Realtime
VRF
High
Violation Severity Level
Lower
Moderate
High
Severe
The
Transmission
Owner had an
encroachment
into the
MVCD
observed in
Real-time,
absent a
Sustained
Outage.
The Transmission Owner had an
encroachment into the MVCD due to a
fall-in from inside the active
transmission line ROW that caused a
vegetation-related Sustained Outage.
The Transmission Owner had
an encroachment into the
MVCD due to blowing
together of applicable lines
and vegetation located inside
the active transmission line
ROW that caused a
vegetation-related Sustained
Outage.
The Transmission Owner had an
encroachment into the MVCD
due to a grow-in that caused a
vegetation-related Sustained
Outage.
High
The Transmission Owner failed
to manage vegetation to prevent
encroachment into the MVCD of
a line identified as an element of
an IROL or Major WECC
transfer path and encroachment
into the MVCD as identified in
FAC-003-Table 2 was observed
in real time absent a Sustained
Outage.
The Transmission Owner failed
to manage vegetation to prevent
encroachment into the MVCD
of a line identified as an element
of an IROL or Major WECC
transfer path and a vegetationrelated Sustained Outage was
caused by one of the following:
•
•
Draft 4: June 165: December 17, 2010
18
A fall-in from inside the
active transmission line
ROW
Blowing together of
applicable lines and
vegetation located inside the
active transmission line
ROW
Formatted Table
FAC-003-2 — Transmission Vegetation Management
R2SDT
Version
R2 Staff
Version
R3
Real-time
Realtime
Long-Term
Planning
Medium
The
Transmission
Owner had an
encroachment
into the
MVCD
observed in
Real-time,
absent a
Sustained
Outage.
The Transmission Owner had an
encroachment into the MVCD due to a
fall-in from inside the active
transmission line ROW that caused a
vegetation-related Sustained Outage.
The Transmission Owner failed
to manage vegetation to prevent
encroachment into the MVCD of
a line not identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD as
identified in FAC-003-Table 2
was observed in real time absent
a Sustained Outage.
Medium
Lower
Draft 4: June 165: December 17, 2010
The Transmission Owner had
an encroachment into the
MVCD due to blowing
together of applicable lines
and vegetation located inside
the active transmission line
ROW that caused a
vegetation-related Sustained
Outage.
The Transmission Owner has
maintenance strategies or documented
the procedures, or processes, or
specifications but doeshas not
incorporateaccounted for the inter-
The Transmission Owner has
maintenance strategies or
documented the procedures,
or processes, or
specifications but doeshas
19
• A grow-in
The Transmission Owner had an
encroachment into the MVCD
due to a grow-in that caused a
vegetation-related Sustained
Outage.
Formatted Table
The Transmission Owner failed
to manage vegetation to prevent
encroachment into the MVCD
of a line not identified as an
element of an IROL or Major
WECC transfer path and a
vegetation-related Sustained
Outage was caused by one of the
following:
•
A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside the
active transmission line
ROW
• A grow-in
The Transmission Owner does
not have any maintenance
strategies or documented
procedures, or processes or
specifications used to prevent
Formatted Table
FAC-003-2 — Transmission Vegetation Management
relationships between vegetation
growth rates, vegetation control
methods, and inspection frequency,
for the Transmission Owner’s
applicable lines.
R4
R5
R6
Real-time
Operations
Planning
Operations
Planning
Medium
not incorporateaccounted for
the dynamicsmovement of a
transmission line conductor’s
movement throughout
itsconductors under their
Rating and all Rated
Electrical Operating
Conditions, for the
Transmission Owner’s
applicable lines.
the encroachment of vegetation
into the MVCD, for the
Transmission Owner’s
applicable lines.
The Transmission Owner
experienced a confirmed
vegetation threat confirmed
by qualified personnel and
notified the control center
holding switching authority
for that transmission line, but
there was intentional delay in
that notification.
The Transmission Owner
experienced a confirmed
vegetation threat confirmed by
qualified personnel and did not
notify the control center holding
switching authority for that
transmission line.
The Transmission Owner did
not take corrective action when
it was constrained from
performing planned vegetation
work where a transmission line
was put at potential risk.
Medium
Medium
The
Transmission
Owner failed
to inspect 5%
or less of the
ROW as
measured
byits
applicableline miles
Draft 4: June 165: December 17, 2010
The Transmission Owner failed to
inspect more than 5% up to and
including 10% of the ROW as
measured byits applicable-line miles
(kilometers) (based on transmission
lines (measured in units of choice: circuit, pole line, ROWline miles or
kilometers, etc.).
The Transmission Owner
failed to inspect more than
10% up to and including
15% of the ROW as
measured byits applicableline miles (kilometers)
(based on transmission lines
(measured in units of choice:
- circuit, pole line, ROWline
miles or kilometers, etc.).
20
The Transmission Owner failed
to inspect more than 15% of the
ROW as measured byits
applicable-line miles
(kilometers) (based on
transmission lines (measured in
units of choice: - circuit, pole
line, ROWline miles or
kilometers, etc.).
Formatted Table
FAC-003-2 — Transmission Vegetation Management
(kilometers)
(based on
transmission
lines
(measured in
units of
choice: circuit, pole
line,
ROWline
miles or
kilometers,
etc.)..)
R7
Operations
Planning
Medium
The
Transmission
Owner failed
to complete
up to 5% of
its annual
vegetation
work plan
(including
modifications
if any).
Draft 4: June 165: December 17, 2010
The Transmission Owner failed to
complete more than 5% and up to 10%
of its annual vegetation work plan
(including modifications if any).
The Transmission Owner
failed to complete more than
10% and up to 15% of its
annual vegetation work plan
(including modifications if
any).
21
The Transmission Owner failed
to complete more than 15% of
its annual vegetation work plan
(including modifications if any).
FAC-003-2 — Transmission Vegetation Management
Va ria n c e s
None.
In te rp re ta tio n s
None.
Draft 4: June 16, 2010
25
FAC-003-2 — Transmission Vegetation Management
GuidelinesGuideline and Technical Basis
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the prevention of vegetation encroachments within a minimum distance of
transmission lines. Content-wise, R1 and R2 are the same requirements; however, they apply to
different Facilities. Both R1 and R2 require each Transmission Owner to preventmanage
vegetation from encroachingto prevent encroachment within the Minimum Vegetation Clearance
Distance (“MVCD”) of transmission lines. R1 is applicable to lines “identified as an element of an
Interconnection Reliability Operating Limit (IROL) or Major Western Electricity Coordinating
Council (WECC) transfer path (operating within Rating and Rated Electrical Operating
Conditions) to avoid a Sustained Outage”. R2 applies to all other applicable lines that are not an
element of an IROL or Major WECC Transfer Path.
The separation of applicability (between R1 and R2) recognizes that an encroachment into the
MVCD of an IROL or Major WECC Transfer Path transmission line is a greater risk to the
electric transmission system. Applicable lines that are not an element of an IROL or Major
WECC Transfer Path are required to be clear of vegetation but these lines are comparatively less
operationally significant. As a reflection of this difference in risk impact, the Violation Risk
Factors (VRFs) are assigned as High for R1 and Medium for R2.
These requirements (R1 and R2) state that if vegetation encroaches within the distances
prescribed in Table 1 in Appendix 1 of this supplemental Transmission Vegetation Management
Standard FAC-003-2 Technical Reference document, it is in violation of the standard. Table 2
delineatestabulates the distances necessary to prevent spark-over based on the Gallet equations as
described more fully in a supplemental Transmission Vegetation Management Standard FAC003-2 Technical Reference.Appendix 1 below.
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating
(potentially in violation of other standards), the occurrence of a clearance encroachment may
occur. For example, emergency actions taken by a Transmission Operator or Reliability
Coordinator to protect an Interconnection may cause the transmission line to sag more and come
closer to vegetation, potentially causing an outage. Such vegetation-related outages are not a
violation of these requirements.
Evidence of violation of Requirement R1 and R2 include real-time observation of a vegetation
encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related encroachment
resulting in a Sustained Outage due to a fall-in from inside the active transmission line ROW, or
a vegetation-related encroachment resulting in a Sustained Outage due to blowing together of
applicable lines and vegetation located inside the active transmission line ROW, or a vegetationrelated encroachment resulting in a Sustained Outage due to a grow-in. If an investigation of a
Fault by a qualified personTransmission Owner confirms that a vegetation encroachment within
the MVCD occurred, then it shall be considered the equivalent of a Real-time observation.
With this approach, the VSLs were defined such that they directly correlate to the severity of a
failure of a Transmission Owner to keepmanage vegetation away from conductors and to the
corresponding performance level of the Transmission Owner’s vegetation program’s ability to
meet the goal of “preventing a Sustained Outage that could lead to Cascading.” Thus violation
Draft 4: June 16, 2010
25
FAC-003-2 — Transmission Vegetation Management
severity increases with a Transmission Owner’s inability to meet this goal and its potential of
leading to a Cascading event. The additional benefits of such a combination are that it simplifies
the standard and clearly defines performance for compliance. A performance-based requirement
of this nature will promote high quality, cost effective vegetation management programs that will
deliver the overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation,. For
example, a limb thatmay only partially breaksbreak and intermittently contactscontact a
conductor. Such events are considered to be a single vegetation-related Sustained Outage under
the Standard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will help prevent transmission outages.
Requirement R3:
Requirement R3 is a competency based requirement concerned with the maintenance strategies,
procedures, processes, or specifications, a Transmission Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the
Transmission Owner uses to plan and perform vegetation work to prevent transmission Sustained
Outages and minimize risk to the Transmission System. The approach provides the basis for
evaluating the intent, allocation of appropriate resources and the competency of the Transmission
Owner in managing vegetation. There are many acceptable approaches to manage vegetation
and avoid Sustained Outages. However, the Transmission Owner must be able to state what its
approach is and how it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach a
Transmission Owner chooses to use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the Transmission Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing as a reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figure 1 below.
Draft 4: June 16, 2010
25
FAC-003-2 — Transmission Vegetation Management
Figure 1
Cross-section view of a single conductor at a given point along the span showing six possible
conductor positions due to movement resulting from thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the
Transmission Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4
involves the notification of potentially threatening vegetation conditions, without any intentional
delay, to the control center holding switching authority for that specific transmission line.
Examples of acceptable unintentional delays may include communication system problems (for
example, cellular service or two-way radio disabled), crews located in remote field locations
with no communication access, delays due to severe weather, etc.
Draft 4: June 16, 2010
25
FAC-003-2 — Transmission Vegetation Management
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of a qualifiedTransmission Owner’s employee who personally identifies such a threat in
the field. Confirmation could also be made by sending out a qualified personan employee to
evaluate a situation reported by a landowner or an unqualified employee.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an assessment
of the possible sag or movement of the conductor while operating between no-load conditions
and its rating.
The Transmission Owner has the responsibility to ensure the proper communication between
field personnel and the control center to allow the control center to take the appropriate action
until the vegetation threat is relieved. Appropriate actions may include a temporary reduction in
the line loading, switching the line out of service, or positioning the system in recognition of the
increasing risk of outage on that circuit. The notification of the threat should be communicated in
terms of minutes or hours as opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some Transmission Owners may have a danger tree identification
program that identifies trees for removal with the potential to fall near the line. These trees
would not require notification to the control center unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
Transmission Owner for the mitigation of Sustained Outage risk when temporarily constrained
from performing vegetation maintenance. The intent of this requirement is to deal with situations
that prevent the Transmission Owner from performing planned vegetation management work
and, as a result, have the potential to put the transmission line at risk. Constraints to performing
vegetation maintenance work as planned could result from legal injunctions filed by property
owners, the discovery of easement stipulations which limit the Transmission Owner’s rights, or
other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
Transmission Owner is not under any immediate time constraint for achieving the management
objective, can easily reschedule work using an alternate approach, and therefore does not need to
take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the Transmission Owner is required to take an interim corrective action to mitigate the potential
risk to the transmission line. A wide range of actions can be taken to address various situations.
General considerations include:
Draft 4: June 16, 2010
25
FAC-003-2 — Transmission Vegetation Management
•
•
•
•
•
Identifying locations where the Transmission Owner is constrained from performing
planned vegetation maintenance work which potentially leaves the transmission line
at risk.
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for each location.
In developing the specific action to mitigate the potential risk to the transmission line
the Transmission Owner could consider location specific measures such as modifying
the inspection and/or maintenance intervals. Where a legal constraint would not allow
any vegetation work, the interim corrective action could include limiting the loading
on the transmission line.
The Transmission Owner should document and track the specific corrective action
taken at each location. This location may be indicated as one span, one tree or a
combination of spans on one property where the constraint is considered to be
temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections that fits general industry practice. In addition, the fact that Vegetation
Inspections can be performed in conjunction with general line inspections further facilitates a
Transmission Owner’s ability to meet this requirement. However, the Transmission Owner may
determine that more frequent inspections are needed to maintain reliability levels, dependent
upon such factors as anticipated growth rates of the local vegetation, length of the growing
season for the geographical area, limited Active Transmission ROW width, and rainfall amounts.
Therefore it is expected that some transmission lines may be designated with a higher frequency
of inspections.
The VSL for Requirement R6 has VSL categories ranked by the percentage of the required ROW
inspections completed. To calculate the percentage of inspection completion, the Transmission
Owner may choose units such as: line miles or kilometers, circuit miles or kilometers, pole line
miles, ROW miles, etc.
For example, when a Transmission Owner operates 2,000 miles of 230 kV transmission lines this
Transmission Owner will be responsible for inspecting all 2,000 miles of 230 kV transmission
lines at least once during the calendar year. If one of the included lines was 100 miles long, and
if it was not inspected during the year, then the amount failed to inspect would be 100/2000 =
0.05 or 5%. The “Low VSL” for R6 would apply in this example.
Requirement R7:
R7 is a risk-based requirement. The Transmission Owner is required to implement an annual
work plan for vegetation management to accomplish the purpose of this standard. Modifications
to the work plan in response to changing conditions or to findings from vegetation inspections
Draft 4: June 16, 2010
25
FAC-003-2 — Transmission Vegetation Management
may be made and documented provided they do not put the transmission system at risk. The
annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a
“line-by-line” detailed description of all work to be performed. It is only intended to require that
the Transmission Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation into
the MVCD.
The ability to modify the work plan allows the Transmission Owner to change priorities or
treatment methodologies during the year as conditions or situations dictate. For example recent
line inspections may identify unanticipated high priority work, weather conditions (drought)
could make herbicide application ineffective during the plan year, or a major storm could require
redirecting local resources away from planned maintenance. This situation may also include
complying with mutual assistance agreements by moving resources off the Transmission
Owner’s system to work on another system. Any of these examples could result in acceptable
deferrals or additions to the annual work plan. Modifications to the annual work plan must
always ensure the reliability of the electric Transmission system.
In general, the vegetation management maintenance approach should use the full extent of the
Transmission Owner’s easement, fee simple and other legal rights allowed. A comprehensive
approach that exercises the full extent of legal rights on the active transmission line ROW is
superior to incremental management in the long term because it reduces the overall potential for
encroachments, and it ensures that future planned work and future planned inspection cycles are
sufficient.
When developing the annual work plan the Transmission Owner should allow time for
procedural requirements to obtain permits to work on federal, state, provincial, public, tribal
lands. In some cases the lead time for obtaining permits may necessitate preparing work plans
more than a year prior to work start dates. Transmission Owners may also need to consider those
special landowner requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the Transmission
Owner, evidence of successful annual work plan execution could consist of signed-off work
orders, signed contracts, printouts from work management systems, spreadsheets of planned
versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence
may include photographs, and walk-through reports.
Draft 4: June 16, 2010
25
FAC-003-2 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD)
7
For Alternating Current Voltages
( AC )
Nominal
System
Voltage
(kV)
( AC )
Maximum
System
Voltage
(kV)
765
800
500
550
345
362
230
242
161*
169
138*
145
115*
121
88*
100
69*
72
MVCD
feet
(meters)
sea level
8.06ft
(2.46m)
5.06ft
(1.54m)
3.12ft
(0.95m)
2.97ft
(0.91m)
2ft
(0.61m)
1.7ft
(0.52m)
1.41ft
(0.43m)
1.15ft
(0.35m)
0.82ft
(0.25m)
MVCD
feet
(meters)
3,000ft
(914.4m)
MVCD
feet
(meters)
4,000ft
(1219.2m)
MVCD
feet
(meters)
5,000ft
(1524m)
MVCD
feet
(meters)
6,000ft
(1828.8m)
8.89ft
(2.71m)
5.66ft
(1.73m)
3.53ft
(1.08m)
3.36ft
(1.02m)
2.28ft
(0.69m)
1.94ft
(0.59m)
1.61ft
(0.49m)
1.32ft
(0.40m)
0.94ft
(0.29m)
9.17ft
(2.80m)
5.86ft
(1.79m)
3.67ft
(1.12m)
3.49ft
(1.06m)
2.38ft
(0.73m)
2.03ft
(0.62m)
1.68ft
(0.51m)
1.38ft
(0.42m)
0.99ft
(0.30m)
9.45ft
(2.88m)
6.07ft
(1.85m)
3.82ft
(1.16m)
3.63ft
(1.11m)
2.48ft
(0.76m)
2.12ft
(0.65m)
1.75ft
(0.53m)
1.44ft
(0.44m)
1.03ft
(0.31m)
9.73ft
(2.97m)
6.28ft
(1.91m)
3.97ft
(1.21m)
3.78ft
(1.15m)
2.58ft
(0.79m)
2.21ft
(0.67m)
1.83ft
(0.56m)
1.5ft
(0.46m)
1.08ft
(0.33m)
MVCD
feet
(meters)
7,000ft
(2133.6m)
MVCD
feet
(meters)
8,000ft
(2438.4m)
MVCD
feet
(meters)
9,000ft
(2743.2m)
MVCD
feet
(meters)
10,000ft
(3048m)
MVCD
feet
(meters)
11,000ft
(3352.8m)
10.01ft
(3.05m)
6.49ft
(1.98m)
4.12ft
(1.26m)
3.92ft
(1.19m)
2.69ft
(0.82m)
2.3ft
(0.70m)
1.91ft
(0.58m)
1.57ft
(0.48m)
1.13ft
(0.34m)
10.29ft
(3.14m)
6.7ft
(2.04m)
4.27ft
(1.30m)
4.07ft
(1.24m)
2.8ft
(0.85m)
2.4ft
(0.73m)
1.99ft
(0.61m)
1.64ft
(0.50m)
1.18ft
(0.36m)
10.57ft
(3.22m)
6.92ft
(2.11m)
4.43ft
(1.35m)
4.22ft
(1.29m)
2.91ft
(0.89m)
2.49ft
(0.76m)
2.07ft
(0.63m)
1.71ft
(0.52m)
1.23ft
(0.37m)
10.85ft
(3.31m)
7.13ft
(2.17m)
4.58ft
(1.40m)
4.37ft
(1.33m)
3.03ft
(0.92m)
2.59ft
(0.79m)
2.16ft
(0.66m)
1.78ft
(0.54m)
1.28ft
(0.39m)
11.13ft
(3.39m)
7.35ft
(2.24m)
4.74ft
(1.44m)
4.53ft
(1.38m)
3.14ft
(0.96m)
2.7ft
(0.82m)
2.25ft
(0.69m)
1.86ft
(0.57m)
1.34ft
(0.41m)
* Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above).
7
The distances in this Table are the minimums required to prevent FlashoverFlash-over; however prudent vegetation maintenance practices dictate that
substantially greater distances will be achieved at time of vegetation maintenance.
Draft 5: December 17, 2010
29
FAC-003-2 — Transmission Vegetation Management
Table 2 (cont.) — Minimum Vegetation Clearance Distances (MVCD)
For Direct Current Voltages
sea level
MVCD feet
(meters)
3,000ft
(914.4m)
Alt.
MVCD feet
(meters)
4,000ft
(1219.2m)
Alt.
MVCD feet
(meters)
5,000ft
(1524m)
Alt.
MVCD feet
(meters)
6,000ft
(1828.8m)
Alt.
MVCD
feet
(meters)
7,000ft
(2133.6m)
Alt.
MVCD
feet
(meters)
(8,000ft
(2438.4m)
Alt.
MVCD
feet
(meters)
9,000ft
(2743.2m)
Alt.
MVCD
feet
(meters)
10,000ft
(3048m)
Alt.
MVCD
feet
(meters)
11,000ft
(3352.8m)
Alt.
±750
13.92ft
(4.24m)
15.07ft
(4.59m)
15.45ft
(4.71m)
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.9ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
±600
10.07ft
(3.07m)
11.04ft
(3.36m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
(13.54ft
4.13m)
±500
7.89ft
(2.40m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
±400
4.78ft
(1.46m)
5.35ft
(1.63m)
5.55ft
(1.69m)
5.75ft
(1.75m)
5.95ft
(1.81m)
6.15ft
(1.87m)
6.36ft
(1.94m)
6.57ft
(2.00m)
6.77ft
(2.06m)
6.98ft
(2.13m)
±250
3.43ft
(1.05m)
4.02ft
(1.23m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5ft
(1.52m)
5.17ft
(1.58m)
( DC )
Nominal Pole
to Ground
Voltage
(kV)
MVCD feet
(meters)
Draft 5: December 17, 2010
30
FAC-003-2 — Transmission Vegetation Management
Table 3 – Minimum Distance from the Centerline of the Circuit to the edge of the active transmission line ROW
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a misapplication. The SDT consulted specialists
who advised that the Gallet Equation would be a technically justified method. The explanation of why the Gallet approach is more
appropriate is explained in the paragraphs below.
The drafting team sought a method of establishing minimum clearance distances that uses realistic weather conditions and realistic
maximum transient over-voltages factors for in-service transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to conductor distances in FAC-003-1:
• avoid the problem associated with referring to tables in another standard (IEEE-516-2003)
• transmission lines operate in non-laboratory environments (wet conditions)
• transient over-voltage factors are lower for in-service transmission lines than for inadvertently re-energized transmission lines
with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in IEEE 516-2003 to determine the
minimum distance between a transmission line conductor and vegetation. The equations and methods provided in IEEE 516 were
developed by an IEEE Task Force in 1968 from test data provided by thirteen independent laboratories. The distances provided in
IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap, or in other words, dry laboratory conditions.
Consequently, the validity of using these distances in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the minimum clearance distances. Table 5
could be used if the Transmission Owner knew the maximum transient over-voltage factor for its system. Otherwise, Table 7 would
have to be used. Table 7 represented minimum air insulation distances under the worst possible case for transient over-voltage factors.
These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV
phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for concern in this
particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is inadvertently re-energized immediately after the
line is de-energized and a trapped charge is still present. The intent of FAC-003 is to keep a transmission line that is in service from
becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst case
Draft 5: December 17, 2010
31
FAC-003-2 — Transmission Vegetation Management
transient overvoltage assumptions are not appropriate for this application. Rather, the appropriate over voltage values are those that
occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are
negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 per unit. This value is a conservative estimate of the transient overvoltage that is created at the point of application (e.g. a substation) by switching a capacitor bank without pre-insertion devices (e.g.
closing resistors). At voltage levels where capacitor banks are not very common (e.g. 362 kV), the maximum transient over-voltage of
an in-service ac line are created by fault initiation on adjacent ac lines and shunt reactor bank switching. These transient voltages are
usually 1.5 per unit or less.
Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order
to be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient
over-voltage factor of 2.0 per unit for transmission lines operated at 242 kV and below is considered to be a realistic maximum in this
application. Likewise, for ac transmission lines operated at 362 kV and above a transient over-voltage factor of 1.4 per unit is
considered a realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These equations are used for computing the
required strike distances for proper transmission line insulation coordination. They were developed for both wet and dry applications
and can be used with any value of transient over-voltage factor. The Gallet Equation also can take into account various air gap
geometries. This approach was used to design the first 500 kV and 765 kV lines in North America [1].
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical spark-over distances
computed using the Gallet wet equations, for each of the nominal voltage classes and identical transient over-voltage factors, the
Gallet equations yield a more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are not vastly different when the same
transient overvoltage factors are used; the “wet” equations will consistently produce slightly larger distances than the IEEE 516
equations when the same transient overvoltage is used. While the IEEE 516 equations were only developed for dry conditions the
Gallet equations have provisions to calculate spark-over distances for both wet and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live vegetation, there are no spark-over formulas
currently derived expressly for vegetation to conductor minimum distances. Therefore the SDT chose a proven method that has been
Draft 5: December 17, 2010
32
FAC-003-2 — Transmission Vegetation Management
used in other EHV applications. The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage
Factor that is consistent with the absence of trapped charges on an in-service transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the Gallet equations using various
transient overvoltage values.
Draft 5: December 17, 2010
33
FAC-003-2 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations
vs.
IEEE 516-2003 MAID distances
using various transient over-voltage factors
69 - 138 kV
139 - 230
kV( AC )
231 - 345
kVNom
( AC )
Transient
System
Max System
Over-voltage
Voltage (kV)
Voltage (kV)
Factor (T)
501 - 765 kV
800
550
362
242
121
1.4
1.4
1.4
2.0
2.0
Table 5
Inserted Cells
IEEE 516
75 ft.Gallet (wet)
87.5 ft.@ Alt.
Inserted Cells
3000 feet
MAID (ft)
@ Alt. 3000 feet
100 ft.8.89
8.65
4.92
3.13
2.8
1.4
5.65
3.52
3.35
1.6
Table 5
(historical maximums)
( AC )
Nom System
Voltage (kV)
( AC )
Max System
Voltage (kV)
Transient
Over-voltage
Factor (T)
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
765
500
345
230
115
800
550
362
242
121
2.0
2.4
3.0
3.0
3.0
14.36
11.0
8.55
5.28
2.46
Draft 5: December 17, 2010
Formatted Table
Inserted Cells
346 - 500
500
345
230
115
37.5 ft.
50 Clearance
(ft..)
IEEE 516
MAID (ft)
@ Alt. 3000 feet
13.95
10.07
7.47
4.2
2.1
34
Formatted Table
Inserted Cells
Inserted Cells
Inserted Cells
FAC-003-2 — Transmission Vegetation Management
Table 7
( AC )
Nom System
Voltage (kV)
( AC )
Max System
Voltage (kV)
Transient
Over-voltage
Factor (T)
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
765
500
345
230
115
800
550
362
242
121
2.5
3.0
3.5
3.5
3.5
20.25
15.02
10.42
6.32
2.90
Draft 5: December 17, 2010
IEEE 516
MAID (ft)
@ Alt. 3000 feet
20.4
14.7
9.44
5.14
2.45
35
Implementation Plan for FAC-003-2
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress
or approved, that must be implemented before this standard can be implemented.
FAC-003-2 – Vegetation Management
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. There are
two revised definitions in the proposed standard. FAC-003-1 will be retired when FAC-003-2
becomes effective.
Compliance with Standard
The standard applies to Transmission Owners.
Effective Date
The effective date is the date entities are expected to meet the performance identified in this
standard. The effective date allows entities time to make revisions to their existing transmission
vegetation management programs to comply with the new requirements.
First calendar day of the first calendar quarter one year after the date of the order approving
the standard from applicable regulatory authorities where such explicit approval is required.
Exceptions:
A line operated below 200kV, designated by the Planning Coordinator as an element of
an IROL or as a Major WECC transfer path, becomes subject to this standard 12
months after the date the Planning Coordinator or WECC initially designates the line as
being subject to this standard.
An existing transmission line operated at 200kV or higher that is newly acquired by an
asset owner and was not previously subject to this standard, becomes subject to this
standard 12 months after the acquisition date of the line.
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com
Implementation Plan for FAC-003-2
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress
or approved, that must be implemented before this standard can be implemented.
FAC-003-2 – Vegetation Management
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. There is
aare two revised definitiondefinitions in the proposed standard. FAC-003-1 will be retired when
FAC-003-2 becomes effective.
Compliance with Standard
The standard applies to Transmission Owners.
Effective Date
The effective date is the date entities are expected to meet the performance identified in this
standard. The effective date allows entities time to make revisions to their existing transmission
vegetation management programs to comply with the new requirements.
First calendar day of the first calendar quarter one year after the date of the order approving
the standard from applicable regulatory authorityauthorities where such explicit approval for
all requirementsis required.
1. First calendar day of the first calendar quarter one year following Board of Trustees
adoption unless governmental authority withholds approval
First calendar day of the first calendar quarter that is at least one year following Board of
Trustees adoption
Exceptions:
A line operated below 200kV, designated by the Planning Coordinator as an element of
an IROL or as a Major WECC transfer path, becomes subject to this standard 12
months after the date the Planning Coordinator or WECC initially designates the line as
being subject to this standard.
An existing transmission line operated at 200kV or higher that is newly acquired by an
asset owner and was not previously subject to this standard, becomes subject to this
standard 12 months after the acquisition date of the line.
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com
Standard FAC-003-1 — Transmission Vegetation Management Program
A.
B.
Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number:
FAC-003-1
3.
Purpose: To improve the reliability of the electric transmission systems by preventing
outages from vegetation located on transmission rights-of-way (ROW) and minimizing
outages from vegetation located adjacent to ROW, maintaining clearances between
transmission lines and vegetation on and along transmission ROW, and reporting vegetationrelated outages of the transmission systems to the respective Regional Reliability
Organizations (RRO) and the North American Electric Reliability Council (NERC).
4.
Applicability:
4.1. Transmission Owner.
4.2. Regional Reliability Organization.
4.3. This standard shall apply to all transmission lines operated at 200 kV and above and to
any lower voltage lines designated by the RRO as critical to the reliability of the
electric system in the region.
5.
Effective Dates:
5.1.
One calendar year from the date of adoption by the NERC Board of Trustees for
Requirements 1 and 2.
5.2.
Sixty calendar days from the date of adoption by the NERC Board of Trustees for
Requirements 3 and 4.
Requirements
R1. The Transmission Owner shall prepare, and keep current, a formal transmission vegetation
management program (TVMP). The TVMP shall include the Transmission Owner’s
objectives, practices, approved procedures, and work specifications 1.
R1.1. The TVMP shall define a schedule for and the type (aerial, ground) of ROW vegetation
inspections. This schedule should be flexible enough to adjust for changing
conditions. The inspection schedule shall be based on the anticipated growth of
vegetation and any other environmental or operational factors that could impact the
relationship of vegetation to the Transmission Owner’s transmission lines.
R1.2. The Transmission Owner, in the TVMP, shall identify and document clearances
between vegetation and any overhead, ungrounded supply conductors, taking into
consideration transmission line voltage, the effects of ambient temperature on
conductor sag under maximum design loading, and the effects of wind velocities on
conductor sway. Specifically, the Transmission Owner shall establish clearances to be
achieved at the time of vegetation management work identified herein as Clearance 1,
and shall also establish and maintain a set of clearances identified herein as Clearance
2 to prevent flashover between vegetation and overhead ungrounded supply
conductors.
R1.2.1. Clearance 1 — The Transmission Owner shall determine and document
appropriate clearance distances to be achieved at the time of transmission
vegetation management work based upon local conditions and the expected
time frame in which the Transmission Owner plans to return for future
1
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices, while
not a requirement of this standard, is considered to be an industry best practice.
Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
1 of 5
Standard FAC-003-1 — Transmission Vegetation Management Program
vegetation management work. Local conditions may include, but are not
limited to: operating voltage, appropriate vegetation management techniques,
fire risk, reasonably anticipated tree and conductor movement, species types
and growth rates, species failure characteristics, local climate and rainfall
patterns, line terrain and elevation, location of the vegetation within the span,
and worker approach distance requirements. Clearance 1 distances shall be
greater than those defined by Clearance 2 below.
R1.2.2. Clearance 2 — The Transmission Owner shall determine and document
specific radial clearances to be maintained between vegetation and conductors
under all rated electrical operating conditions. These minimum clearance
distances are necessary to prevent flashover between vegetation and
conductors and will vary due to such factors as altitude and operating voltage.
These Transmission Owner-specific minimum clearance distances shall be no
less than those set forth in the Institute of Electrical and Electronics Engineers
(IEEE) Standard 516-2003 (Guide for Maintenance Methods on Energized
Power Lines) and as specified in its Section 4.2.2.3, Minimum Air Insulation
Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 516-2003,
phase-to-ground distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 516-2003,
phase-to-phase voltages, with appropriate altitude correction
factors applied.
R1.3. All personnel directly involved in the design and implementation of the TVMP shall
hold appropriate qualifications and training, as defined by the Transmission Owner, to
perform their duties.
R1.4. Each Transmission Owner shall develop mitigation measures to achieve sufficient
clearances for the protection of the transmission facilities when it identifies locations
on the ROW where the Transmission Owner is restricted from attaining the clearances
specified in Requirement 1.2.1.
R1.5. Each Transmission Owner shall establish and document a process for the immediate
communication of vegetation conditions that present an imminent threat of a
transmission line outage. This is so that action (temporary reduction in line rating,
switching line out of service, etc.) may be taken until the threat is relieved.
R2. The Transmission Owner shall create and implement an annual plan for vegetation
management work to ensure the reliability of the system. The plan shall describe the methods
used, such as manual clearing, mechanical clearing, herbicide treatment, or other actions. The
plan should be flexible enough to adjust to changing conditions, taking into consideration
anticipated growth of vegetation and all other environmental factors that may have an impact
on the reliability of the transmission systems. Adjustments to the plan shall be documented as
they occur. The plan should take into consideration the time required to obtain permissions or
permits from landowners or regulatory authorities. Each Transmission Owner shall have
systems and procedures for documenting and tracking the planned vegetation management
work and ensuring that the vegetation management work was completed according to work
specifications.
Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
2 of 5
Standard FAC-003-1 — Transmission Vegetation Management Program
R3. The Transmission Owner shall report quarterly to its RRO, or the RRO’s designee, sustained
transmission line outages determined by the Transmission Owner to have been caused by
vegetation.
R3.1. Multiple sustained outages on an individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the actual number of outages within a 24hour period.
R3.2. The Transmission Owner is not required to report to the RRO, or the RRO’s designee,
certain sustained transmission line outages caused by vegetation: (1) Vegetationrelated outages that result from vegetation falling into lines from outside the ROW that
result from natural disasters shall not be considered reportable (examples of disasters
that could create non-reportable outages include, but are not limited to, earthquakes,
fires, tornados, hurricanes, landslides, wind shear, major storms as defined either by
the Transmission Owner or an applicable regulatory body, ice storms, and floods), and
(2) Vegetation-related outages due to human or animal activity shall not be considered
reportable (examples of human or animal activity that could cause a non-reportable
outage include, but are not limited to, logging, animal severing tree, vehicle contact
with tree, arboricultural activities or horticultural or agricultural activities, or removal
or digging of vegetation).
R3.3. The outage information provided by the Transmission Owner to the RRO, or the
RRO’s designee, shall include at a minimum: the name of the circuit(s) outaged, the
date, time and duration of the outage; a description of the cause of the outage; other
pertinent comments; and any countermeasures taken by the Transmission Owner.
R3.4. An outage shall be categorized as one of the following:
R3.4.1. Category 1 — Grow-ins: Outages caused by vegetation growing into lines
from vegetation inside and/or outside of the ROW;
R3.4.2. Category 2 — Fall-ins: Outages caused by vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages caused by vegetation falling into lines from
outside the ROW.
R4. The RRO shall report the outage information provided to it by Transmission Owner’s, as
required by Requirement 3, quarterly to NERC, as well as any actions taken by the RRO as a
result of any of the reported outages.
C.
Measures
M1. The Transmission Owner has a documented TVMP, as identified in Requirement 1.
M1.1. The Transmission Owner has documentation that the Transmission Owner performed
the vegetation inspections as identified in Requirement 1.1.
M1.2. The Transmission Owner has documentation that describes the clearances identified in
Requirement 1.2.
M1.3. The Transmission Owner has documentation that the personnel directly involved in the
design and implementation of the Transmission Owner’s TVMP hold the qualifications
identified by the Transmission Owner as required in Requirement 1.3.
M1.4. The Transmission Owner has documentation that it has identified any areas not
meeting the Transmission Owner’s standard for vegetation management and any
mitigating measures the Transmission Owner has taken to address these deficiencies as
identified in Requirement 1.4.
Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
3 of 5
Standard FAC-003-1 — Transmission Vegetation Management Program
M1.5. The Transmission Owner has a documented process for the immediate communication
of imminent threats by vegetation as identified in Requirement 1.5.
M2. The Transmission Owner has documentation that the Transmission Owner implemented the
work plan identified in Requirement 2.
M3. The Transmission Owner has documentation that it has supplied quarterly outage reports to
the RRO, or the RRO’s designee, as identified in Requirement 3.
M4. The RRO has documentation that it provided quarterly outage reports to NERC as identified in
Requirement 4.
D.
Compliance
1.
2.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
RRO
NERC
1.2.
Compliance Monitoring Period and Reset
One calendar Year
1.3.
Data Retention
Five Years
1.4.
Additional Compliance Information
The Transmission Owner shall demonstrate compliance through self-certification
submitted to the compliance monitor (RRO) annually that it meets the requirements of
NERC Reliability Standard FAC-003-1. The compliance monitor shall conduct an onsite audit every five years or more frequently as deemed appropriate by the compliance
monitor to review documentation related to Reliability Standard FAC-003-1. Field
audits of ROW vegetation conditions may be conducted if determined to be necessary
by the compliance monitor.
Levels of Non-Compliance
2.1.
Level 1:
2.1.1.
The TVMP was incomplete in one of the requirements specified in any
subpart of Requirement 1, or;
2.1.2.
Documentation of the annual work plan, as specified in Requirement 2, was
incomplete when presented to the Compliance Monitor during an on-site
audit, or;
2.1.3.
The RRO provided an outage report to NERC that was incomplete and did not
contain the information required in Requirement 4.
2.2. Level 2:
2.2.1.
The TVMP was incomplete in two of the requirements specified in any
subpart of Requirement 1, or;
2.2.2.
The Transmission Owner was unable to certify during its annual selfcertification that it fully implemented its annual work plan, or documented
deviations from, as specified in Requirement 2.
2.2.3.
The Transmission Owner reported one Category 2 transmission vegetationrelated outage in a calendar year.
Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
4 of 5
Standard FAC-003-1 — Transmission Vegetation Management Program
2.3. Level 3:
2.4.
E.
2.3.1.
The Transmission Owner reported one Category 1 or multiple Category 2
transmission vegetation-related outages in a calendar year, or;
2.3.2.
The Transmission Owner did not maintain a set of clearances (Clearance 2),
as defined in Requirement 1.2.2, to prevent flashover between vegetation
and overhead ungrounded supply conductors, or;
2.3.3.
The TVMP was incomplete in three of the requirements specified in any
subpart of Requirement 1.
Level 4:
2.4.1.
The Transmission Owner reported more than one Category 1 transmission
vegetation-related outage in a calendar year, or;
2.4.2.
The TVMP was incomplete in four or more of the requirements specified in
any subpart of Requirement 1.
Regional Differences
None Identified.
Version History
Version
Date
Action
Change Tracking
Version 1
TBA
1. Added “Standard Development
Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date: April
7, 2006” to footer.
4. Added “Draft 3: November 17, 2005” to
footer.
Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
5 of 5
Unofficial Comment Form for 5th Draft of FAC-003-2 Transmission
Vegetation Management —Project 2007-07 Vegetation Management
Please DO NOT use this form to submit comments. Please use the electronic form located at
the site below to submit comments on the 5th Draft of FAC-003-2 Transmission Vegetation
Management. Comments must be submitted by February 28, 2011.
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
If you have questions please contact Doug Keegan or by telephone at 404-446-2576.
Draft 5 Information
On November 4, 2010 NERC staff provided a Quality Review of FAC-003-2 to the Standards
Committee (SC). In November, 2010 the SC requested the VMSDT to work with NERC staff
in addressing the items identified in the Quality Review, and approved posting of the revised
documents. The SDT conducted several conference calls and acted in good faith to produce
this Draft 5 of FAC-003-2. The VMSDT considered the feedback provided in the Quality
Review by NERC staff and reached consensus in the following areas:
1. Elaborated upon the Purpose Statement to encompass more of the standard’s
content.
2. Added a Rationale text box to the 4.2 Facilities section, to explain the exclusion of
substation facilities. Clarified 4.2.4 by adding specific boundary details.
3. Updated Requirement R1 and R2 to emphasize the “planning” time horizon as the
applicable temporal context.
4. Elaborated upon the explanation in the Rationale text boxes for R1 and R2, to
highlight the range of non-compliant performance.
5. Re-organized the content of Requirement R3 for improved readability.
6. Augmented Requirement R5 to include a “reliability objective.”
7. Modified Requirement R6 and the associated VSLs for improved enforceability and for
consistency in the units of measure between the Requirement and the associated
VSLs.
8. Modified Requirement R7 and the associated VSLs for improved enforceability and for
consistency in the units of measure between the Requirement and the associated
VSLs.
9. Updated the Evidence Retention section in accordance with current guidelines.
Modification incorporated into this Draft 5 of FAC-003-2 in response to stakeholder
comments include:
A. Removed reference to Active Transmission Line ROW.
B. Redefined the Glossary term for ROW to address Paragraph 734 of FERC Order 693
addressing the width of ROW to be maintained.
C. Redefined the Glossary term for Vegetation Inspection to include identifying hazards
to the line inside the ROW.
D. Included the term referred to as “applicable lines” under 4.2 Facilities.
E. Removed 4.4 addressing “force majeure” under Applicability to Footnotes 2, 3 and 4.
F. In R1./R2 – M1/M2
• Added reference “into the MVCD” into the text.
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com
Unofficial Comment Form for 3rd Draft of FAC-003-2 — Project 2007-07 Vegetation
Management
•
G.
H.
I.
J.
K.
L.
M.
Eliminated “types of encroachment” and added “The four types of failure to
manage vegetation, in order of increasing severity.”
• In M1/M2 Added a paragraph defining “later confirmation of a Fault by the TO as
a real-time observation.”
• Added Footnote 2
• Added to the Rationale box types of failures to manage vegetation.
In R4. Changed “qualified personnel” to TO.
In R5. Added the term “is constrained from performing vegetation work” and
referenced MVCD.
• Removed reference to 2003 NE blackout from Rationale box
In R6. added the phrase “ but no more than 18 months between inspections” also
added Footnote 3.
In R7. Replaced major storms bullet with “circumstances that are beyond the control
of a Transmission Owner”. Added Footnote 4 to this requirement.
In Additional Compliance Information
• Category 2 was split into two parts recognizing IROL’s and Major WECC Transfer
Paths
• Added Category 3 for Fall-ins from outside the ROW.
• Category 4 was split into two parts recognizing IROL’s and Major WECC Transfer
Paths
Removed alternate versions of VSL’s for R1./R2.
Deleted Table 3 from the Guidelines and Technical Basis section
Background Information
The purpose of Project 2007-07 Vegetation Management is to:
•
Assist in providing an adequate level of reliability for the North American electric
Transmission System by verifying that the FAC-003-2 Transmission Vegetation
Management standard is complete and that its requirements are set at an
appropriate level to ensure reliability.
•
Incorporate other general improvements described in the Standard Review
Guidelines to bring FAC-003-2 Transmission Vegetation Management into
conformance with the latest version of the Reliability Standards Development
Procedure and the ERO Sanctions Guidelines.
•
Consider comments received from ERO regulatory authorities and stakeholders on
FAC-003-1 Transmission Vegetation Management as noted in the NERC Standards
Issues Database.
•
Satisfy the requirement for review of FAC-003-2 Transmission Vegetation
Management within five-year review cycle.
In addition, on January 14, 2010, the NERC Standards Committee endorsed the use of
Project 2007-07 Vegetation Management as the prototype for the proof-of-concept for using
the results-based criteria for developing a reliability standard. The results-based initiative is
intended to focus the collective effort of NERC and industry participants on improving the
clarity and quality of NERC reliability standards by developing performance-based, riskbased and competency-based requirements that accomplish a reliability objective through a
defense-in-depth strategy, while eliminating documentation-driven requirements that do not
have an impact on bulk power system reliability.
The Standards Committee also directed the standard drafting team for Project 2007-07
Vegetation Management to do so with a target for final industry ballot of draft FAC-003-2
Transmission Vegetation Management by August 31, 2010.
2
Unofficial Comment Form for 3rd Draft of FAC-003-2 — Project 2007-07 Vegetation
Management
The criteria for developing a results-based reliability standard include:
1. Strive to achieve a portfolio of performance-based, risk-based, and competencybased mandatory reliability requirements that provide an effective defense-in-depth
strategy for achieving an adequate level of reliability of the bulk power system.
a) Performance-based — defines a particular reliability objective or outcome
to be achieved. In its simplest form, a results-based requirement has four
components: who, under what conditions (if any), shall perform what action,
to achieve what particular result or outcome?
b) Risk-based — preventive requirements to reduce the risks of failure to
acceptable tolerance levels. A risk-based reliability requirement should be
framed as: who, under what conditions (if any), shall perform what action, to
achieve what particular result or outcome that reduces a stated risk to the
reliability of the bulk power system?
c) Competency-based — defines a minimum capability an entity needs to have
to demonstrate it is able to perform its designated reliability functions.
2. The defense-in-depth strategy for reliability standards development should recognize
that each requirement in a NERC reliability standard has a role in preventing system
failures, and that these roles are complementary and reinforcing. Reliability
standards should not be viewed as a body of unrelated requirements, but rather
should be viewed as part of a portfolio of requirements designed to achieve an
overall defense-in-depth strategy and comport with the quality objectives of a
reliability standard.
3. Each requirement should identify a clear and measurable expected outcome, such
as: i) a stated level of reliability performance, ii) a reduction in a specified reliability
risk, or iii) a necessary competency.
4. Strive to minimize prescriptive, administrative (document something), and
commercial requirements within the set of NERC reliability standards (i.e., these
types of requirements are permissible in standards but should be the exception
rather than the rule).
5. A requirement should not prescribe commercial business practices which do not
contribute directly to reliability.
The Vegetation Management Standard Drafting Team worked with Ivy Hooks of Compliance
Automation, Inc. to apply the “results-based” approach to developing requirements that are
clear and enforceable. Ivy is the CEO of Compliance Automation and has shared a wealth of
knowledge and expertise with the drafting team. The “look and feel” of the proposed
standard contains much more information than we have been including in previous
standards, thus the look and feel of the draft FAC-003-2 Transmission Vegetation
Management standard is quite different from the look of our existing standards. One of the
more obvious changes is the addition of information to aid end users in reading the
requirements from a common understanding of the standard’s objective and the rationale
for including each requirement. During the Three-year Performance Assessment,
stakeholders indicated that they wanted more information to assist in applying standards –
and the additional details provided in the proposed Vegetation Management standard
provide an example of one way to fill that void.
3
Unofficial Comment Form for 3rd Draft of FAC-003-2 — Project 2007-07 Vegetation
Management
On February 11, 2010 the Standards Committee authorized the standard drafting team for
Project 2007-07 Vegetation Management to take the following actions relative to the
development of draft FAC-003-2 Transmission Vegetation Management:
•
Discontinue work in developing a complete Consideration of Comments Report for
the comments received in response to the posting of the second draft of the draft
FAC-003-2 Transmission Vegetation Management standard that was posted in
August 2009; however, post the comments received along with a summary of the
actions taken by the team in response to those comments but without an individual
response to each comment provided.
•
Use informal comment periods to collect comments on future “drafts” of the
standard, post the comments received during the informal comment periods along
with a summary of how the team used the comments received and a redline version
of the standard showing the changes made based on the comments received.
•
Conduct a 45-day formal comment period in parallel with the formation of the ballot
pool and the initial ballot of the standard; post the comments from the formal
comment period as they are received for at least the first 30 days of the comment
period.
•
Use a standard template that is different from the template stipulated in the
Reliability Standard Development Procedure as provided by the Standards
Committee’s Process Subcommittee.
With respect to the first bullet above, that work was completed with the March 1, 2010
posting. With respect to the second bullet above, this current posting is the second informal
posting for comments, and the current plans are for the next posting to be a formal posting.
A summary of the SDT considerations for the responses to the March 1, 2010 submittal has
been posted on the NERC website in lieu of a full Consideration of Comments Report.
The following questions will assist the SDT in finalizing the development of FAC-003-2
Transmission Vegetation Management. For questions where you agree with indicated
statement, please state that you agree. If you disagree with the statement, please explain
why you disagree and provide a rationale, or alternate language, to support your position.
We would appreciate answers to as many of the following questions as possible.
1. The SDT proposes a revised NERC Glossary definition for Right-of-Way (ROW). This
revised definition will be used in lieu of the Active Transmission Line ROW. Do you
agree? If answer is no, please explain.
Yes
No
Comments:
2. In R1 and R2 and their associated VSLs, the SDT added the phrase “in order of
increasing severity” and added the sentence, “The types of encroachments are listed in
order of increasing degrees of severity in non-compliant performance as it relates to a
failure of a TO’s vegetation maintenance program.” to the Rationale boxes for R1/R2. Do
you agree? If answer is no, please explain.
Yes
4
Unofficial Comment Form for 3rd Draft of FAC-003-2 — Project 2007-07 Vegetation
Management
No
Comments:
3. In response to comments received regarding the term “investigation” in M1/M2, the SDT
substituted “confirmation…by the Transmission Owner...” in its place, among other
minor edits to these measures. Do you agree? If answer is no, please explain.
Yes
No
Comments:
4. In response to comments received that requirement R3 is unclear with respect to intent,
the SDT added “maintenance strategies.” Do you agree this clarifies the intent? If
answer is no, please offer alternative language.
Yes
No
Comments:
5. The SDT added clarifying language in M7 to explain how the annual work plan
percentage complete calculation is to be performed. Is this adequate? If no, please
provide improved examples.
Yes
No
Comments:
5
Transmission Vegetation Management
Standard FAC-003-2 Technical Reference
Prepared by the
North American Electric Reliability Corporation
Vegetation Management Standard Drafting Team
December 17, 2010
NERC Standard FAC-003-2 Technical Reference
Introduction
This document is intended to provide supplemental information and guidance for complying with
the requirements of Reliability Standard FAC-003-2.
The purpose of the Standard is to improve the reliability of the electric transmission system by
preventing those vegetation related outages that could lead to Cascading.
Compliance with the Standard is mandatory and enforceable.
FAC-003-2 Technical Reference
December 17, 2010
2
NERC Standard FAC-003-2 Technical Reference
Special Note: The Application of Results-Based
Approach to FAC-003-2
In its three-year assessment as the ERO, NERC acknowledged stakeholder comments and
committed to:
i) addressing quality issues to ensure each reliability standard has a clear statement of
purpose, and has outcome-focused requirements that are clear and measurable; and
ii) eliminating requirements that do not have an impact on bulk power system reliability.
In 2010, the Standards Committee approved a recommendation to use Project 2007-07
Vegetation Management as a first proof of concept for developing results-based standards.
The Standard Drafting Team (SDT) employed a defense-in-depth 1 strategy for FAC-003-2,
where each requirement has a role in preventing those vegetation related outages that could lead
to Cascading. This portfolio of requirements was designed to achieve an overall defense-indepth strategy and to comply with the quality objectives identified in the Acceptance Criteria of
a Reliability Standard document.
The SDT developed a portfolio of performance, risk, and competency-based mandatory
reliability requirements to support an effective defense-in-depth strategy. Each Requirement was
developed using one of the following requirement types:
a)
Performance-based - defines a particular reliability objective or outcome to be
achieved. In its simplest form, a results-based requirement has four components:
who, under what conditions (if any), shall perform what action, to achieve what
particular result or outcome?
b) Risk-based - preventive requirements to reduce the risks of failure to acceptable
tolerance levels. A risk-based reliability requirement should be framed as: who,
under what conditions (if any), shall perform what action, to achieve what particular
result or outcome that reduces a stated risk to the reliability of the bulk power
system?
c) Competency-based - defines a minimum set of capabilities an entity needs to have
to demonstrate it is able to perform its designated reliability functions. A
competency-based reliability requirement should be framed as: who, under what
conditions (if any), shall have what capability, to achieve what particular result or
outcome to perform an action to achieve a result or outcome or to reduce a risk to
the reliability of the bulk power system?
The drafting team reviewed and edited version 1 of FAC-003-1 to remove prescriptive
and administrative language in order to distill the technical requirements down to their
1
A defense-in-depth strategy for reliability standards recognizes that each requirement in the NERC standards has a
role in preventing system failures, and that these roles are complementary and reinforcing. These prevention
measures should be arranged in a series of defensive layers or walls. No single defensive layer provides complete
protection from failure by itself. But taken together, with well-designed layers including performance, risk, and
competency-based requirements, a defense-in-depth approach can be very effective in preventing future large scale
power system failures.
FAC-003-2 Technical Reference
December 17, 2010
3
NERC Standard FAC-003-2 Technical Reference
essential reliability content. Text that is explanatory in nature is placed in a special
section of the standard entitled Guideline and Technical Basis to aid in the understanding
of the requirements. Furthermore, Rationale text boxes are inserted alongside each
requirement to communicate the foundation for the requirement.
FAC-003-2 Technical Reference
December 17, 2010
4
NERC Standard FAC-003-2 Technical Reference
Disclaimer
This supporting document is supplemental to the reliability standard FAC-003-2 —
Transmission Vegetation Management and does not contain mandatory requirements subject to
compliance review.
FAC-003-2 Technical Reference
December 17, 2010
5
NERC Standard FAC-003-2 Technical Reference
Preface
The NERC Vegetation Management Standard Drafting Team (VM SDT) acknowledges those
across the industry who contributed to the development of this Standard and companion
Technical Reference document. The Technical Reference document is intended to provide
supplemental explanatory background and guidance related to requirements contained in the
Standard but does not in itself contain requirements subject to compliance review.
The VM SDT believes that a well-designed and executed Transmission Vegetation Management
Program (TVMP) will have few problems meeting the requirements of this Standard. While the
Standard requires a TVMP to contain certain elements, it allows the Transmission Owner
flexibility in designing a TVMP to meet local needs provided it also meets the purpose of the
Standard.
While there are many approaches to vegetation management, the VMSDT supports industry best
practices contained in ANSI A300 (Part 7) – Integrated Vegetation Management (IVM) practices
on Utility Rights-of-way, as well as the companion publication Best Management Practices –
Integrated Vegetation Management, as an effective strategy to maintain compliance with this
Standard. ANSI A300 (Part 7), approved by industry consensus in 2006, contains many elements
needed for an effective TVMP as required by this Standard. One key element is the “wire zone
– border zone” concept. Supported by over 50 years of continuous research, wire zone – border
zone is a proven method to manage vegetation on transmission rights-of-ways and is an industry
accepted best practice to help ensure electric system reliability.
The VM SDT believes that Transmission Owners who adopt and effectively implement IVM
principles, particularly the “wire zone – border zone” concept, are far less likely to experience a
vegetation caused outage than those who do not.
FAC-003-2 Technical Reference
December 17, 2010
6
NERC Standard FAC-003-2 Technical Reference
Definition of Terms
Right-of-Way (ROW)*
The corridor of land under a transmission line(s)
The current glossary definition of this NERC
needed to operate the line(s). The width of the
term is modified to address the issues set forth
corridor is established by engineering or
in Paragraph 734 of FERC Order 693.
construction standards as documented in either
construction documents, pre-2007 vegetation
maintenance records, or by the blowout standard in effect when the line was built. The ROW
width in no case exceeds the Transmission Owner’s legal rights but may be less based on the
aforementioned criteria.
The current NERC glossary definition of Right of Way has been modified to address the matter
set forth in Paragraph 734 of FERC Order 693. The Order pointed out that Transmission Owners
may in some cases own more property or rights than are needed to reliably operate transmission
lines. This modified definition represents a slight but significant departure from the strict legal
definition of “right of way” in that this definition is based on engineering and construction
considerations that establish the width of a corridor from a technical basis.
Vegetation Inspection*
The systematic examination of vegetation conditions
on a Right-of-Way and those vegetation conditions
under the Transmission Owner’s control that are
likely to pose a hazard to the line(s) prior to the
next planned maintenance or inspection. This may
be combined with a general line inspection.
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
The inspection includes the identification of any
vegetation that may pose a threat to reliability prior
to the next planned maintenance or inspection work, considering the current location of the
conductor and other possible locations of the conductor due to sag and sway for rated conditions.
This definition allows both maintenance inspections and vegetation inspections to be performed
concurrently.
FAC-003-2 Technical Reference
December 17, 2010
7
NERC Standard FAC-003-2 Technical Reference
* This is a modification to a defined term in the NERC glossary and will be incorporated into the
NERC glossary of terms with final approval of this standard revision
FAC-003-2 Technical Reference
December 17, 2010
8
NERC Standard FAC-003-2 Technical Reference
Applicability of the Standard
4. Applicability
4.1. Functional Entities:
Transmission Owners
4.2. Facilities: Defined below (referred to as “applicable lines”), including but not
limited to those that cross lands owned by federal 1, state, provincial, public,
private, or tribal entities:
4.2.1 Overhead transmission lines operated at 200kV or higher.
4.2.2 Overhead transmission lines operated below 200kV having been identified
as included in the definition of an Interconnection Reliability Operating
Limit (IROL) under NERC Standard FAC 014 by the Planning Coordinator.
4.2.3 Overhead transmission lines operated below 200 kV having been identified
as included in the definition of one of the Major WECC Transfer Paths in
the Bulk Electric System.
4.2.4 This standard applies to
Rationale
overhead transmission lines
-The areas excluded in 4.2.4 were excluded based
on comments from industry for reasons summarized
identified above (4.2.1
as follows: 1) There is a very low risk from
through 4.2.3) located outside
vegetation in this area. Based on an informal
the fenced area of the
survey, no TOs reported such an event. 2)
switchyard, station or
Substations, switchyards, and stations have many
substation and any portion of
inspection and maintenance activities that are
the span of the transmission
necessary for reliability. Those existing process
line that is crossing the
manage the threat. As such, the formal steps in this
substation fence.
standard are not well suited for this environment. 3)
4.3. Enforcement: The reliability
obligations of the applicable entities
and facilities are contained within
the technical requirements of this
standard. [Straw proposal]
The standard was written for Transmission Owners.
Rolling the excluded areas into this standard will
bring GO and DP into the standard, even though
NERC has an initiative in place to address this
bigger registry issue. 4) Specifically addressing the
areas where the standard applies or doesn’t makes
the standard stronger as it relates to clarity.
In Order 693, FERC discussed the 200 kV bright-line test of applicability. While FERC did not
change the 200 kV bright line, the Commission remained concerned that there may be some
transmission lines operating at lesser voltages that could have significant impact on the Bulk
Electric System that should therefore be subject to this standard.
NERC Standard FAC-014 has the stated purpose, “To ensure that System Operating Limits
(SOLs) used in the reliable planning and operation of the Bulk Electric System (BES) are
determined based on an established methodology or methodologies.” FAC-014 requires
Reliability Coordinators, Planning Coordinators, and Transmission Planners to have a
methodology to identify all lines that might comprise an IROL. Thus, these entities would
identify sub-200 kV lines that qualify as part of an IROL and should be subject to FAC-003-2.
1
EPAct 2005 section 1211c: “Access approvals by Federal agencies”.
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Although all three entities may prepare the list of elements, FAC-003-2 presently does not
specify that it is the list from the Planning Coordinator that should be used by Transmission
Owners for FAC-003. However, the Time Horizon needed to plan vegetation management work
does not lend itself to the operating horizon of a Reliability Coordinator. Additionally, the
Planning Coordinator has a wider-area view than the Transmission Planner and could thus
identify any elements of importance to a sub-set of its area that might be missed by a
Transmission Planner.
Transmission Owners, who do not already get the list of circuits included in the definition of an
IROL, can get them from the Planning Coordinator. Specifically R5 of FAC-014 specifies that
“The Reliability Coordinator, Planning Authority (Coordinator) and Transmission Planner
shall each provide its SOLs and IROLs to those entities that have a reliability-related need for
those limits and provide a written request that includes a schedule for delivery of those limits”
Vegetation-related Sustained Outages that occur due to natural disasters are beyond the control
of the Transmission Owner. These events are not classified as vegetation-related Sustained
Outages and are therefore exempt from the Standard. Transmission lines are not designed to
withstand the impacts of natural disasters such as flood, drought, earthquake, major storms, fire,
hurricane, tornado, landslides, ice storms, etc. In the aftermath of catastrophic system damage
from natural disasters the Transmission Owner’s focus is on electric system restoration for public
safety and critical support infrastructure.
Sustained Outages due to human or animal activity are beyond the control of the Transmission
Owner. These outages are not classified as vegetation-related Sustained Outages and are
therefore exempt from the Standard. Examples of these events may include new plantings by
outside parties of tall vegetation under the transmission line planted since the last Vegetation
Inspection, tree contacts with line initiated by vehicles, logging activities, etc.
The foregoing exemptions are addressed in a new footnote 2. Referred to collectively as force
majeure events and activities, this footnote applies to requirements R1 and R2 in FAC-003-2.
The reliability objective of this NERC Vegetation Management Standard (“Standard”) is to
prevent vegetation-related outages which could lead to Cascading by effective vegetation
maintenance while recognizing that certain outages such as those due to vandalism, human errors
and acts of nature are not preventable. Operating experience clearly indicates that trees that have
grown out of specification could contribute to a cascading grid failure, especially under heavy
electrical loading conditions.
Serious outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations. To
properly reduce and manage this risk, it is necessary to apply the Standard to applicable lines on
any kind of land or easement, whether they are Federal Lands, state or provincial lands, public or
private lands, franchises, easements or lands owned in fee. For the purposes of the Standard and
this Technical Reference document, the term “public lands” includes municipal lands, village
lands, city lands, and land owned by a host of other governmental entities.
The Standard addresses vegetation management along applicable overhead lines that serve to
connect one electric station to another. However, it is not intended to be applied to lines sections
inside the electric station fence or other boundary of an electric station, submarine or
underground lines.
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The Standard is intended to reduce the risk of Cascading involving vegetation. It is not intended
to prevent customer outages from occurring due to tree contact with all transmission lines and
voltages. For example, localized customer service might be disrupted if vegetation were to make
contact with a 69kV transmission line supplying power to a 12kV distribution station. However,
this Standard is not written to address such isolated situations which have little impact on the
overall Bulk Electric System.
Vegetation growth is constant and always present. Unmanaged vegetation poses an increased
outage risk when numerous transmission lines are operating at or near their Rating. This poses a
significant risk of multiple line failures and Cascading. On the other hand, most other outage
causes (such as trees falling into lines, lightning, animals, motor vehicles, etc.) are statistically
intermittent. The probability of occurrence of these events is not dependent on heavy loads.
There is no cause-effect relationship which creates the probability of simultaneous occurrence of
other such events. Therefore these types of events are highly unlikely to cause large-scale grid
failures.
In preparing the original vegetation management standard in 2005, industry stakeholders set the
threshold for applicability of the standard at 200kV. This was because an unexpected loss of
lines operating at above 200kV has a higher probability of initiating a widespread blackout or
cascading outages compared with lines operating at less than 200kV.
The original NERC Standard FAC-003-1 also allowed for application of the standard to
“critical” circuits (critical from the perspective of initiating widespread blackouts or cascading
outages) operating below 200kV. While the percentage of these circuits is relatively low, it
remains a fact that there are sub-200kV circuits whose loss could contribute to a widespread
outage. Given the very limited exposure and unlikelihood of a major event related to these lowervoltage lines, it would be an imprudent use of resources to apply the Standard to all sub-200kV
lines. The drafting team, after evaluating several alternatives, selected the IROL and WECC
Major Transfer Path criteria to determine applicable lines below 200 kV that are subject to this
standard.
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Requirements R1 and R2
R1.
Each Transmission Owner shall manage
Rationale
vegetation to prevent encroachments of
Rationale
the types shown below, into the Minimum
The MVCD is a calculated minimum
Vegetation Clearance Distance (MVCD)
distance stated in feet (meters) to prevent
of any of its applicable line(s) identified
flash-over between conductors and
as an element of an Interconnection
vegetation, for various altitudes and
Reliability Operating Limit (IROL) in the
operating voltages. The distances in Table 2
planning horizon by the Planning
were derived using a proven transmission
Coordinator; or Major Western
design method. The types of failure to
Electricity Coordinating Council
manage vegetation are listed in order of
(WECC) transfer path(s); operating
increasing degrees of severity in nonwithin its Rating and all Rated Electrical
compliant performance as it relates to a
Operating Conditions. 2
failure of a TO’s vegetation maintenance
1. An encroachment into the MVCD as
program since the encroachments listed
shown in FAC-003-Table 2, observed
require different and increasing levels of
in Real-time, absent a Sustained
skills and knowledge and thus constitute a
Outage,
logical progression of how well, or poorly,
2. An encroachment due to a fall-in from
a TO manages vegetation relative to this
inside the Right-of-Way (ROW) that
Requirement.
caused a vegetation-related Sustained
Outage,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage,
4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage.
[VRF – High] [Time Horizon – Real-time]
R2. Each Transmission Owner shall manage vegetation to prevent encroachments of the types
shown below, into the MVCD of any of its applicable line(s) that is not an element of an
IROL; or Major WECC transfer path; operating within its Rating and all Rated Electrical
Operating Conditions.Error! Bookmark not defined.
1. An encroachment into the MVCD as shown in FAC-003-Table 2, observed in Real-time,
absent a Sustained Outage,
2. An encroachment due to a fall-in from inside the ROW that caused a vegetation-related
Sustained Outage,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage,
2
This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to
this reliability standard, including natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, wind
shear, fresh gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice
storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree,
arboricultural activities or horticultural or agricultural activities, or removal or digging of vegetation. Nothing in this
footnote should be construed to limit the Transmission Owner’s right to exercise its full legal rights on the ROW.
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4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage.
[VRF – Medium] [Time Horizon – Real-time]
M1. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-time observations of any MVCD encroachments.
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation
encroachment within the MVCD has occurred from vegetation within the ROW, this
shall be considered the equivalent of a Real-time observation.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. (R1)
M2. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R2. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-time observations of any MVCD encroachments.
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation
encroachment within the MVCD has occurred from vegetation within the ROW, this
shall be considered the equivalent of a Real-time observation.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. (R2)
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the prevention of vegetation encroachments within a minimum distance of
transmission lines. Content-wise, R1 and R2 are the same requirements; however, they apply to
different Facilities. Both R1 and R2 require each Transmission Owner to manage vegetation to
prevent encroachment within the Minimum Vegetation Clearance Distance (“MVCD”) of
transmission lines. R1 is applicable to lines “identified as an element of an Interconnection
Reliability Operating Limit (IROL) or Major Western Electricity Coordinating Council (WECC)
transfer path (operating within Rating and Rated Electrical Operating Conditions) to avoid a
Sustained Outage”. R2 applies to all other applicable lines that are not an element of an IROL or
Major WECC Transfer Path.
The separation of applicability (between R1 and R2) recognizes that an encroachment into the
MVCD of an IROL or Major WECC Transfer Path transmission line is a greater risk to the
electric transmission system. Applicable lines that are not an element of an IROL or Major
WECC Transfer Path are required to be clear of vegetation but these lines are comparatively less
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operationally significant. As a reflection of this difference in risk impact, the Violation Risk
Factors (VRFs) are assigned as High for R1 and Medium for R2.
These requirements (R1 and R2) state that if vegetation encroaches within the distances in Table
1 in Appendix 1 of this supplemental Transmission Vegetation Management Standard FAC-0032 Technical Reference document, it is in violation of the standard. Table 2 tabulates the distances
necessary to prevent spark-over based on the Gallet equations as described more fully in
Appendix 1 below.
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating
(potentially in violation of other standards), the occurrence of a clearance encroachment may
occur. For example, emergency actions taken by a Transmission Operator or Reliability
Coordinator to protect an Interconnection may cause the transmission line to sag more and come
closer to vegetation, potentially causing an outage. Such vegetation-related outages are not a
violation of these requirements.
Evidence of violation of Requirement R1 and R2 include real-time observation of a vegetation
encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related encroachment
resulting in a Sustained Outage due to a fall-in from inside the ROW, or a vegetation-related
encroachment resulting in a Sustained Outage due to blowing together of applicable lines and
vegetation located inside the ROW, or a vegetation-related encroachment resulting in a Sustained
Outage due to a grow-in. If an investigation of a Fault by a Transmission Owner confirms that a
vegetation encroachment within the MVCD occurred, then it shall be considered the equivalent
of a Real-time observation.
With this approach, the VSLs were defined such that they directly correlate to the severity of a
failure of a Transmission Owner to manage vegetation and to the corresponding performance
level of the Transmission Owner’s vegetation program’s ability to meet the goal of “preventing a
Sustained Outage that could lead to Cascading.” Thus violation severity increases with a
Transmission Owner’s inability to meet this goal and its potential of leading to a Cascading
event. The additional benefits of such a combination are that it simplifies the standard and clearly
defines performance for compliance. A performance-based requirement of this nature will
promote high quality, cost effective vegetation management programs that will deliver the
overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For
example, a limb may only partially break and intermittently contact a conductor. Such events are
considered to be a single vegetation-related Sustained Outage under the Standard where the
Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will prevent transmission outages.
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Requirement R3
Rationale
The documentation provides a basis for
evaluating the competency of the
Transmission Owner’s vegetation program.
There may be many acceptable approaches to
maintain clearances. Any approach must
demonstrate that the Transmission Owner
avoids vegetation-to-wire conflicts under all
Rated Electrical Operating Conditions. See
Figure 1 for an illustration of possible
conductor locations.
R3. Each Transmission Owner shall have
documented maintenance strategies or
procedures or processes or specifications
it uses to prevent the encroachment of
vegetation into the MVCD of its applicable
transmission lines that include(s) the
following:
3.1 Accounts for the movement of
applicable transmission line
conductors under their Facility Rating
and all Rated Electrical Operating
Conditions;
3.2 Accounts for the inter-relationships between vegetation growth
rates, vegetation control methods, and inspection frequency.
[VRF – Lower] [Time Horizon – Long Term Planning]
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the Transmission Owner can prevent encroachment into the
MVCD considering the factors identified in the requirement. (R3)
Requirement R3 is a competency based requirement concerned with the maintenance strategies,
procedures, processes, or specifications, a Transmission Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the
Transmission Owner uses to plan and perform vegetation work to prevent transmission Sustained
Outages and minimize risk to the Transmission System. The approach provides the basis for
evaluating the intent, allocation of appropriate resources and the competency of the Transmission
Owner in managing vegetation. There are many acceptable approaches to manage vegetation
and avoid Sustained Outages. However, the Transmission Owner must be able to state what its
approach is and how it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach a
Transmission Owner chooses to use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the Transmission Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing as a reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
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NERC Standard FAC-003-2 Technical Reference
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figures 2 and 3 below.
Conductor Dynamics
In order for a Transmission Owner to develop a specific maintenance approach, it is important to
understand the dynamics of a line conductor’s movement. This paper will first address the
complexities inherent in observing and predicting conductor movement, particularly for field
personnel. It will then present some examples of maintenance approaches which Transmission
Owners may consider that take into account these complexities, while resulting in practical
approaches for field personnel.
Additionally, it is important the Transmission Owner consider all conductor locations, the
MVCD, and vegetation growth between maintenance activities when developing a maintenance
approach.
Understanding Conductor Position and Movement
The conductor’s position in space at any point in time is continuously changing as a reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading.
As a consequence of these loading variables, the conductor’s position in space is dynamic and
moving. When calculating the range of conductor positions, the Transmission Owner should use
the same design criteria and assumptions that the Transmission Owner uses when establishing
Ratings and SOL, as described in other standards. Typically, the greatest conductor movement
would be at mid-span. As the conductor moves through various positions, a spark-over zone
surrounding the conductor moves with it. The radius of the spark-over zone may be found by
referring to Table 1 (“Minimum Vegetation Clearance Distances”) in the standard. For
illustrations of this zone and conductor movements, Figures 1 through 3 below demonstrate
these concepts. At the time of making a field observation, however, it is very difficult to
precisely know where the conductor is in relation to its wide range of all possible positions.
Therefore, Transmission Owners must adopt maintenance approaches that account for this
dynamic situation.
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Figure 1
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NERC Standard FAC-003-2 Technical Reference
Figure 2
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Cross-Section View of a Single Conductor
At a Given Point Along The Span
Showing Six Possible Conductor Positions Due to Movement
Resulting From Thermal and Mechanical Loading
For Consideration in Developing a Maintenance Approach
Figure 3
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NERC Standard FAC-003-2 Technical Reference
Selecting a Maintenance Approach
In order to maintain adequate separation between vegetation and transmission line conductors,
the Transmission Owner must craft a maintenance strategy that keeps vegetation well away from
the spark-over zone mentioned above. In fact, it is generally necessary to incorporate a variety of
maintenance strategies. For example, one Transmission Owner may utilize a combination of
routine cycles, traditional IVM techniques and long-term planning. Another Transmission Owner
may place a higher reliance on frequent inspections and quick remediation as opposed to a
cyclical approach. This variation of approaches is further warranted when factors, such as
terrain, legal and other constraints, vegetation types, and climates, are considered in developing a
Transmission Owner’s specific approach to satisfying this requirement.
The following is a sample description of one combination of strategies which may be utilized by
a Transmission Owner. A Transmission Owner’s basic maintenance approach could be to
remove all incompatible vegetation from the right of way if it has the right to do so and has no
constraints. In mountainous terrain, however, this strategy could change to one where the
Transmission Owner manages vegetation based on vegetation-to-conductor clearances, since it
might not be necessary to remove vegetation in a valley that is far below.
If faced with constraints and assuming a line design with sufficient ground clearance, the
Transmission Owner ’s approach could then be to allow vegetation such as fruit trees, but
perhaps only up to a given height at maturity (perhaps 10 feet from the ground). If constraints
cannot be overcome and if design clearances are sufficient, an exception to the Transmission
Owner’s 10-foot guideline might be made. Finally, if the Transmission Owner has chosen to
utilize vegetation-to-conductor clearance distance methods, the Transmission Owner could have
an inspection regimen in place to regularly ensure that any impending clearance problems are
identified early for rectification.
ANSI A300 – Best Management Practices for Tree Care Operations
A description of ANSI A-300, part 7, is offered below to illustrate another maintenance approach
that could be used in developing a comprehensive transmission vegetation management program.
Introduction
Integrated Vegetation Management (IVM) is a best management practice conveyed in the
American National Standard for Tree Care Operations, Part 7 (ANSI 2006) and the International
Society of Arboriculture Best Management Practices: Integrated Vegetation Management
(Miller 2007). IVM is consistent with the requirements in FAC-003-02, and it provides
practitioners with what industry experts consider to be appropriate techniques to apply to electric
right-of-way projects in order to meet or exceed the Standard.
IVM is a system of managing plant communities whereby managers set objectives; identify
compatible and incompatible vegetation; consider action thresholds; and evaluate, select and
implement the most appropriate control method or methods to achieve set objectives. The choice
of control method or methods should be based on the environmental impact and anticipated
effectiveness; along with site characteristics, security, economics, current land use and other
factors.
Planning and Implementation
Best management practices provide a systematic way of planning and implementing a vegetation
management program. While designed primarily with transmission systems in mind, it is also
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applicable to distribution projects. As presented in ANSI A300 part 7 and the ISA best
management practices, IVM consists of 6 elements:
1)
2)
3)
4)
5)
6)
Set Objectives
Evaluate the Site
Define Action Thresholds
Evaluate and Select Control Methods
Implement IVM
Monitor Treatment and Quality Assurance
The setting of objectives, defining action thresholds, and evaluating and selecting control
methods all require decisions. The planning and implementation process is cyclical and
continuous, because vegetation is dynamic and managers must have the flexibility to adjust their
plans. Adjustments may be made at each stage as new information becomes available and
circumstances evolve.
Set Objectives
Objectives should be clearly defined and documented. Examples of objectives can
include promoting safety, preventing sustained outages caused by vegetation growing
into electric facilities, maintaining regulatory compliance, protecting structures and
security, restoring electric service during emergencies, maintaining access and clear lines
of sight, protecting the environment, and facilitating cost effectiveness.
Objectives should be based on site factors, such as workload and vegetation type, in
addition to human, equipment and financial resources. They will vary from utility to
utility and project to project, depending on line voltage and criticality, as well as
topographical, environmental, fiscal and political considerations. However, where it is
appropriate, the overriding focus should be on environmentally-sound, cost effective
control of species that potentially conflict with the electric facility, while promoting
compatible, early successional, sustainable plant communities.
Work Load Evaluations
Work-load evaluations are inventories of vegetation that could have a bearing on
management objectives. Work load assessments can capture a variety of vegetation
characteristics, such as location, height, species, size and condition, hazard status, density
and clearance from conductors. Assessments should be conducted considering voltage,
conductor sag from ambient temperatures and loading, and the potential influence of
wind on line sway.
Evaluate and Select Control Methods
Control methods are the process through which managers achieve objectives. The most
suitable control method best achieves management objectives at a particular site. Many
cases call for a combination of methods. Managers have a variety of controls from which
to choose, including manual, mechanical, herbicide and tree growth regulators,
biological, and cultural options.
Manual Control Methods
Manual methods employ workers with hand-carried tools, including chainsaws,
handsaws, pruning shears and other devices to control incompatible vegetation. The
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advantage of manual techniques is that they are selective and can be used where others
may not be. On the other hand, manual techniques can be inefficient and expensive
compared to other methods.
Mechanical Control Methods
Mechanical controls are done with machines. They are efficient and cost effective,
particularly for clearing dense vegetation during initial establishment, or reclaiming
neglected or overgrown right of way. On the other hand, mechanical control methods can
be non-selective and disturb sensitive sites.
Tree Growth Regulator and Herbicide Control Methods
Tree growth regulators and herbicides can be effective for vegetation management. Tree
growth regulators (TGRs) are designed to reduce growth rates by interfering with natural
plant processes. TGRs can be helpful where removals are prohibited or impractical by
reducing the growth rates of some fast-growing species.
Herbicides control plants by interfering with specific botanical biochemical pathways.
Herbicide use can control individual plants that are prone to re-sprout or sucker after
removal. When trees that re-sprout or sucker are removed without herbicide treatment,
dense thickets develop, impeding access, swelling workloads, increasing costs, blocking
lines-of-site, and deteriorating wildlife habitat. Treating suckering plants allows early
successional, compatible species to dominate the right-of-way and out-compete
incompatible species, ultimately reducing work.
Cultural Control Methods
Cultural methods modify habitat to discourage incompatible vegetation and establish and
manage desirable, early successional plant communities. Cultural methods take
advantage of seed banks of native, compatible species lying dormant on site. In the long
run, cultural control is the most desirable method where it is applicable.
A cultural control known as cover-type conversion provides a competitive advantage to
short-growing, early successional plants, allowing them to thrive and eventually outcompete unwanted tree species for sunlight, essential elements and water. The early
successional plant community is relatively stable, tree-resistant and reduces the amount
of work, including herbicide application, with each successive treatment.
Wire-Border Zone
The wire-border zone technique is a management philosophy that can be applied through
cultural control. W.C. Bramble and W.R. Byrnes developed it in the mid-1980s out of
research begun in 1952 on a transmission right-of-way in the Pennsylvania State Game
Lands 33 Research and Demonstration project (Yahner and Hutnik (2004).
The wire zone is the section of a utility transmission right-of-way directly under the wires
and extending outward about 10 feet on each side. The wire zone is managed to promote
a low-growing plant community dominated by grasses, herbs and small shrubs (under 3
feet in height at maturity). The border zone is the remainder of the right-of-way. It is
managed to establish small trees and tall shrubs (under 25 feet in height at maturity).
When properly managed, diverse, tree-resistant plant communities develop in wire and
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border zones. The communities not only protect the electric facility and reduce long-term
maintenance, but also enhance wildlife habitat, forest ecology and aesthetic values.
Although the wire-border zone is a best practice in many instances, it is not necessarily
universally suitable. For example, standard wire-border zone prescriptions may be
unnecessary where lines are high off the ground, such as across low valleys or canyons,
so the technique can be modified without sacrificing reliability.
One way to accommodate variances in topography is to establish different regions based
on wire height. For example, over canyon bottoms or other areas where conductors are
100 feet or more above the ground, only a few trees are likely to be tall enough to conflict
with the lines. In those cases, trees that potentially interfere with the transmission lines
can be removed selectively on a case-by-case basis.
In areas where the wire is lower, perhaps between 50-100 feet from the ground, a border
zone community can be developed throughout the right-of-way. Note that in many cases,
conductor attachment points are more than 50 feet off the ground, so a border zone
community can be cultivated near structures. Where the line is less than 50 feet off the
ground, managers could apply a full wire-border zone prescription.
An environmental advantage of this type of modification is stream protection. Streams
often course through the valleys and canyons where lines are likely to be elevated.
Leaving timber or border zone communities in canyon bottoms helps shelter this valuable
habitat, enabling managers to achieve environmentally sensitive objectives.
Implement IVM
All laws and regulations governing IVM practices and specifications written by qualified
vegetation managers must be followed. Integrated vegetation management control
methods should be implemented on regular work schedules, which are based on
established objectives and completed assessments. Work should progress systematically,
using control measures determined to be best for varying conditions at specific locations
along a right-of-way. Some considerations used in developing schedules include the
importance and type of line, vegetation clearances, work loads, growth rate of predominant
vegetation, geography, accessibility, and in some cases, time lapsed since the last scheduled
work.
Clearances Following Work
Clearances following work should be sufficient to meet management objectives,
including preventing trees from entering the Minimum Vegetation Clearance Distance,
electric safety risks, service-reliability threats and cost.
Monitor Treatment and Quality Assurance
An effective program includes documented processes to evaluate results. Evaluations
can involve quality assurance while work is underway and after it is completed.
Monitoring for quality assurance should begin early to correct any possible
miscommunication or misunderstanding on the part of crewmembers. Early and
consistent observation and evaluation also provides an opportunity to modify the plan, if
need be, in time for a successful outcome.
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Utility vegetation management programs should have systems and procedures in place
for documenting and verifying that vegetation management work was completed to
specifications. Post-control reviews can be comprehensive or based on a statistically
representative sample. This final review points back to the first step and the planning
process begins again.
Summary of A-300 example
Integrated Vegetation Management offers among others, a systematic way of planning and
implementing a vegetation management program as presented in ANSI A300 Part 7. This
methodology enables a program to comply with the NERC Transmission Vegetation
Management Program standard (FAC-003-2). Managers should select control options to best
promote management objectives.
Vegetation Inspections
As with the ANSI A-300 example, The Transmission Owner’s transmission vegetation
management program (TVMP) establishes the frequency of vegetation inspections based upon
many factors. Such local and environmental factors may include anticipated growth rates of the
local vegetation, length of the growing season for the geographical area, limited Rights of Way
width, rainfall amounts, etc.
Annual Work Plan
Requirement R7 of the Standard addresses the execution of the annual work plan. A
comprehensive approach that exercises the full extent of legal rights is superior to incremental
management in the long term because it reduces overall encroachments, and it ensures that future
planned work and future planned inspection cycles are sufficient at all locations on the Right of
Way. Removal is superior to pruning. Removal minimizes the possibility of conflicts between
energized conductors and vegetation. Since this is not always possible, the Transmission
Owner’s approach should be to use its prescribed vegetation maintenance methods to work
towards or achieve the maximum use of the Right of Way.
FAC-003-2 Technical Reference
December 17, 2010
24
NERC Standard FAC-003-2 Technical Reference
Requirement R4
R4. Each Transmission Owner, without any
intentional time delay, shall notify the
control center holding switching
authority for the associated applicable
transmission line when the Transmission
Owner has confirmed the existence of a
vegetation condition that is likely to
cause a Fault at any moment.
Rationale
To ensure expeditious communication
between the Transmission Owner and the
control center when a critical situation is
confirmed.
[VRF – Medium] [Time Horizon – Real-time]
M4. Each Transmission Owner that has a confirmed vegetation condition likely to cause a Fault
at any moment will have evidence that it notified the control center holding switching
authority for the associated transmission line without any intentional time delay. Examples
of evidence may include control center logs, voice recordings, switching orders, clearance
orders and subsequent work orders. (R4)
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the
Transmission Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4
involves the notification of potentially threatening vegetation conditions, without any intentional
delay, to the control center holding switching authority for that specific transmission line.
Examples of acceptable unintentional delays may include communication system problems (for
example, cellular service or two-way radio disabled), crews located in remote field locations
with no communication access, delays due to severe weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of a Transmission Owner’s employee who personally identifies such a threat in the
field. Confirmation could also be made by sending out an employee to evaluate a situation
reported by a landowner.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an assessment
of the possible sag or movement of the conductor while operating between no-load conditions
and its rating.
The Transmission Owner has the responsibility to ensure the proper communication between
field personnel and the control center to allow the control center to take the appropriate action
until the vegetation threat is relieved. Appropriate actions may include a temporary reduction in
the line loading, switching the line out of service, or positioning the system in recognition of the
increasing risk of outage on that circuit. The notification of the threat should be communicated in
terms of minutes or hours as opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some Transmission Owners may have a danger tree identification
FAC-003-2 Technical Reference
December 17, 2010
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NERC Standard FAC-003-2 Technical Reference
program that identifies trees for removal with the potential to fall near the line. These trees
would not require notification to the control center unless they pose an immediate fall-in threat.
FAC-003-2 Technical Reference
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NERC Standard FAC-003-2 Technical Reference
Requirement R5
R5.
When a Transmission Owner is
constrained from performing vegetation
work, and the constraint may lead to a
vegetation encroachment into the MVCD
of its applicable transmission lines prior
to the implementation of the next annual
work plan then the Transmission Owner
shall take corrective action to ensure
continued vegetation management to
prevent encroachments. [VRF – Medium]
[Time Horizon – Operations Planning]
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
Transmission Owner from performing
planned vegetation maintenance work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the Transmission Owner to put interim
measures in place, rather than do nothing.
The corrective action process is not intended
to address situations where a planned work
methodology cannot be performed but an
alternate work methodology can be used.
M5. Each Transmission Owner has evidence
of the corrective action taken for each
constraint where an applicable
transmission line was put at potential risk. Examples of acceptable forms of evidence may
include initially-planned work orders, documentation of constraints from landowners,
court orders, inspection records of increased monitoring, documentation of the de-rating
of lines, revised work orders, invoices, and evidence that a line was de-energized. (R5)
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
Transmission Owner for the mitigation of Sustained Outage risk when temporarily constrained
from performing vegetation maintenance. The intent of this requirement is to deal with situations
that prevent the Transmission Owner from performing planned vegetation management work
and, as a result, have the potential to put the transmission line at risk. Constraints to performing
vegetation maintenance work as planned could result from legal injunctions filed by property
owners, the discovery of easement stipulations which limit the Transmission Owner’s rights, or
other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
Transmission Owner is not under any immediate time constraint for achieving the management
objective, can easily reschedule work using an alternate approach, and therefore does not need to
take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the Transmission Owner is required to take an interim corrective action to mitigate the potential
risk to the transmission line. A wide range of actions can be taken to address various situations.
General considerations include:
FAC-003-2 Technical Reference
December 17, 2010
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NERC Standard FAC-003-2 Technical Reference
•
•
•
•
•
Identifying locations where the Transmission Owner is constrained from performing
planned vegetation maintenance work which potentially leaves the transmission line
at risk.
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for each location.
In developing the specific action to mitigate the potential risk to the transmission line
the Transmission Owner could consider location specific measures such as modifying
the inspection and/or maintenance intervals. Where a legal constraint would not allow
any vegetation work, the interim corrective action could include limiting the loading
on the transmission line.
The Transmission Owner should document and track the specific corrective action
taken at each location. This location may be indicated as one span, one tree or a
combination of spans on one property where the constraint is considered to be
temporary.
FAC-003-2 Technical Reference
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NERC Standard FAC-003-2 Technical Reference
Requirement R6
R6. Each Transmission Owner shall perform a
Vegetation Inspection of 100% of its
applicable transmission lines (measured
in units of choice - circuit, pole line, line
miles or kilometers, etc.) at least once per
calendar year and with no more than 18
months between inspections on the same
ROW. 3
[VRF – Medium] [Time Horizon –
Operations Planning]
Rationale
Inspections are used by Transmission Owners
to assess the condition of the entire ROW. The
information from the assessment can be used to
determine risk, determine future work and
evaluate recently-completed work. This
requirement sets a minimum Vegetation
Inspection frequency of once per calendar year
but with no more than 18 months between
inspections on the same ROW. Based upon
average growth rates across North America
and on common utility practice, this minimum
frequency is reasonable. Transmission Owners
should consider local and environmental
factors that could warrant more frequent
inspections.
M6. Each Transmission Owner has evidence
that it conducted Vegetation Inspections of
the transmission line ROW for all
applicable transmission lines at least once
per calendar year but with no more than
18 months between inspections on the same ROW. Examples of acceptable forms of
evidence may include completed and dated work orders, dated invoices, or dated
inspection records. (R6)
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections that fits general industry practice. In addition, the fact that Vegetation
Inspections can be performed in conjunction with general line inspections further facilitates a
Transmission Owner’s ability to meet this requirement. However, the Transmission Owner may
determine that more frequent inspections are needed to maintain reliability levels, dependent
upon such factors as anticipated growth rates of the local vegetation, length of the growing
season for the geographical area, limited ROW width, and rainfall amounts. Therefore it is
expected that some transmission lines may be designated with a higher frequency of inspections.
The SDT added footnote 3 to address the situation where a Transmission Owner through no fault
of its own, would be unable to complete the vegetation inspection within the allotted time period.
This would include the situation of mutual aid as well as disasters to the Transmission Owner’s
own system.
The VSL for Requirement R6 has VSL categories ranked by the percentage of the required ROW
inspections completed. To calculate the percentage of inspection completion, the Transmission
Owner may choose units such as: line miles or kilometers, circuit miles or kilometers, pole line
miles, ROW miles, etc.
3
When the Transmission Owner is prevented from performing a Vegetation Inspection within the timeframe in R6
due to a natural disaster, the TO is granted a time extension that is equivalent to the duration of the time the TO was
prevented from performing the Vegetation Inspection.
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NERC Standard FAC-003-2 Technical Reference
For example, when a Transmission Owner operates 2,000 miles of 230 kV transmission lines this
Transmission Owner will be responsible for inspecting all 2,000 miles of 230 kV transmission
lines at least once during the calendar year. If one of the included lines was 100 miles long, and
if it was not inspected during the year, then the amount failed to inspect would be 100/2000 =
0.05 or 5%. The “Low VSL” for R6 would apply in this example.
FAC-003-2 Technical Reference
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NERC Standard FAC-003-2 Technical Reference
Requirement R7
R7. Each Transmission Owner shall complete
Rationale
100% of its annual vegetation work plan
This requirement sets the expectation that the
to ensure no vegetation encroachments
work identified in the annual work plan will
occur within the MVCD. Modifications to
be completed as planned. An annual
the work plan in response to changing
vegetation work plan allows for work to be
conditions or to findings from vegetation
modified for changing conditions, taking into
inspections may be made (provided they
consideration anticipated growth of
do not put the transmission system at risk
vegetation and all other environmental
of a vegetation encroachment) and must
factors, provided that the changes do not
be documented. The percent completed
violate the encroachment within the MVCD.
calculation is based on the number of
units actually completed divided by the
number of units in the final amended plan (measured in units of choice - circuit, pole line,
line miles or kilometers, etc.) Examples of reasons for modification to annual plan may
include:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of a Transmission Owner 4
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
[VRF – Medium] [Time Horizon – Operations Planning]
M7. Each Transmission Owner has evidence that it completed its annual vegetation work plan.
Examples of acceptable forms of evidence may include a copy of the completed annual
work plan (including modifications if any), dated work orders, dated invoices, or dated
inspection records. (R7)
R7 is a risk-based requirement. The Transmission Owner is required to implement an annual
work plan for vegetation management to accomplish the purpose of this Standard. Modifications
to the work plan in response to changing conditions or to findings from vegetation inspections
may be made and documented provided they do not put the transmission system at risk. The
annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a
“line-by-line” detailed description of all work to be performed. It is only intended to require that
the Transmission Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation into
the MVCD.
4
circumstances that are beyond the control of a Transmission Owner include but are not limited to natural disasters
such as earthquakes, fires, tornados, hurricanes, landslides, major storms as defined either by the TO or an
applicable regulatory body, ice storms, and floods; arboricultural, horticultural or agricultural activities.
FAC-003-2 Technical Reference
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NERC Standard FAC-003-2 Technical Reference
The ability to modify the work plan allows the Transmission Owner to change priorities or
treatment methodologies during the year as conditions or situations dictate. For example recent
line inspections may identify unanticipated high priority work, weather conditions (drought)
could make herbicide application ineffective during the plan year, or a major storm could require
redirecting local resources away from planned maintenance or work may be deferred to a
subsequent year because of slower-than-expected growth. This situation may also include
complying with mutual assistance agreements by moving resources off the Transmission
Owner’s system to work on another system. Any of these examples could result in acceptable
deferrals or additions to the annual work plan. Modifications to the annual work plan must
always ensure the reliability of the electric Transmission system.
In general, the vegetation management maintenance approach should use the full extent of the
Transmission Owner’s legal rights on the ROW. A comprehensive approach that exercises the
full extent of legal rights on the ROW is superior to incremental management in the long term
because it reduces the overall potential for encroachments, and it ensures that future planned
work and future planned inspection cycles are sufficient.
When developing the annual work plan, the Transmission Owner should allow time for
reasonable and predictable procedural requirements to obtain permits to work on federal, state,
provincial, public, tribal lands. In some cases, the lead time for obtaining permits may
necessitate preparing work plans more than a year prior to the start of work. Transmission
Owners may also need to consider those special landowner requirements.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the Transmission
Owner, evidence of successful annual work plan execution could consist of signed-off work
orders, signed contracts, printouts from work management systems, spreadsheets of planned
versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence
may include photographs and walk-through reports.
FAC-003-2 Technical Reference
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NERC Standard FAC-003-2 Technical Reference
Appendix 1: Clearance Distance Derivation by the
Gallet Equation
The Gallet Equation is a well-known method of computing the required strike distance for proper
insulation coordination, and has the ability to take into account various air gap geometries, as
well as non-standard atmospheric conditions. When the Gallet Equation and conservative
probabilistic methods are combined, i.e. deterministic design, sparkover probabilities of 10-6 or
less are achieved. This approach is well known for its conservatism and was used to design the
first 500 kV and 765 kV lines in North America [1]. Thus, the deterministic design approach
using the Gallet Equation is used for the standard to compute the minimum strike distance
between transmission lines and the vegetation that may be present in or along the transmission
corridor.
Method Explanation (Gallet Equation)
In 1975 G. Gallet published a benchmark paper that provided a method to compute the critical
flashover voltage (CFO) of various air gap geometries [4]. The Gallet Equation uses various
“gap factors” to take into account various air gap geometries. Various gap factor values are
provided in [1]. If the vegetation in a transmission corridor, e.g. a tree, is assumed electrically to
be a large structure then the CFO of such an air gap geometry can be computed for dry or wet
conditions using a well established equation proposed by Gallet [1],[2],[4],
CFOA = k w ⋅ k g ⋅ δ m ⋅
3400
8
1+
D
(1)
where,
kw
is defined as the factor that takes into account wet or dry conditions (dry = 1.0
and wet = 0.96) and phase arrangement (multiply by 1.08 for outside phase), e.g.
outside phase and wet conditions = (0.96)(1.08) = 1.037,
kg
is defined as the gap factor (1.3 for conductor to large structure),
D
is the strike distance (m),
CFOA
is the CFO for the relative air density (kV).
δ
is defined as the relative air density and is approximately equal to (2) where A is
the altitude in km,
δ =e
A
8.6
(2)
=
m 1.25G0 ( G0 − 0.2 )
(3)
CFOs
500 ⋅ D
(4)
G0 =
FAC-003-2 Technical Reference
December 17, 2010
−
33
NERC Standard FAC-003-2 Technical Reference
CFOs = k w ⋅ k g ⋅
3400
8
1+
D
(5)
where CFOS is the CFO for standard atmospheric conditions (kV). Using (1)-(5), the required CFOA can be
computed using an iterative process.
Once the CFOA is known, deterministic methods can be used to determine the required clearance
distance. If we let the maximum switching overvoltage be equal to the withstand voltage of the
air gap (CFOA - 3σ) then the CFOA can be written as (6).
Vm
σ
1− 3
CFOA
CFOA =
(6)
where
Vm is equal to the maximum switching overvoltage, i.e. the value that has a 0.135% chance of being
exceeded,
σ is the standard deviation of the air gap insulation,
CFOA is the critical flashover voltage of the air gap insulation under non-standard atmospheric conditions.
The ratio of σ to the CFOA given in (6) can be assumed to be 0.05 (5%) [1]. Thus, (6) can be
written as (7).
CFOA =
Vm
0.85
(7)
Substituting (7) into (1) we arrive at (8).
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ m ⋅
3400
8
1+
D
(8)
Equation 8 relates the maximum transient overvoltage, Vm, to the air gap distance, D. Using (8)
to compute the required clearance distance for the specified air gap geometry (conductor to large
structure) results in a probability of flashover in the range of 10-6.
TRANSIENT OVERVOLTAGE
In general, the worst case transient overvoltages occurring on a transmission line are caused by
energizing or re-energizing the line with the latter being the extreme case if trapped charge is
present. The intent of FAC-003 is to keep a transmission line that is in service from becoming
de-energized (i.e. tripped out) due to sparkover from the line conductor to nearby vegetation.
Thus, the worst case scenarios that are typically analyzed for insulation coordination purposes
(e.g. line energization and re-energization) can be ignored. For the purposes of FAC-003-2, the
worst case transient overvoltage then becomes the maximum value that can occur with the line
energized. Determining a realistic value of transient overvoltage for this situation is difficult
because the maximum transient overvoltage factors listed in the literature are based on a
FAC-003-2 Technical Reference
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NERC Standard FAC-003-2 Technical Reference
switching operation of the line in question. In other words, these maximum overvoltage values
(e.g. the values listed in [2], [3] and [5]) are based on the assumption that the subject line is being
energized, re-energized or de-energized. These operations, by their very nature, will create the
largest transient overvoltages. Typical values of transient overvoltages of in-service lines, as
such, are not readily available in the literature because the resulting level of overvoltage is
negligible compared with the maximum (e.g. re-energizing a transmission line with trapped
charge). A conservative value for the maximum transient overvoltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 p.u.[2]. This value is a
conservative estimate of the transient overvoltage that is created at the point of application (e.g. a
substation) by switching a capacitor bank without a pre-insertion device (e.g. closing resistors).
At voltage levels where capacitor banks are not very common (e.g. 362 kV), the maximum
transient overvoltage of an “in-service” ac line are created by fault initiation on adjacent ac lines
and shunt reactor bank switching. These transient voltages are usually 1.5 p.u. or less [2]. It is
well known that these theoretical transient overvoltages will not be experienced at locations
remote from the bus at which they were created; however, in order to be conservative, it will be
assumed that all nearby ac lines are subjected to this same level of overvoltage. Thus, a
maximum transient overvoltage factor of 2.0 p.u. for 242 kV and below and 1.4 p.u. for ac
transmission lines 362 kV and above is used to compute the required clearance distances for
vegetation management purposes.
The overvoltage characteristics of dc transmission lines vary somewhat from their ac
counterparts. The referenced empirically derived transient overvoltage factor used to calculate
the minimum clearance distances from dc transmission lines to vegetation for the purpose of
FAC-003-2 will be 1.8 p.u.[3].
EXAMPLE CALCULATION
An example calculation is presented below using the proposed method of computing the
vegetation clearance distances. It is assumed that the line in question has a maximum operating
voltage of 550 kVrms line-to-line. Using a per unit transient overvoltage factor of 1.4, the result
is a peak transient voltage of 629 kVcrest. It is further assumed that the line in question operates
at a maximum altitude of 7000 feet (2.134 km) above sea level.
The required withstand voltage of the air gap must be equal to or greater than 629 kVcrest. Since
the altitude is above sea level, (1) - (5) have to be iterated on to achieve the desired result.
Equation (9) can be used as an initial guess for the clearance distance.
Di =
8
3400 ⋅ k w ⋅ k g
Vm
0.85
(9)
−1
For our case here, Vm is equal to 629 kV, kw = 1.037 and kg = 1.3. Thus,
Di =
8
3400 ⋅ k w ⋅ k g
Vm
0.85
FAC-003-2 Technical Reference
December 17, 2010
=
−1
8
= 1.535m
3400 ⋅ 1.037 ⋅ 1.3
−1
629
0.85
(10)
35
NERC Standard FAC-003-2 Technical Reference
Using (2)-(5) and (8) the withstand voltage of the air gap is next computed. This value will then
be compared to the maximum transient overvoltage.
CFOS = k w ⋅ k g ⋅
−
3400
3400
= 1.037 ⋅ 1.3 ⋅
= 737.7 kV
8
8
1+
1+
1.535
D
A
−
2.134
8.6
8.6
=
δ e=
e =
0.78
GO =
(12)
CFOS
737.7
=
= 0.961
500 ⋅ D (500 ) ⋅ (1.535 )
(13)
m = 1.25 ⋅ GO (GO − 0.2 ) = 1.25 ⋅ 0.961(0.961 − 0.2 ) = 0.915
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ
m
(11)
3400
3400
0.915
⋅
= (0.85 )(1.037 )(1.3 )(0.78 )
8
8
1
1+
+
D
1.535
(14)
= 499.8 kV
(15)
The calculated Vm is less than 629 kV; thus, the clearance distance must be increased. A few
iterations using (2)-(5) and (8) are required until the computed Vm ≥ 629 kV. For this case it was
found that D = 1.978 m (6.49 feet) yielded Vm = 629.3 kV. Using this clearance distance the
following values were computed for the final iteration.
CFOS = k w ⋅ k g ⋅
−
3400
3400
= 1.037 ⋅ 1.3 ⋅
= 908.5 kV
8
8
1+
1+
D
1.978
A
−
2.134
8.6
8.6
=
δ e=
e =
0.78
GO =
(17)
CFOS
908.5
=
= 0.919
500 ⋅ D (500 ) ⋅ (1.978 )
(18)
m = 1.25 ⋅ GO (GO − 0.2 ) = 1.25 ⋅ 0.919(0.919 − 0.2 ) = 0.825
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ m ⋅
(16)
3400
3400
= (0.85 )(1.037 )(1.3)(0.78 )0.825
8
8
1
1+
+
D
1.978
(19)
= 629.3kV
(20)
Therefore, the minimum vegetation clearance distance for a maximum line to line ac operating
voltage of 550 kV at 7000 feet above sea level is 1.978 m (6.49 feet). Table 1 provides
calculated distances for various altitudes and maximum system operating ac voltages.
FAC-003-2 Technical Reference
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NERC Standard FAC-003-2 Technical Reference
TABLE 1 — Minimum Vegetation Clearance Distances (MVCD) 6
For Alternating Current Voltages
( AC )
Nominal
System
Voltage
(kV)
( AC )
Maximum
System
Voltage
(kV)
765
800
500
550
345
362
230
242
161*
169
138*
145
115*
121
88*
100
69*
72
MVCD
feet
(meters)
sea level
8.06ft
(2.46m)
5.06ft
(1.54m)
3.12ft
(0.95m)
2.97ft
(0.91m)
2ft
(0.61m)
1.7ft
(0.52m)
1.41ft
(0.43m)
1.15ft
(0.35m)
0.82ft
(0.25m)
MVCD
feet
(meters)
3,000ft
(914.4m)
MVCD
feet
(meters)
4,000ft
(1219.2m)
MVCD
feet
(meters)
5,000ft
(1524m)
MVCD
feet
(meters)
6,000ft
(1828.8m)
8.89ft
(2.71m)
5.66ft
(1.73m)
3.53ft
(1.08m)
3.36ft
(1.02m)
2.28ft
(0.69m)
1.94ft
(0.59m)
1.61ft
(0.49m)
1.32ft
(0.40m)
0.94ft
(0.29m)
9.17ft
(2.80m)
5.86ft
(1.79m)
3.67ft
(1.12m)
3.49ft
(1.06m)
2.38ft
(0.73m)
2.03ft
(0.62m)
1.68ft
(0.51m)
1.38ft
(0.42m)
0.99ft
(0.30m)
9.45ft
(2.88m)
6.07ft
(1.85m)
3.82ft
(1.16m)
3.63ft
(1.11m)
2.48ft
(0.76m)
2.12ft
(0.65m)
1.75ft
(0.53m)
1.44ft
(0.44m)
1.03ft
(0.31m)
9.73ft
(2.97m)
6.28ft
(1.91m)
3.97ft
(1.21m)
3.78ft
(1.15m)
2.58ft
(0.79m)
2.21ft
(0.67m)
1.83ft
(0.56m)
1.5ft
(0.46m)
1.08ft
(0.33m)
MVCD
feet
(meters)
7,000ft
(2133.6m)
MVCD
feet
(meters)
8,000ft
(2438.4m)
MVCD
feet
(meters)
9,000ft
(2743.2m)
MVCD
feet
(meters)
10,000ft
(3048m)
MVCD
feet
(meters)
11,000ft
(3352.8m)
10.01ft
(3.05m)
6.49ft
(1.98m)
4.12ft
(1.26m)
3.92ft
(1.19m)
2.69ft
(0.82m)
2.3ft
(0.70m)
1.91ft
(0.58m)
1.57ft
(0.48m)
1.13ft
(0.34m)
10.29ft
(3.14m)
6.7ft
(2.04m)
4.27ft
(1.30m)
4.07ft
(1.24m)
2.8ft
(0.85m)
2.4ft
(0.73m)
1.99ft
(0.61m)
1.64ft
(0.50m)
1.18ft
(0.36m)
10.57ft
(3.22m)
6.92ft
(2.11m)
4.43ft
(1.35m)
4.22ft
(1.29m)
2.91ft
(0.89m)
2.49ft
(0.76m)
2.07ft
(0.63m)
1.71ft
(0.52m)
1.23ft
(0.37m)
10.85ft
(3.31m)
7.13ft
(2.17m)
4.58ft
(1.40m)
4.37ft
(1.33m)
3.03ft
(0.92m)
2.59ft
(0.79m)
2.16ft
(0.66m)
1.78ft
(0.54m)
1.28ft
(0.39m)
11.13ft
(3.39m)
7.35ft
(2.24m)
4.74ft
(1.44m)
4.53ft
(1.38m)
3.14ft
(0.96m)
2.7ft
(0.82m)
2.25ft
(0.69m)
1.86ft
(0.57m)
1.34ft
(0.41m)
* Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above).
6
The distances in this Table are the minimums required to prevent Flashover; however prudent vegetation maintenance practices dictate that substantially greater distances
will be achieved at time of vegetation maintenance.
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NERC Standard FAC-003-2 Technical Reference
TABLE 1 (CONT.) — Minimum Vegetation Clearance Distances (MVCD)
For Direct Current Voltages
sea level
MVCD feet
(meters)
3,000ft
(914.4m)
Alt.
MVCD feet
(meters)
4,000ft
(1219.2m)
Alt.
MVCD feet
(meters)
5,000ft
(1524m)
Alt.
MVCD feet
(meters)
6,000ft
(1828.8m)
Alt.
MVCD
feet
(meters)
7,000ft
(2133.6m)
Alt.
MVCD
feet
(meters)
(8,000ft
(2438.4m)
Alt.
MVCD
feet
(meters)
9,000ft
(2743.2m)
Alt.
MVCD
feet
(meters)
10,000ft
(3048m)
Alt.
MVCD
feet
(meters)
11,000ft
(3352.8m)
Alt.
±750
13.92ft
(4.24m)
15.07ft
(4.59m)
15.45ft
(4.71m)
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.9ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
±600
10.07ft
(3.07m)
11.04ft
(3.36m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
(13.54ft
4.13m)
±500
7.89ft
(2.40m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
±400
4.78ft
(1.46m)
5.35ft
(1.63m)
5.55ft
(1.69m)
5.75ft
(1.75m)
5.95ft
(1.81m)
6.15ft
(1.87m)
6.36ft
(1.94m)
6.57ft
(2.00m)
6.77ft
(2.06m)
6.98ft
(2.13m)
±250
3.43ft
(1.05m)
4.02ft
(1.23m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5ft
(1.52m)
5.17ft
(1.58m)
( DC )
Nominal Pole
to Ground
Voltage
(kV)
MVCD feet
(meters)
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NERC Standard FAC-003-2 Technical Reference
List of Acronyms and Abbreviations
ANSI
American National Standards Institute
IEEE
Institute of Electrical and Electronics Engineers
IVM
Integrated Vegetation Management
NERC
North American Electric Reliability Corporation
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NERC Standard FAC-003-2 Technical Reference
References
Andrew Hileman, Insulation Coordination for Power System, Marcel Dekker, New York, NY
1999
EPRI, EPRI Transmission Line Reference Book 345 kV and Above, Electric Power Research
Council, Palo Alto, Ca. 1975.
IEEE Std. 516-2003 IEEE Guide for Maintenance Methods on Energized Power Lines
G. Gallet, G. Leroy, R. Lacey, I. Kromer, General Expression for Positive Switching Impulse
Strength Valid Up to Extra Long Air Gaps, IEEE Transactions on Power Apparatus and
Systems, Vol. pAS-94, No. 6, Nov./Dec. 1975.
IEEE Std. 1313.2-1999 (R2005) IEEE Guide for the Application of Insulation Coordination.
2007 National Electric Safety Code
EPRI, HVDC Transmission Line Reference Book, EPRI TR-102764 , Project 2472-03, Final
Report, September 1993
ANSI. 2001. American National Standard for Tree Care Operations – Tree, Shrub, and Other
Plant Maintenance – Standard Practices (Pruning). Part 1. American National Standards
Institute, NY
ANSI. 2006. American National Standard for Tree Care Operations – Tree, Shrub, and Other
Plant Maintenance – Standard Practices (Integrated Vegetation Management a. Electric
Utility Rights-of-way). Part 7. American National Standards Institute, NY.
Cieslewicz, S. and R. Novembri. 2004. Utility Vegetation Management Final Report. Federal
Energy Regulatory Commission. Commissioned to support the Federal Investigation of the
August 14, 2003 Northeast Blackout. Federal Energy Regulatory Commission, Washington,
DC. pg. 39.
Kempter, G.P. 2004. Best Management Practices: Utility Pruning of Trees. International
Society of Arboriculture, Champaign, IL
Miller, R.H. 2007. Best Management Practices: Integrated Vegetation Management. Society of
Arboriculture, Champaign, IL.
Yahner, R.H. and R.J. Hutnik. 2004. Integrated Vegetation Management on an electric
transmission right-of-way in Pennsylvania, U.S. Journal of Arboriculture. 30:295-300
Results-based Initiative Ad Hoc Group. Acceptance Criteria of a Reliability Standard.
FAC-003-2 Technical Reference
December 17, 2010
40
Transmission Vegetation Management
Standard FAC-003-2 Technical Reference
Prepared by the
North American Electric Reliability Corporation
Vegetation Management Standard Drafting Team
June 28December 17, 2010
NERC Standard FAC-003-2 Technical Reference
Table of Contents
INTRODUCTION ..................................................................................................................................................................... 3
SPECIAL NOTE: THE APPLICATION OF RESULTS-BASED APPROACH TO FAC-003-2 ...................................... 4
DISCLAIMER ........................................................................................................................................................................... 6
PREFACE .................................................................................................................................................................................. 7
APPLICABILITY OF THE STANDARD............................................................................................................................... 9
ACTIVE TRANSMISSION LINE ROW ................................................................................................................................. 11
REQUIREMENTS R1 AND R2 ............................................................................................................................................. 16
REQUIREMENT R3 ............................................................................................................................................................... 19
ANSI A300 – BEST MANAGEMENT PRACTICES FOR TREE CARE OPERATIONS ............................................................. 24
REQUIREMENT R4 ............................................................................................................................................................... 30
REQUIREMENT R5 ............................................................................................................................................................... 32
REQUIREMENT R6 ............................................................................................................................................................... 34
REQUIREMENT R7 ............................................................................................................................................................... 35
APPENDIX 1: CLEARANCE DISTANCE DERIVATION BY THE GALLET EQUATION ....................................... 37
LIST OF ACRONYMS AND ABBREVIATIONS ............................................................................................................... 44
REFERENCES ........................................................................................................................................................................ 45
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NERC Standard FAC-003-2 Technical Reference
Introduction
This document is intended to provide supplemental information and guidance for complying with
the requirements of Reliability Standard FAC-003-2.
The purpose of the Standard is to improve the reliability of the electric transmission system by
preventing those vegetation related outages that could lead to Cascading.
Compliance with the Standard is mandatory and enforceable.
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NERC Standard FAC-003-2 Technical Reference
Special Note: The Application of Results-Based
Approach to FAC-003-2
In its three-year assessment as the ERO, NERC acknowledged stakeholder comments and
committed to:
i) addressing quality issues to ensure each reliability standard has a clear statement of
purpose, and has outcome-focused requirements that are clear and measurable; and
ii) eliminating requirements that do not have an impact on bulk power system reliability.
In 2010, the Standards Committee approved a recommendation to use Project 2007-07
Vegetation Management as a first proof of concept for developing results-based standards.
The Standard Drafting Team (SDT) employed a defense-in-depth 1 strategy for FAC-003-2,
where each requirement has a role in preventing those vegetation related outages that could lead
to Cascading. This portfolio of requirements was designed to achieve an overall defense-indepth strategy and to comply with the quality objectives identified in the Acceptance Criteria of
a Reliability Standard document.
The SDT developed a portfolio of performance, risk, and competency-based mandatory
reliability requirements to support an effective defense-in-depth strategy. Each Requirement was
developed using one of the following requirement types:
a)
Performance-based - defines a particular reliability objective or outcome to be
achieved. In its simplest form, a results-based requirement has four components:
who, under what conditions (if any), shall perform what action, to achieve what
particular result or outcome?
b) Risk-based - preventive requirements to reduce the risks of failure to acceptable
tolerance levels. A risk-based reliability requirement should be framed as: who,
under what conditions (if any), shall perform what action, to achieve what particular
result or outcome that reduces a stated risk to the reliability of the bulk power
system?
c) Competency-based - defines a minimum set of capabilities an entity needs to have
to demonstrate it is able to perform its designated reliability functions. A
competency-based reliability requirement should be framed as: who, under what
conditions (if any), shall have what capability, to achieve what particular result or
outcome to perform an action to achieve a result or outcome or to reduce a risk to
the reliability of the bulk power system?
The drafting team reviewed and edited version 1 of FAC-003-1 to remove prescriptive
and administrative language in order to distill the technical requirements down to their
1
A defense-in-depth strategy for reliability standards recognizes that each requirement in the NERC standards has a
role in preventing system failures, and that these roles are complementary and reinforcing. These prevention
measures should be arranged in a series of defensive layers or walls. No single defensive layer provides complete
protection from failure by itself. But taken together, with well-designed layers including performance, risk, and
competency-based requirements, a defense-in-depth approach can be very effective in preventing future large scale
power system failures.
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NERC Standard FAC-003-2 Technical Reference
essential reliability content. Text that is explanatory in nature is placed in a special
section of the standard entitled Guideline and Technical Basis to aid in the understanding
of the requirements. Furthermore, Rationale text boxes are inserted alongside each
requirement to communicate the foundation for the requirement.
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NERC Standard FAC-003-2 Technical Reference
Disclaimer
This supporting document is supplemental to the reliability standard FAC-003-2 —
Transmission Vegetation Management and does not contain mandatory requirements subject to
compliance review.
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NERC Standard FAC-003-2 Technical Reference
Preface
The NERC Vegetation Management Standard Drafting Team (VM SDT) acknowledges those
across the industry who contributed to the development of this Standard and companion
Technical Reference document. The Technical Reference document is intended to provide
supplemental explanatory background and guidance related to requirements contained in the
Standard but does not in itself contain requirements subject to compliance review.
The VM SDT believes that a well-designed and executed Transmission Vegetation Management
Program (TVMP) will have few problems meeting the requirements of this Standard. While the
Standard requires a TVMP to contain certain elements, it allows the Transmission Owner
flexibility in designing a TVMP to meet local needs provided it also meets the purpose of the
Standard.
While there are many approaches to vegetation management, the VMSDT supports industry best
practices contained in ANSI A300 (Part 7) – Integrated Vegetation Management (IVM) practices
on Utility Rights-of-way, as well as the companion publication Best Management Practices –
Integrated Vegetation Management, as an effective strategy to maintain compliance with this
Standard. ANSI A300 (Part 7), approved by industry consensus in 2006, contains many elements
needed for an effective TVMP as required by this Standard. One key element is the “wire zone
– border zone” concept. Supported by over 50 years of continuous research, wire zone – border
zone is a proven method to manage vegetation on transmission rights-of-ways and is an industry
accepted best practice to help ensure electric system reliability.
The VM SDT believes that Transmission Owners who adopt and effectively implement IVM
principles, particularly the “wire zone – border zone” concept, are far less likely to experience a
vegetation caused outage than those who do not.
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NERC Standard FAC-003-2 Technical Reference
Definition of Terms
Right-of-Way (ROW)*
The corridor of land under a transmission line(s)
The current glossary definition of this NERC
needed to operate the line(s). The width of the
term is modified to address the issues set forth
corridor is established by engineering or
in Paragraph 734 of FERC Order 693.
construction standards as documented in either
construction documents, pre-2007 vegetation
maintenance records, or by the blowout standard in effect when the line was built. The ROW
width in no case exceeds the Transmission Owner’s legal rights but may be less based on the
aforementioned criteria.
The current NERC glossary definition of Right of Way has been modified to address the matter
set forth in Paragraph 734 of FERC Order 693. The Order pointed out that Transmission Owners
may in some cases own more property or rights than are needed to reliably operate transmission
lines. This modified definition represents a slight but significant departure from the strict legal
definition of “right of way” in that this definition is based on engineering and construction
considerations that establish the width of a corridor from a technical basis.
Vegetation Inspection** — *
The systematic examination of vegetation conditions
on an Active Transmission Line Right-of-Way
whicha Right-of-Way and those vegetation
conditions under the Transmission Owner’s control
that are likely to pose a hazard to the line(s) prior
to the next planned maintenance or inspection. This
may be combined with a general line inspection.
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
The inspection includes the identification of any
vegetation that may pose a threat to reliability prior to the next planned inspection or
maintenance or inspection work, considering the current location of the conductor and other
possible locations of the conductor due to sag and sway for rated conditions.
This definition allows both maintenance inspections and vegetation inspections to be performed
concurrently.
*To
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NERC Standard FAC-003-2 Technical Reference
* This is a modification to a defined term in the NERC glossary and will be added toincorporated
into the NERC glossary of terms with final approval of this standard revision
** This is a modification to a defined term in the NERC glossary.
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NERC Standard FAC-003-2 Technical Reference
Applicability of the Standard
4. Applicability
4.1. Functional Entities:
Transmission Owners
4.2. Facilities: Defined below, (referred to as “applicable lines”), including but not
limited to those that cross lands owned by federal 1, state, provincial, public,
private, or tribal entities:
4.2.1 Overhead transmission lines operated at 200kV or higher.
4.2.2 Overhead transmission lines operated below 200kV having been identified
as included in the definition of an Interconnection Reliability Operating
Limit (IROL) under NERC Standard FAC 014 by the Planning Coordinator.
4.2.3 Overhead transmission lines operated below 200 kV having been identified
as included in the definition of one of the Major WECC Transfer Paths in
the Bulk Electric System.
4.2.4 This standard does not
Rationale
applyapplies to
-The areas excluded in 4.2.4 were excluded based
on comments from industry for reasons summarized
Facilitiesoverhead
as follows: 1) There is a very low risk from
transmission lines identified
vegetation in this area. Based on an informal
above (4.2.1 through 4.2.3)
survey, no TOs reported such an event. 2)
located inoutside the fenced
Substations, switchyards, and stations have many
area of athe switchyard,
inspection and maintenance activities that are
station or substation. and
necessary for reliability. Those existing process
any portion of the span of the
manage the threat. As such, the formal steps in this
transmission line that is
standard are not well suited for this environment. 3)
crossing the substation fence.
The standard was written for Transmission Owners.
4.3. Enforcement: The reliability
obligations of the applicable entities
and facilities are contained within
the technical requirements of this
standard. [Straw proposal]
Rolling the excluded areas into this standard will
bring GO and DP into the standard, even though
NERC has an initiative in place to address this
bigger registry issue. 4) Specifically addressing the
areas where the standard applies or doesn’t makes
the standard stronger as it relates to clarity.
4.4. Other:
This Standard does not apply to any occurrence, non-occurrence, or other set of
circumstances that are beyond the control of a Transmission Owner subject to this
reliability standard, including acts of God, flood, drought, earthquake, major
storms, fire, hurricane, tornado, landslides, ice storms, vehicle contact with tree,
human activity involving: removal of, installation of, or digging around vegetation,
animals severing trees, lightning, epidemic, strike, war, riot, civil disturbance,
sabotage, vandalism, terrorism, wind shear, or fresh gale (or higher wind speed)
that restricts or prevents performance to comply with this reliability standard’s
1
EPAct 2005 section 1211c: “Access approvals by Federal agencies”.
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NERC Standard FAC-003-2 Technical Reference
requirements. Nothing in this section should be construed to limit the Transmission
Owner’s right to exercise its full legal rights on the Active Transmission Line ROW.
In Order 693, FERC discussed the 200 kV bright-line test of applicability. While FERC did not
change the 200 kV bright -line, the Commission remained concerned that there may be some
transmission lines operating at lesser voltages that could have significant impact on the Bulk
Electric System that should therefore be subject to this standard.
NERC Standard FAC-014 has the stated purpose, “To ensure that System Operating Limits
(SOLs) used in the reliable planning and operation of the Bulk Electric System (BES) are
determined based on an established methodology or methodologies.” FAC-014 requires
Reliability Coordinators, Planning Coordinators, and Transmission Planners to have a
methodology to identify all lines that might comprise an IROL. Thus, these entities would
identify sub-200 kV lines that qualify as part of an IROL and should be subject to FAC-003-2.
Although all three entities may prepare the list of elements, FAC-003-2 presently does not
specify that it is the list from the Planning Coordinator that should be used by Transmission
Owners for FAC-003. However, the Time Horizon needed to plan vegetation management work
does not lend itself to the operating horizon of a Reliability Coordinator. Additionally, the
Planning Coordinator has a wider-area view than the Transmission Planner and could thus
identify any elements of importance to a sub-set of its area that might be missed by a
Transmission Planner.
Transmission Owners, who do not already get the list of circuits included in the definition of an
IROL, can get them from the Planning Coordinator. Specifically R5 of FAC-014 specifies that
“The Reliability Coordinator, Planning Authority (Coordinator) and Transmission Planner
shall each provide its SOLs and IROLs to those entities that have a reliability-related need for
those limits and provide a written request that includes a schedule for delivery of those limits”
Vegetation-related Sustained Outages that occur due to natural disasters are beyond the control
of the Transmission Owner. These events are not classified as vegetation-related Sustained
Outages and are therefore exempt from the Standard. Transmission lines are not designed to
withstand the impacts of natural disasters such as flood, drought, earthquake, major storms, fire,
hurricane, tornado, landslides, ice storms, etc. In the aftermath of catastrophic system damage
from natural disasters the Transmission Owner’s focus is on electric system restoration for public
safety and critical support infrastructure.
Sustained Outages due to human or animal activity are beyond the control of the Transmission
Owner. These outages are not classified as vegetation-related Sustained Outages and are
therefore exempt from the Standard. Examples of these events may include new plantings by
outside parties of tall vegetation under the transmission line planted since the last Vegetation
Inspection, tree contacts with line initiated by vehicles, logging activities, etc.
The foregoing exemptions are addressed in a new subsection, 4.4 Other, of the Applicability
section.footnote 2. Referred to collectively as force majeure events and activities, this
sectionfootnote applies to all requirements R1 and R2 in FAC-003-2.
The reliability objective of this NERC Vegetation Management Standard (“Standard”) is to
prevent vegetation-related outages which could lead to Cascading by effective vegetation
maintenance while recognizing that certain outages such as those due to vandalism, human errors
and acts of nature are not preventable. Operating experience clearly indicates that trees that have
FAC-003-2 Technical Reference
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NERC Standard FAC-003-2 Technical Reference
grown out of specification could contribute to a cascading grid failure, especially under heavy
electrical loading conditions.
Serious outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations. To
properly reduce and manage this risk, it is necessary to apply the Standard to applicable lines on
any kind of land or easement, whether they are Federal Lands, state or provincial lands, public or
private lands, franchises, easements or lands owned in fee. For the purposes of the Standard and
this Technical Reference document, the term “public lands” includes municipal lands, village
lands, city lands, and land owned by a host of other governmental entities.
The Standard addresses vegetation management along applicable overhead lines that serve to
connect one electric station to another. However, it is not intended to be applied to lines sections
inside the electric station fence or other boundary of an electric station, submarine or
underground lines.
The Standard is intended to reduce the risk of Cascading involving vegetation. It is not intended
to prevent customer outages from occurring due to tree contact with all transmission lines and
voltages. For example, localized customer service might be disrupted if vegetation were to make
contact with a 69kV transmission line supplying power to a 12kV distribution station. However,
this Standard is not written to address such isolated situations which have little impact on the
overall Bulk Electric System.
Vegetation growth is constant and always present. Unmanaged vegetation poses an increased
outage risk when numerous transmission lines are operating at or near their Rating. This poses a
significant risk of multiple line failures and Cascading. On the other hand, most other outage
causes (such as trees falling into lines, lightning, animals, motor vehicles, etc.) are statistically
intermittent. The probability of occurrence of these events is not dependent on heavy loads.
There is no cause-effect relationship which creates the probability of simultaneous occurrence of
other such events. Therefore these types of events are highly unlikely to cause large-scale grid
failures.
In preparing the original vegetation management standard in 2005, industry stakeholders set the
threshold for applicability of the standard at 200kV. This was because an unexpected loss of
lines operating at above 200kV has a higher probability of initiating a widespread blackout or
cascading outages compared with lines operating at less than 200kV.
The original NERC Standard FAC-003-1 also allowed for application of the standard to
“critical” circuits (critical from the perspective of initiating widespread blackouts or cascading
outages) operating below 200kV. While the percentage of these circuits is relatively low, it
remains a fact that there are sub-200kV circuits whose loss could contribute to a widespread
outage. Given the very limited exposure and unlikelihood of a major event related to these lowervoltage lines, it would be an imprudent use of resources to apply the Standard to all sub-200kV
lines. The drafting team, after evaluating several alternatives, selected the IROL and WECC
Major Transfer Path criteria to determine applicable lines below 200 kV that are subject to this
standard.
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NERC Standard FAC-003-2 Technical Reference
Active Transmission Line ROW
The term “Active Transmission Line Right of Way” is defined in the Standard in a footnote
repeated for convenience below:
A strip or corridor of land that is occupied by active transmission facilities. This
corridor does not include the parts of the Right-of-Way that are unused or
intended for other facilities. However, it is not to be less than the width of the
easement itself unless the easement exceeds distances as shown in Table 3 for
various voltage classes.
The term Right of Way (ROW) can be used in reference to many situations. This is partially
because some lines are built on the land that is owned fee simple by the transmission owner,
other lines are built across federal or provincial lands with only limited rights under a permit or
agreement, and many other lines cross lands with only limited easement rights to construct,
operate and maintain the line. Transmission line configurations on ROWs are present in many
combinations of multiple circuits on various tower types. The number of circuits and
configurations change along the length of the ROW due to circuits departing to other locations or
terminating at nearby substations. Figures 1, 2 and 3 on the following pages depict several
typical transmission line configurations on typical rights of way.
A Transmission Owner may plan for a nominal width along the entire length of a line during
planning using its design specifications for a particular circuit configuration and voltage. The
actual acquired ROW width at the time a circuit is constructed is however impacted in many
cases, by other considerations. Those considerations include other future circuits that may be
built adjacent to the subject line, or property parcels with unusual ‘extra” widths due to special
property owner demands during initial acquisition, or other existing lines adjacent to the subject
line (which may be retired or abandoned at a future date). Refer to Figures 1 and 3 for common
examples of such situations.
This Standard requires the Transmission Owner to prevent sustained outages due to vegetation
“growing into” or “blowing-together” with line conductors if that vegetation is under the line or
growing beside the line (provided the Transmission Owner has the legal right to remove or trim
the vegetation growing beside the line). Transmission Owners are also required to prevent
sustained outages due to fall-ins from trees that, before falling, were standing inside the limits
established in footnote 2 and associated “Table 3” (see below).
However it is recognized that any requirement in this standard to impose violations for sustained
outages due to “fall-ins” must consider the impact of forcing the clearing of ROWs to the legal
edge or to widths wider than they are typically managed. Therefore the standard drafting team
inserted the subject footnote “active transmission line ROW” to provide a distance for a
Transmission Owner to use if they do not already have a codified ROW width for a particular
circuit or voltage”. This approach of defining “active” and “inactive” right of way is intended to
clarify the confusion created by the current standard which simply states that a fall-in from
within the ROW is a violation. This provides the Transmission Owner with a means to define a
right of way width that is applicable to fall-ins, provided it is not less than those limits in “Table
3”.
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69 - 138 kV
37.5 ft.
139 - 230 kV
50 ft.
231 - 345 kV
75 ft.
346 - 500 kV
87.5 ft.
501 - 765 kV
100 ft.
“Table 3 – Minimum Distance from the Centerline of the Circuit to the edge of the active
transmission line ROW”
Figure 1
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Figure 2
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Figure 3
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Requirements R1 and R2
R1.
2
Each Transmission Owner shall manage
Rationale
vegetation to prevent encroachment that
The
MVCD is a calculated minimum
Rationale
could result in a Sustained Outage of any
distance
stated
feet (meters)
to prevent
The MVCD
is in
a calculated
minimum
lineencroachments of the types shown
spark-over
between
conductors
distance stated in feet (meters)and
to prevent
below, into the Minimum Vegetation
vegetation,
for various
altitudes and
flash-over between
conductors
and
Clearance Distance (MVCD) of any of its
operating
voltages.
The
distances
in
vegetation, for various altitudes and
applicable line(s) identified as an element Table 2 were derived using a proven
operating voltages. The distances in Table 2
of an Interconnection Reliability
transmission
were deriveddesign
using method.
a proven transmission
Operating Limit (IROL) in the planning
design method. The types of failure to
horizon by the Planning Coordinator; or
manage vegetation are listed in order of
Major Western Electricity Coordinating
increasing degrees of severity in nonCouncil (WECC) transfer path ((s);
compliant performance as it relates to a
operating within its Rating and all Rated
failure of a TO’s vegetation maintenance
Electrical Operating Conditions). Types
program since the encroachments listed
of encroachment include:. 2
require different and increasing levels of
1. An encroachment into the Minimum
skills and knowledge and thus constitute a
Vegetation Clearance Distance (MVCD)
logical progression of how well, or poorly,
MVCD as shown in FAC-003-Table 2,
a TO manages vegetation relative to this
observed in Real-time, absent a
Requirement.
Sustained Outage,
2. An encroachment due to a fall-in from
inside the Active Transmission Line ROWRight-of-Way (ROW) that caused a vegetationrelated Sustained Outage,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the Active Transmission Line ROW that caused a vegetation-related Sustained
Outage,
4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage.
[VRF – High] [Time Horizon – Real-time]
This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to
this reliability standard, including natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, wind
shear, fresh gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice
storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree,
arboricultural activities or horticultural or agricultural activities, or removal or digging of vegetation. Nothing in this
footnote should be construed to limit the Transmission Owner’s right to exercise its full legal rights on the ROW.
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R2. Each Transmission Owner shall manage vegetation to prevent encroachment that could
result in a Sustained Outageencroachments of the types shown below, into the MVCD
of any of its applicable linesline(s) that areis not elements of an Interconnection
Reliability Operating Limit (element of an IROL); or Major Western Electricity
Coordinating Council (WECC) transfer path (; operating within its Rating and all Rated
Electrical Operating Conditions). Types of encroachment include:.Error!
Bookmark not defined.
1. An encroachment into the Minimum Vegetation Clearance Distance (MVCD)MVCD as
shown in FAC-003-Table 2, observed in Real-time, absent a Sustained Outage,
2. An encroachment due to a fall-in from inside the Active Transmission Line ROW that
caused a vegetation-related Sustained Outage,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the Active Transmission Line ROW that caused a vegetation-related Sustained
Outage,
4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage.
[VRF – Medium] [Time Horizon – Real-time]
M1. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, reports containing no Sustained Outages
associated with encroachment types 2 through 4 above, or records confirming no RealTime observations of any MVCD encroachments.
datedMultiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24-hour
period. If an investigation of a Fault by a qualified person confirms that a vegetation
encroachment within the MVCD occurred, then it shall be considered a Real-time
observation.
M2. Each Transmission Owner has evidence that it managed vegetation as described in
R2. Examples of acceptable forms of evidence may include attestations, reports
containing no Sustained Outages associated with encroachment types 2 through 4
above, or records confirming no Real-time observations of any MVCD
encroachments.
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation
encroachment within the MVCD has occurred from vegetation within the ROW, this
shall be considered the equivalent of a Real-time observation.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. (R1)
M2. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R2. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
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Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-time observations of any MVCD encroachments.
If an investigationa later confirmation of a Fault by a qualified person confirmsthe
Transmission Owner shows that a vegetation encroachment within the MVCD has
occurred, then it from vegetation within the ROW, this shall be considered the
equivalent of a Real-time observation.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. (R2)
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the prevention of vegetation encroachments within a minimum distance of
transmission lines. Content-wise, R1 and R2 are the same requirements; however, they apply to
different Facilities. Both R1 and R2 require each Transmission Owner to preventmanage
vegetation from encroachingto prevent encroachment within the Minimum Vegetation Clearance
Distance (“MVCD”) of transmission lines. R1 is applicable to lines “identified as an element of an
Interconnection Reliability Operating Limit (IROL) or Major Western Electricity Coordinating
Council (WECC) transfer path (operating within Rating and Rated Electrical Operating
Conditions) to avoid a Sustained Outage”. R2 applies to all other applicable lines that are not an
element of an IROL or Major WECC Transfer Path.
The separation of applicability (between R1 and R2) recognizes that an encroachment into the
MVCD of an IROL or Major WECC Transfer Path transmission line is a greater risk to the
electric transmission system. Applicable lines that are not an element of an IROL or Major
WECC Transfer Path are required to be clear of vegetation but these lines are comparatively less
operationally significant. As a reflection of this difference in risk impact, the Violation Risk
Factors (VRFs) are assigned as High for R1 and Medium for R2.
These requirements (R1 and R2) state that if vegetation encroaches within the distances in Table
1 in Appendix 1 of this supplemental Transmission Vegetation Management Standard FAC-0032 Technical Reference document, it is in violation of the standard. Table 12 tabulates the
distances necessary to prevent spark-over based on the Gallet equations as described more fully
in Appendix 1 below.
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating
(potentially in violation of other standards), the occurrence of a clearance encroachment may
occur. For example, emergency actions taken by a Transmission Operator or Reliability
Coordinator to protect an Interconnection may cause the transmission line to sag more and come
closer to vegetation, potentially causing an outage. Such vegetation-related outages are not a
violation of these requirements.
Evidence of violation of Requirement R1 and R2 include real-time observation of a vegetation
encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related encroachment
resulting in a Sustained Outage due to a fall-in from inside the Active Transmission Line ROW,
or a vegetation-related encroachment resulting in a Sustained Outage due to blowing together of
applicable lines and vegetation located inside the Active Transmission Line ROW, or a
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vegetation-related encroachment resulting in a Sustained Outage due to a grow-in. If an
investigation of a Fault by a qualified personTransmission Owner confirms that a vegetation
encroachment within the MVCD occurred, then it shall be considered the equivalent of a Realtime observation.
With this approach, the VSLs were defined such that they directly correlate to the severity of a
failure of a Transmission Owner to keepmanage vegetation away from conductors and to the
corresponding performance level of the Transmission Owner’s vegetation program’s ability to
meet the goal of “preventing a Sustained Outage that could lead to Cascading.” Thus violation
severity increases with a Transmission Owner’s inability to meet this goal and its potential of
leading to a Cascading event. The additional benefits of such a combination are that it simplifies
the standard and clearly defines performance for compliance. A performance-based requirement
of this nature will promote high quality, cost effective vegetation management programs that will
deliver the overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation,. For
example, a limb thatmay only partially breaksbreak and intermittently contactscontact a
conductor. Such events are considered to be a single vegetation-related Sustained Outage under
the Standard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will help prevent transmission outages.
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Requirement R3
Rationale
ProvideThe documentation provides a basis
for evaluation onevaluating the intent and
competency of the Transmission Owner in
maintainingOwner’s vegetation program.
There may be many acceptable approaches to
maintain clearances. However,Any approach
must demonstrate that the Transmission
Owner should be able avoids vegetation-to
state what its approach is and how it conducts
work to maintain clearances.-wire conflicts
under all Rated Electrical Operating
Conditions. See Figure 1 [in Standard FAC003-2] for an illustration of possible
conductor locations.
R3. Each Transmission Owner shall document
the have documented maintenance
strategies or procedures, or processes, or
specifications it uses to prevent the
encroachment of vegetation into the
MVCD. Such documentation will
incorporate of its applicable transmission
lines that include(s) the following:
3.1 Accounts for the dynamicsmovement of
aapplicable transmission line
conductor’s movement throughout its
conductors under their Facility Rating
and all Rated Electrical Operating
Conditions and;
3.2 Accounts for the inter-relationships
between vegetation growth rates, vegetation control methods, and
inspection frequency, for the Transmission Owner’s applicable lines.
[VRF – Lower] [Time Horizon – Long Term Planning]
M3. The maintenance strategies or procedures, or processes, or specifications provided
demonstrate that the Transmission Owner can prevent encroachment into the
MVCD considering the factors identified in the requirement. (R3)
Requirement R3 is a competency based requirement concerned with the maintenance strategies,
procedures, processes, or specifications, a Transmission Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the
Transmission Owner uses to plan and perform vegetation work to prevent transmission Sustained
Outages and minimize risk to the Transmission System. The approach provides the basis for
evaluating the intent, allocation of appropriate resources and the competency of the Transmission
Owner in managing vegetation. There are many acceptable approaches to manage vegetation
and avoid Sustained Outages. However, the Transmission Owner must be able to state what its
approach is and how it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach a
Transmission Owner chooses to use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the Transmission Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing as a reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
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NERC Standard FAC-003-2 Technical Reference
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figure 5Figures 2 and 3 below.
Conductor Dynamics
In order for a Transmission Owner to develop a specific maintenance approach, it is important to
understand the dynamics of a line conductor’s movement. This paper will first address the
complexities inherent in observing and predicting conductor movement, particularly for field
personnel. It will then present some examples of maintenance approaches which Transmission
Owners may consider that take into account these complexities, while resulting in practical
approaches for field personnel.
Additionally, it is important the Transmission Owner consider all conductor locations, the
MVCD, and vegetation growth between maintenance activities when developing a maintenance
approach.
Understanding Conductor Position and Movement
The conductor’s position in space at any point in time is continuously changing as a reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading.
As a consequence of these loading variables, the conductor’s position in space is dynamic and
moving. When calculating the range of conductor positions, the Transmission Owner should use
the same design criteria and assumptions that the Transmission Owner uses when establishing
Ratings and SOL, as described in other standards. Typically, the greatest conductor movement
would be at mid-span. As the conductor moves through various positions, a spark-over zone
surrounding the conductor moves with it. The radius of the spark-over zone may be found by
referring to Table 1 (“Minimum Vegetation Clearance Distances”) in the standard. For
illustrations of this zone and conductor movements, Figures 41 through 63 below demonstrate
these concepts. At the time of making a field observation, however, it is very difficult to
precisely know where the conductor is in relation to its wide range of all possible positions.
Therefore, Transmission Owners must adopt maintenance approaches that account for this
dynamic situation.
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Figure 41
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Figure 52
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Cross-Section View of a Single Conductor
At a Given Point Along The Span
Showing Six Possible Conductor Positions Due to Movement
Resulting From Thermal and Mechanical Loading
For Consideration in Developing a Maintenance Approach
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Figure 63
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Selecting a Maintenance Approach
In order to maintain adequate separation between vegetation and transmission line conductors,
the Transmission Owner must craft a maintenance strategy that keeps vegetation well away from
the spark-over zone mentioned above. In fact, it is generally necessary to incorporate a variety of
maintenance strategies. For example, one Transmission Owner may utilize a combination of
routine cycles, traditional IVM techniques and long-term planning. Another Transmission Owner
may place a higher reliance on frequent inspections and quick remediation as opposed to a
cyclical approach. This variation of approaches is further warranted when factors, such as
terrain, legal and other constraints, vegetation types, and climates, are considered in developing a
Transmission Owner’s specific approach to satisfying this requirement.
The following is a sample description of one combination of strategies which may be utilized by
a Transmission Owner. A Transmission Owner’s basic maintenance approach could be to
remove all incompatible vegetation from the right of way if it has the right to do so and has no
constraints. In mountainous terrain, however, this strategy could change to one where the
Transmission Owner manages vegetation based on vegetation-to-conductor clearances, since it
might not be necessary to remove vegetation in a valley that is far below.
If faced with constraints and assuming a line design with sufficient ground clearance, the
Transmission Owner ’s approach could then be to allow vegetation such as fruit trees, but
perhaps only up to a given height at maturity (perhaps 10 feet from the ground). If constraints
cannot be overcome and if design clearances are sufficient, an exception to the Transmission
Owner’s 10-foot guideline might be made. Finally, if the Transmission Owner has chosen to
utilize vegetation-to-conductor clearance distance methods, the Transmission Owner could have
an inspection regimen in place to regularly ensure that any impending clearance problems are
identified early for rectification.
ANSI A300 – Best Management Practices for Tree Care Operations
A description of ANSI A-300, part 7, is offered below to illustrate another maintenance approach
that could be used in developing a comprehensive transmission vegetation management program.
Introduction
Integrated Vegetation Management (IVM) is a best management practice conveyed in the
American National Standard for Tree Care Operations, Part 7 (ANSI 2006) and the International
Society of Arboriculture Best Management Practices: Integrated Vegetation Management
(Miller 2007). IVM is consistent with the requirements in FAC-003-02, and it provides
practitioners with what industry experts consider to be appropriate techniques to apply to electric
right-of-way projects in order to meet or exceed the Standard.
IVM is a system of managing plant communities whereby managers set objectives; identify
compatible and incompatible vegetation; consider action thresholds; and evaluate, select and
implement the most appropriate control method or methods to achieve set objectives. The choice
of control method or methods should be based on the environmental impact and anticipated
effectiveness; along with site characteristics, security, economics, current land use and other
factors.
Planning and Implementation
Best management practices provide a systematic way of planning and implementing a vegetation
management program. While designed primarily with transmission systems in mind, it is also
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applicable to distribution projects. As presented in ANSI A300 part 7 and the ISA best
management practices, IVM consists of 6 elements:
1)
2)
3)
4)
5)
6)
Set Objectives
Evaluate the Site
Define Action Thresholds
Evaluate and Select Control Methods
Implement IVM
Monitor Treatment and Quality Assurance
The setting of objectives, defining action thresholds, and evaluating and selecting control
methods all require decisions. The planning and implementation process is cyclical and
continuous, because vegetation is dynamic and managers must have the flexibility to adjust their
plans. Adjustments may be made at each stage as new information becomes available and
circumstances evolve.
Set Objectives
Objectives should be clearly defined and documented. Examples of objectives can
include promoting safety, preventing sustained outages caused by vegetation growing
into electric facilities, maintaining regulatory compliance, protecting structures and
security, restoring electric service during emergencies, maintaining access and clear lines
of sight, protecting the environment, and facilitating cost effectiveness.
Objectives should be based on site factors, such as workload and vegetation type, in
addition to human, equipment and financial resources. They will vary from utility to
utility and project to project, depending on line voltage and criticality, as well as
topographical, environmental, fiscal and political considerations. However, where it is
appropriate, the overriding focus should be on environmentally-sound, cost effective
control of species that potentially conflict with the electric facility, while promoting
compatible, early successional, sustainable plant communities.
Work Load Evaluations
Work-load evaluations are inventories of vegetation that could have a bearing on
management objectives. Work load assessments can capture a variety of vegetation
characteristics, such as location, height, species, size and condition, hazard status, density
and clearance from conductors. Assessments should be conducted considering voltage,
conductor sag from ambient temperatures and loading, and the potential influence of
wind on line sway.
Evaluate and Select Control Methods
Control methods are the process through which managers achieve objectives. The most
suitable control method best achieves management objectives at a particular site. Many
cases call for a combination of methods. Managers have a variety of controls from which
to choose, including manual, mechanical, herbicide and tree growth regulators,
biological, and cultural options.
Manual Control Methods
Manual methods employ workers with hand-carried tools, including chainsaws,
handsaws, pruning shears and other devices to control incompatible vegetation. The
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advantage of manual techniques is that they are selective and can be used where others
may not be. On the other hand, manual techniques can be inefficient and expensive
compared to other methods.
Mechanical Control Methods
Mechanical controls are done with machines. They are efficient and cost effective,
particularly for clearing dense vegetation during initial establishment, or reclaiming
neglected or overgrown right of way. On the other hand, mechanical control methods can
be non-selective and disturb sensitive sites.
Tree Growth Regulator and Herbicide Control Methods
Tree growth regulators and herbicides can be effective for vegetation management. Tree
growth regulators (TGRs) are designed to reduce growth rates by interfering with natural
plant processes. TGRs can be helpful where removals are prohibited or impractical by
reducing the growth rates of some fast-growing species.
Herbicides control plants by interfering with specific botanical biochemical pathways.
Herbicide use can control individual plants that are prone to re-sprout or sucker after
removal. When trees that re-sprout or sucker are removed without herbicide treatment,
dense thickets develop, impeding access, swelling workloads, increasing costs, blocking
lines-of-site, and deteriorating wildlife habitat. Treating suckering plants allows early
successional, compatible species to dominate the right-of-way and out-compete
incompatible species, ultimately reducing work.
Cultural Control Methods
Cultural methods modify habitat to discourage incompatible vegetation and establish and
manage desirable, early successional plant communities. Cultural methods take
advantage of seed banks of native, compatible species lying dormant on site. In the long
run, cultural control is the most desirable method where it is applicable.
A cultural control known as cover-type conversion provides a competitive advantage to
short-growing, early successional plants, allowing them to thrive and eventually outcompete unwanted tree species for sunlight, essential elements and water. The early
successional plant community is relatively stable, tree-resistant and reduces the amount
of work, including herbicide application, with each successive treatment.
Wire-Border Zone
The wire-border zone technique is a management philosophy that can be applied through
cultural control. W.C. Bramble and W.R. Byrnes developed it in the mid-1980s out of
research begun in 1952 on a transmission right-of-way in the Pennsylvania State Game
Lands 33 Research and Demonstration project (Yahner and Hutnik (2004).
The wire zone is the section of a utility transmission right-of-way directly under the wires
and extending outward about 10 feet on each side. The wire zone is managed to promote
a low-growing plant community dominated by grasses, herbs and small shrubs (under 3
feet in height at maturity). The border zone is the remainder of the right-of-way. It is
managed to establish small trees and tall shrubs (under 25 feet in height at maturity).
When properly managed, diverse, tree-resistant plant communities develop in wire and
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border zones. The communities not only protect the electric facility and reduce long-term
maintenance, but also enhance wildlife habitat, forest ecology and aesthetic values.
Although the wire-border zone is a best practice in many instances, it is not necessarily
universally suitable. For example, standard wire-border zone prescriptions may be
unnecessary where lines are high off the ground, such as across low valleys or canyons,
so the technique can be modified without sacrificing reliability.
One way to accommodate variances in topography is to establish different regions based
on wire height. For example, over canyon bottoms or other areas where conductors are
100 feet or more above the ground, only a few trees are likely to be tall enough to conflict
with the lines. In those cases, trees that potentially interfere with the transmission lines
can be removed selectively on a case-by-case basis.
In areas where the wire is lower, perhaps between 50-100 feet from the ground, a border
zone community can be developed throughout the right-of-way. Note that in many cases,
conductor attachment points are more than 50 feet off the ground, so a border zone
community can be cultivated near structures. Where the line is less than 50 feet off the
ground, managers could apply a full wire-border zone prescription.
An environmental advantage of this type of modification is stream protection. Streams
often course through the valleys and canyons where lines are likely to be elevated.
Leaving timber or border zone communities in canyon bottoms helps shelter this valuable
habitat, enabling managers to achieve environmentally sensitive objectives.
Implement IVM
All laws and regulations governing IVM practices and specifications written by qualified
vegetation managers must be followed. Integrated vegetation management control
methods should be implemented on regular work schedules, which are based on
established objectives and completed assessments. Work should progress systematically,
using control measures determined to be best for varying conditions at specific locations
along a right-of-way. Some considerations used in developing schedules include the
importance and type of line, vegetation clearances, work loads, growth rate of predominant
vegetation, geography, accessibility, and in some cases, time lapsed since the last scheduled
work.
Clearances Following Work
Clearances following work should be sufficient to meet management objectives,
including preventing trees from entering the Minimum Vegetation Clearance Distance,
electric safety risks, service-reliability threats and cost.
Monitor Treatment and Quality Assurance
An effective program includes documented processes to evaluate results. Evaluations
can involve quality assurance while work is underway and after it is completed.
Monitoring for quality assurance should begin early to correct any possible
miscommunication or misunderstanding on the part of crewmembers. Early and
consistent observation and evaluation also provides an opportunity to modify the plan, if
need be, in time for a successful outcome.
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Utility vegetation management programs should have systems and procedures in place
for documenting and verifying that vegetation management work was completed to
specifications. Post-control reviews can be comprehensive or based on a statistically
representative sample. This final review points back to the first step and the planning
process begins again.
Summary of A-300 example
Integrated Vegetation Management offers among others, a systematic way of planning and
implementing a vegetation management program as presented in ANSI A300 Part 7. This
methodology enables a program to comply with the NERC Transmission Vegetation
Management Program standard (FAC-003-2). Managers should select control options to best
promote management objectives.
Vegetation Inspections
As with the ANSI A-300 example, The Transmission Owner’s transmission vegetation
management program (TVMP) establishes the frequency of vegetation inspections based upon
many factors. Such local and environmental factors may include anticipated growth rates of the
local vegetation, length of the growing season for the geographical area, limited Active
Transmission Rights of Way width, rainfall amounts, etc.
Annual Work Plan
Requirement R7 of the Standard addresses the execution of the annual work plan. A
comprehensive approach that exercises the full extent of legal rights is superior to incremental
management in the long term because it reduces overall encroachments, and it ensures that future
planned work and future planned inspection cycles are sufficient at all locations on the Active
Transmission Line Right of Way. Removal is superior to pruning. Removal minimizes the
possibility of conflicts between energized conductors and vegetation. Since this is not always
possible, the Transmission Owner’s approach should be to use its prescribed vegetation
maintenance methods to work towards or achieve the maximum use of the Active Transmission
Line Right of Way.
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Requirement R4
R4. Each Transmission Owner, without any
intentional time delay, shall notify the
control center holding switching
authority for the associated applicable
transmission line when qualified
personnel confirmthe Transmission
Owner has confirmed the existence of a
vegetation condition that is likely to
cause a Fault at any moment.
Rationale
To ensure expeditious communication
between qualified field personnelthe
Transmission Owner and proper operating
personnelthe control center when a critical
situation is confirmed.
Qualified field personnel may include
[VRF – Medium] [Time Horizon – Real-time]
M4. Each Transmission Owner that has a confirmed vegetation condition likely to cause a Fault
at any moment, as confirmed by qualified personnel, will have evidence that it notified the
control center holding switching authority for the associated transmission line without any
intentional time delay. Examples of evidence may include control center logs, voice
recordings, switching orders, clearance orders and subsequent work orders. (R4)
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the
Transmission Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4
involves the notification of potentially threatening vegetation conditions, without any intentional
delay, to the control center holding switching authority for that specific transmission line.
Examples of acceptable unintentional delays may include communication system problems (for
example, cellular service or two-way radio disabled), crews located in remote field locations
with no communication access, delays due to severe weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of a qualifiedTransmission Owner’s employee who personally identifies such a threat in
the field. Confirmation could also be made by sending out a qualified personan employee to
evaluate a situation reported by a landowner or an unqualified employee..
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an assessment
of the possible sag or movement of the conductor while operating between no-load conditions
and its rating.
The Transmission Owner has the responsibility to ensure the proper communication between
field personnel and the control center to allow the control center to take the appropriate action
until the vegetation threat is relieved. Appropriate actions may include a temporary reduction in
the line loading, switching the line out of service, or positioning the system in recognition of the
increasing risk of outage on that circuit. The notification of the threat should be communicated in
terms of minutes or hours as opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some Transmission Owners may have a danger tree identification
FAC-003-2 Technical Reference
June 28December 17, 2010
35
NERC Standard FAC-003-2 Technical Reference
program that identifies trees for removal with the potential to fall near the line. These trees
would not require notification to the control center unless they pose an immediate fall-in threat.
FAC-003-2 Technical Reference
June 28December 17, 2010
36
NERC Standard FAC-003-2 Technical Reference
Requirement R5
R5. Each
When a Transmission Owner
shall take corrective action when it is
constrained from performing planned
vegetation work, where a transmission
line is put at potential risk due to and the
constraint. may lead to a vegetation
encroachment into the MVCD of its
applicable transmission lines prior to the
implementation of the next annual work
plan then the Transmission Owner shall
take corrective action to ensure continued
vegetation management to prevent
encroachments. [VRF – Medium] [Time
Horizon – Operations Planning]
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
Transmission Owner from performing
planned vegetation maintenance work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the Transmission Owner to put interim
measures in place, rather than do nothing.
For example, in the 2003 NE blackout a
Transmission Owner was prevented by a
court order from performing planned work.
However, when the court order expired, the
TO failed to take action to maintain the
M5. Each Transmission Owner has evidence of the corrective action taken for each constraint
where aan applicable transmission line was put at potential risk. Examples of acceptable
forms of evidence may include initially-planned work orders, documentation of constraints
from landowners, court orders, inspection records of increased monitoring,
documentation of the de-rating of lines, revised work orders, invoices, and evidence that a
line was de-energized. (R5)
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
Transmission Owner for the mitigation of Sustained Outage risk when temporarily constrained
from performing vegetation maintenance. The intent of this requirement is to deal with situations
that prevent the Transmission Owner from performing planned vegetation management work
and, as a result, have the potential to put the transmission line at risk. Constraints to performing
vegetation maintenance work as planned could result from legal injunctions filed by property
owners, the discovery of easement stipulations which limit the Transmission Owner’s rights, or
other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
Transmission Owner is not under any immediate time constraint for achieving the management
objective, can easily reschedule work using an alternate approach, and therefore does not need to
take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the Transmission Owner is required to take an interim corrective action to mitigate the potential
risk to the transmission line. A wide range of actions can be taken to address various situations.
General considerations include:
FAC-003-2 Technical Reference
June 28December 17, 2010
37
NERC Standard FAC-003-2 Technical Reference
•
•
•
•
•
Identifying locations where the Transmission Owner is constrained from performing
planned vegetation maintenance work which potentially leaves the transmission line
at risk.
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for each location.
In developing the specific action to mitigate the potential risk to the transmission line
the Transmission Owner could consider location specific measures such as modifying
the inspection and/or maintenance intervals. Where a legal constraint would not allow
any vegetation work, the interim corrective action could include limiting the loading
on the transmission line.
The Transmission Owner should document and track the specific corrective action
taken at each location. This location may be indicated as one span, one tree or a
combination of spans on one property where the constraint is considered to be
temporary.
FAC-003-2 Technical Reference
June 28December 17, 2010
38
NERC Standard FAC-003-2 Technical Reference
Requirement R6
R6. Each Transmission Owner shall perform a
Vegetation Inspection of all100% of its
applicable transmission lines (measured
in units of choice - circuit, pole line, line
miles or kilometers, etc.) at least once per
calendar year. and with no more than 18
months between inspections on the same
ROW. 3
[VRF – Medium] [Time Horizon –
Operations Planning]
Rationale
Inspections are used by Transmission Owners
to prevent
assess the
thecondition
encroachment
of the of
entire
vegetation
ROW. into
The
information
the
MVCD and
fromprovide
the assessment
a basis forcan
assessing
be used to
determine
risk.
This requirement
risk, determine
setsfuture
a minimum
work and
evaluate recently-completed
vegetation
inspection frequency
work.
of once
This per
requirement
calendar
year.
setsBased
a minimum
upon average
Vegetation
growth
Inspection
rates
acrossfrequency
North America
of onceand
peroncalendar
common
year
but with
utility
practice,
no more
this
than
minimum
18 months
frequency
betweenis
inspections on
reasonable.
Transmission
the same ROW.
Owners
Based
should
upon
average growth
consider
local and
rates
environmental
across Northfactors
America
that
and onwarrant
could
common
more
utility
frequent
practice,
inspections.
this minimum
frequency is reasonable. Transmission Owners
should consider local and environmental
factors that could warrant more frequent
inspections.
M6. Each Transmission Owner has evidence
that it conducted Vegetation Inspections at
least once per calendar year for
applicableof the transmission linesline
ROW for all applicable transmission lines
at least once per calendar year but with no more than 18 months between inspections on
the same ROW. Examples of acceptable forms of evidence may include completed and
dated work orders, dated invoices, or dated inspection records. (R6)
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections that fits general industry practice. In addition, the fact that Vegetation
Inspections can be performed in conjunction with general line inspections further facilitates a
Transmission Owner’s ability to meet this requirement. However, the Transmission Owner may
determine that more frequent inspections are needed to maintain reliability levels, dependent
upon such factors as anticipated growth rates of the local vegetation, length of the growing
season for the geographical area, limited Active Transmission ROW width, and rainfall amounts.
Therefore it is expected that some transmission lines may be designated with a higher frequency
of inspections.
The SDT added footnote 3 to address the situation where a Transmission Owner through no fault
of its own, would be unable to complete the vegetation inspection within the allotted time period.
This would include the situation of mutual aid as well as disasters to the Transmission Owner’s
own system.
The VSL for Requirement R6 has VSL categories ranked by the percentage of the required ROW
inspections completed. To calculate the percentage of inspection completion, the Transmission
Owner may choose units such as: line miles or kilometers, circuit miles or kilometers, pole line
miles, ROW miles, etc.
3
When the Transmission Owner is prevented from performing a Vegetation Inspection within the timeframe in R6
due to a natural disaster, the TO is granted a time extension that is equivalent to the duration of the time the TO was
prevented from performing the Vegetation Inspection.
FAC-003-2 Technical Reference
39
June 28December 17, 2010
NERC Standard FAC-003-2 Technical Reference
For example, when a Transmission Owner operates 2,000 miles of 230 kV transmission lines this
Transmission Owner will be responsible for inspecting all 2,000 miles of 230 kV transmission
lines at least once during the calendar year. If one of the included lines was 100 miles long, and
if it was not inspected during the year, then the amount failed to inspect would be 100/2000 =
0.05 or 5%. The “Low VSL” for R6 would apply in this example.
FAC-003-2 Technical Reference
June 28December 17, 2010
40
NERC Standard FAC-003-2 Technical Reference
Requirement R7
R7. Each Transmission Owner shall complete
Rationale
the work in an100% of its annual
This requirement sets the expectation that the
vegetation work plan to ensure no
work identified in the annual work plan will
vegetation encroachments occur within
be completed as planned. An annual
the MVCD. Modifications to the work
vegetation work plan allows for work to be
plan in response to changing conditions or
modified for changing conditions, taking into
to findings from vegetation inspections
consideration anticipated growth of
may be made and documented (provided
vegetation and all other environmental
they do not put the transmission system at
factors, provided that the changes do not
risk of a vegetation encroachment.) and
violate the encroachment within the MVCD.
must be documented. The percent
completed calculation is based on the
number of units actually completed divided by the number of units in the final amended
plan (measured in units of choice - circuit, pole line, line miles or kilometers, etc.)
Examples of reasons for modification to annual plan may include:
•
•
•
•
•
•
•
•
•
•
•
• Change in expected growth rate/ environmental factors
Major storms
• Circumstances that are beyond the control of a Transmission Owner 4
Rescheduling work between growing seasons
• Crew or contractor availability/ Mutual assistance agreements
• Identified unanticipated high priority work
• Weather conditions/Accessibility
• Permitting delays
• Land ownership changes/Change in land use by the landowner
Funding adjustments (increase or decrease)
• Emerging technologies
[VRF – Medium] [Time Horizon – Operations Planning]
M7. Each Transmission Owner has evidence that it completed its annual vegetation work plan.
Examples of acceptable forms of evidence may include a copy of the completed annual
work plan (including modifications if any), dated work orders, dated invoices, or dated
inspection records. (R7)
R7 is a risk-based requirement. The Transmission Owner is required to implement an annual
work plan for vegetation management to accomplish the purpose of this Standard. Modifications
to the work plan in response to changing conditions or to findings from vegetation inspections
may be made and documented provided they do not put the transmission system at risk. The
annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a
“line-by-line” detailed description of all work to be performed. It is only intended to require that
the Transmission Owner provide evidence of annual planning and execution of a vegetation
4
circumstances that are beyond the control of a Transmission Owner include but are not limited to natural disasters
such as earthquakes, fires, tornados, hurricanes, landslides, major storms as defined either by the TO or an
applicable regulatory body, ice storms, and floods; arboricultural, horticultural or agricultural activities.
FAC-003-2 Technical Reference
41
June 28December 17, 2010
NERC Standard FAC-003-2 Technical Reference
management maintenance approach which successfully prevents encroachment of vegetation into
the MVCD.
The ability to modify the work plan allows the Transmission Owner to change priorities or
treatment methodologies during the year as conditions or situations dictate. For example recent
line inspections may identify unanticipated high priority work, weather conditions (drought)
could make herbicide application ineffective during the plan year, or a major storm could require
redirecting local resources away from planned maintenance. or work may be deferred to a
subsequent year because of slower-than-expected growth. This situation may also include
complying with mutual assistance agreements by moving resources off the Transmission
Owner’s system to work on another system. Any of these examples could result in acceptable
deferrals or additions to the annual work plan. Modifications to the annual work plan must
always ensure the reliability of the electric Transmission system.
In general, the vegetation management maintenance approach should use the full extent of the
Transmission Owner’s easement, fee simple and other legal rights allowed. on the ROW. A
comprehensive approach that exercises the full extent of legal rights on the Active Transmission
Line ROW is superior to incremental management in the long term because it reduces the overall
potential for encroachments, and it ensures that future planned work and future planned
inspection cycles are sufficient.
When developing the annual work plan, the Transmission Owner should allow time for
reasonable and predictable procedural requirements to obtain permits to work on federal, state,
provincial, public, tribal lands. In some cases, the lead time for obtaining permits may
necessitate preparing work plans more than a year prior to workthe start datesof work.
Transmission Owners may also need to consider those special landowner requirements as
documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the Transmission
Owner, evidence of successful annual work plan execution could consist of signed-off work
orders, signed contracts, printouts from work management systems, spreadsheets of planned
versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence
may include photographs, and walk-through reports.
FAC-003-2 Technical Reference
June 28December 17, 2010
42
NERC Standard FAC-003-2 Technical Reference
Appendix 1: Clearance Distance Derivation by the
Gallet Equation
The Gallet Equation is a well-known method of computing the required strike distance for proper
insulation coordination, and has the ability to take into account various air gap geometries, as
well as non-standard atmospheric conditions. When the Gallet Equation and conservative
probabilistic methods are combined, i.e. deterministic design, sparkover probabilities of 10-6 or
less are achieved. This approach is well known for its conservatism and was used to design the
first 500 kV and 765 kV lines in North America [1]. Thus, the deterministic design approach
using the Gallet Equation is used for the standard to compute the minimum strike distance
between transmission lines and the vegetation that may be present in or along the transmission
corridor.
Method Explanation (Gallet Equation)
In 1975 G. Gallet published a benchmark paper that provided a method to compute the critical
flashover voltage (CFO) of various air gap geometries [4]. The Gallet Equation uses various
“gap factors” to take into account various air gap geometries. Various gap factor values are
provided in [1]. If the vegetation in a transmission corridor, e.g. a tree, is assumed electrically to
be a large structure then the CFO of such an air gap geometry can be computed for dry or wet
conditions using a well established equation proposed by Gallet [1],[2],[4],
CFOA = k w ⋅ k g ⋅ δ m ⋅
3400
8
1+
D
(1)
where,
kw
is defined as the factor that takes into account wet or dry conditions (dry = 1.0
and wet = 0.96) and phase arrangement (multiply by 1.08 for outside phase), e.g.
outside phase and wet conditions = (0.96)(1.08) = 1.037,
kg
is defined as the gap factor (1.3 for conductor to large structure),
D
is the strike distance (m),
CFOA
is the CFO for the relative air density (kV).
δ
is defined as the relative air density and is approximately equal to (2) where A is
the altitude in km,
δ =e
A
8.6
(2)
=
m 1.25G0 ( G0 − 0.2 )
(3)
CFOs
500 ⋅ D
(4)
G0 =
FAC-003-2 Technical Reference
June 28December 17, 2010
−
43
NERC Standard FAC-003-2 Technical Reference
CFOs = k w ⋅ k g ⋅
3400
8
1+
D
(5)
where CFOS is the CFO for standard atmospheric conditions (kV). Using (1)-(5), the required CFOA can be
computed using an iterative process.
Once the CFOA is known, deterministic methods can be used to determine the required clearance
distance. If we let the maximum switching overvoltage be equal to the withstand voltage of the
air gap (CFOA - 3σ) then the CFOA can be written as (6).
Vm
σ
1− 3
CFOA
CFOA =
(6)
where
Vm is equal to the maximum switching overvoltage, i.e. the value that has a 0.135% chance of being
exceeded,
σ is the standard deviation of the air gap insulation,
CFOA is the critical flashover voltage of the air gap insulation under non-standard atmospheric conditions.
The ratio of σ to the CFOA given in (6) can be assumed to be 0.05 (5%) [1]. Thus, (6) can be
written as (7).
CFOA =
Vm
0.85
(7)
Substituting (7) into (1) we arrive at (8).
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ m ⋅
3400
8
1+
D
(8)
Equation 8 relates the maximum transient overvoltage, Vm, to the air gap distance, D. Using (8)
to compute the required clearance distance for the specified air gap geometry (conductor to large
structure) results in a probability of flashover in the range of 10-6.
TRANSIENT OVERVOLTAGE
In general, the worst case transient overvoltages occurring on a transmission line are caused by
energizing or re-energizing the line with the latter being the extreme case if trapped charge is
present. The intent of FAC-003 is to keep a transmission line that is in service from becoming
de-energized (i.e. tripped out) due to sparkover from the line conductor to nearby vegetation.
Thus, the worst case scenarios that are typically analyzed for insulation coordination purposes
(e.g. line energization and re-energization) can be ignored. For the purposes of FAC-003-2, the
worst case transient overvoltage then becomes the maximum value that can occur with the line
energized. Determining a realistic value of transient overvoltage for this situation is difficult
because the maximum transient overvoltage factors listed in the literature are based on a
FAC-003-2 Technical Reference
June 28December 17, 2010
44
NERC Standard FAC-003-2 Technical Reference
switching operation of the line in question. In other words, these maximum overvoltage values
(e.g. the values listed in [2], [3] and [5]) are based on the assumption that the subject line is being
energized, re-energized or de-energized. These operations, by their very nature, will create the
largest transient overvoltages. Typical values of transient overvoltages of in-service lines, as
such, are not readily available in the literature because the resulting level of overvoltage is
negligible compared with the maximum (e.g. re-energizing a transmission line with trapped
charge). A conservative value for the maximum transient overvoltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 p.u.[2]. This value is a
conservative estimate of the transient overvoltage that is created at the point of application (e.g. a
substation) by switching a capacitor bank without a pre-insertion device (e.g. closing resistors).
At voltage levels where capacitor banks are not very common (e.g. 362 kV), the maximum
transient overvoltage of an “in-service” ac line are created by fault initiation on adjacent ac lines
and shunt reactor bank switching. These transient voltages are usually 1.5 p.u. or less [2]. It is
well known that these theoretical transient overvoltages will not be experienced at locations
remote from the bus at which they were created; however, in order to be conservative, it will be
assumed that all nearby ac lines are subjected to this same level of overvoltage. Thus, a
maximum transient overvoltage factor of 2.0 p.u. for 242 kV and below and 1.4 p.u. for ac
transmission lines 362 kV and above is used to compute the required clearance distances for
vegetation management purposes.
The overvoltage characteristics of dc transmission lines vary somewhat from their ac
counterparts. The referenced empirically derived transient overvoltage factor used to calculate
the minimum clearance distances from dc transmission lines to vegetation for the purpose of
FAC-003-2 will be 1.8 p.u.[3].
EXAMPLE CALCULATION
An example calculation is presented below using the proposed method of computing the
vegetation clearance distances. It is assumed that the line in question has a maximum operating
voltage of 550 kVrms line-to-line. Using a per unit transient overvoltage factor of 1.4, the result
is a peak transient voltage of 629 kVcrest. It is further assumed that the line in question operates
at a maximum altitude of 7000 feet (2.134 km) above sea level.
The required withstand voltage of the air gap must be equal to or greater than 629 kVcrest. Since
the altitude is above sea level, (1) - (5) have to be iterated on to achieve the desired result.
Equation (9) can be used as an initial guess for the clearance distance.
Di =
8
3400 ⋅ k w ⋅ k g
Vm
0.85
(9)
−1
For our case here, Vm is equal to 629 kV, kw = 1.037 and kg = 1.3. Thus,
Di =
8
3400 ⋅ k w ⋅ k g
Vm
0.85
FAC-003-2 Technical Reference
June 28December 17, 2010
=
−1
8
= 1.535m
3400 ⋅ 1.037 ⋅ 1.3
−1
629
0.85
(10)
45
NERC Standard FAC-003-2 Technical Reference
Using (2)-(5) and (8) the withstand voltage of the air gap is next computed. This value will then
be compared to the maximum transient overvoltage.
CFOS = k w ⋅ k g ⋅
−
3400
3400
= 1.037 ⋅ 1.3 ⋅
= 737.7 kV
8
8
1+
1+
1.535
D
A
−
2.134
8.6
8.6
=
δ e=
e =
0.78
GO =
(12)
CFOS
737.7
=
= 0.961
500 ⋅ D (500 ) ⋅ (1.535 )
(13)
m = 1.25 ⋅ GO (GO − 0.2 ) = 1.25 ⋅ 0.961(0.961 − 0.2 ) = 0.915
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ
m
(11)
3400
3400
0.915
⋅
= (0.85 )(1.037 )(1.3 )(0.78 )
8
8
1
1+
+
D
1.535
(14)
= 499.8 kV
(15)
The calculated Vm is less than 629 kV; thus, the clearance distance must be increased. A few
iterations using (2)-(5) and (8) are required until the computed Vm ≥ 629 kV. For this case it was
found that D = 1.978 m (6.49 feet) yielded Vm = 629.3 kV. Using this clearance distance the
following values were computed for the final iteration.
CFOS = k w ⋅ k g ⋅
−
3400
3400
= 1.037 ⋅ 1.3 ⋅
= 908.5 kV
8
8
1+
1+
D
1.978
A
−
2.134
8.6
8.6
=
δ e=
e =
0.78
GO =
(17)
CFOS
908.5
=
= 0.919
500 ⋅ D (500 ) ⋅ (1.978 )
(18)
m = 1.25 ⋅ GO (GO − 0.2 ) = 1.25 ⋅ 0.919(0.919 − 0.2 ) = 0.825
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ m ⋅
(16)
3400
3400
= (0.85 )(1.037 )(1.3)(0.78 )0.825
8
8
1
1+
+
D
1.978
(19)
= 629.3kV
(20)
Therefore, the minimum vegetation clearance distance for a maximum line to line ac operating
voltage of 550 kV at 7000 feet above sea level is 1.978 m (6.49 feet). Table 1 provides
calculated distances for various altitudes and maximum system operating ac voltages.
FAC-003-2 Technical Reference
June 28December 17, 2010
46
NERC Standard FAC-003-2 Technical Reference
TABLE 1 — Minimum Vegetation Clearance Distances (MVCD) 6
For Alternating Current Voltages
( AC )
Nominal
System
Voltage
(kV)
( AC )
Maximum
System
Voltage
(kV)
765
800
500
550
345
362
230
242
161*
169
138*
145
115*
121
88*
100
69*
72
MVCD
feet
(meters)
sea level
8.06ft
(2.46m)
5.06ft
(1.54m)
3.12ft
(0.95m)
2.97ft
(0.91m)
2ft
(0.61m)
1.7ft
(0.52m)
1.41ft
(0.43m)
1.15ft
(0.35m)
0.82ft
(0.25m)
MVCD
feet
(meters)
3,000ft
(914.4m)
MVCD
feet
(meters)
4,000ft
(1219.2m)
MVCD
feet
(meters)
5,000ft
(1524m)
MVCD
feet
(meters)
6,000ft
(1828.8m)
8.89ft
(2.71m)
5.66ft
(1.73m)
3.53ft
(1.08m)
3.36ft
(1.02m)
2.28ft
(0.69m)
1.94ft
(0.59m)
1.61ft
(0.49m)
1.32ft
(0.40m)
0.94ft
(0.29m)
9.17ft
(2.80m)
5.86ft
(1.79m)
3.67ft
(1.12m)
3.49ft
(1.06m)
2.38ft
(0.73m)
2.03ft
(0.62m)
1.68ft
(0.51m)
1.38ft
(0.42m)
0.99ft
(0.30m)
9.45ft
(2.88m)
6.07ft
(1.85m)
3.82ft
(1.16m)
3.63ft
(1.11m)
2.48ft
(0.76m)
2.12ft
(0.65m)
1.75ft
(0.53m)
1.44ft
(0.44m)
1.03ft
(0.31m)
9.73ft
(2.97m)
6.28ft
(1.91m)
3.97ft
(1.21m)
3.78ft
(1.15m)
2.58ft
(0.79m)
2.21ft
(0.67m)
1.83ft
(0.56m)
1.5ft
(0.46m)
1.08ft
(0.33m)
MVCD
feet
(meters)
7,000ft
(2133.6m)
MVCD
feet
(meters)
8,000ft
(2438.4m)
MVCD
feet
(meters)
9,000ft
(2743.2m)
MVCD
feet
(meters)
10,000ft
(3048m)
MVCD
feet
(meters)
11,000ft
(3352.8m)
10.01ft
(3.05m)
6.49ft
(1.98m)
4.12ft
(1.26m)
3.92ft
(1.19m)
2.69ft
(0.82m)
2.3ft
(0.70m)
1.91ft
(0.58m)
1.57ft
(0.48m)
1.13ft
(0.34m)
10.29ft
(3.14m)
6.7ft
(2.04m)
4.27ft
(1.30m)
4.07ft
(1.24m)
2.8ft
(0.85m)
2.4ft
(0.73m)
1.99ft
(0.61m)
1.64ft
(0.50m)
1.18ft
(0.36m)
10.57ft
(3.22m)
6.92ft
(2.11m)
4.43ft
(1.35m)
4.22ft
(1.29m)
2.91ft
(0.89m)
2.49ft
(0.76m)
2.07ft
(0.63m)
1.71ft
(0.52m)
1.23ft
(0.37m)
10.85ft
(3.31m)
7.13ft
(2.17m)
4.58ft
(1.40m)
4.37ft
(1.33m)
3.03ft
(0.92m)
2.59ft
(0.79m)
2.16ft
(0.66m)
1.78ft
(0.54m)
1.28ft
(0.39m)
11.13ft
(3.39m)
7.35ft
(2.24m)
4.74ft
(1.44m)
4.53ft
(1.38m)
3.14ft
(0.96m)
2.7ft
(0.82m)
2.25ft
(0.69m)
1.86ft
(0.57m)
1.34ft
(0.41m)
* Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above).
6
The distances in this Table are the minimums required to prevent Flashover; however prudent vegetation maintenance practices dictate that substantially greater distances
will be achieved at time of vegetation maintenance.
FAC-003-2 Technical Reference
47
June 28December 17, 2010
NERC Standard FAC-003-2 Technical Reference
TABLE 1 (CONT.) — Minimum Vegetation Clearance Distances (MVCD)
For Direct Current Voltages
sea level
MVCD feet
(meters)
3,000ft
(914.4m)
Alt.
MVCD feet
(meters)
4,000ft
(1219.2m)
Alt.
MVCD feet
(meters)
5,000ft
(1524m)
Alt.
MVCD feet
(meters)
6,000ft
(1828.8m)
Alt.
MVCD
feet
(meters)
7,000ft
(2133.6m)
Alt.
MVCD
feet
(meters)
(8,000ft
(2438.4m)
Alt.
MVCD
feet
(meters)
9,000ft
(2743.2m)
Alt.
MVCD
feet
(meters)
10,000ft
(3048m)
Alt.
MVCD
feet
(meters)
11,000ft
(3352.8m)
Alt.
±750
13.92ft
(4.24m)
15.07ft
(4.59m)
15.45ft
(4.71m)
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.9ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
±600
10.07ft
(3.07m)
11.04ft
(3.36m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
(13.54ft
4.13m)
±500
7.89ft
(2.40m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
±400
4.78ft
(1.46m)
5.35ft
(1.63m)
5.55ft
(1.69m)
5.75ft
(1.75m)
5.95ft
(1.81m)
6.15ft
(1.87m)
6.36ft
(1.94m)
6.57ft
(2.00m)
6.77ft
(2.06m)
6.98ft
(2.13m)
±250
3.43ft
(1.05m)
4.02ft
(1.23m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5ft
(1.52m)
5.17ft
(1.58m)
( DC )
Nominal Pole
to Ground
Voltage
(kV)
MVCD feet
(meters)
FAC-003-2 Technical Reference
June 28December 17, 2010
48
NERC Standard FAC-003-2 Technical Reference
List of Acronyms and Abbreviations
ANSI
American National Standards Institute
IEEE
Institute of Electrical and Electronics Engineers
IVM
Integrated Vegetation Management
NERC
North American Electric Reliability Corporation
FAC-003-2 Technical Reference
June 28December 17, 2010
49
NERC Standard FAC-003-2 Technical Reference
References
Andrew Hileman, Insulation Coordination for Power System, Marcel Dekker, New York, NY
1999
EPRI, EPRI Transmission Line Reference Book 345 kV and Above, Electric Power Research
Council, Palo Alto, Ca. 1975.
IEEE Std. 516-2003 IEEE Guide for Maintenance Methods on Energized Power Lines
G. Gallet, G. Leroy, R. Lacey, I. Kromer, General Expression for Positive Switching Impulse
Strength Valid Up to Extra Long Air Gaps, IEEE Transactions on Power Apparatus and
Systems, Vol. pAS-94, No. 6, Nov./Dec. 1975.
IEEE Std. 1313.2-1999 (R2005) IEEE Guide for the Application of Insulation Coordination.
2007 National Electric Safety Code
EPRI, HVDC Transmission Line Reference Book, EPRI TR-102764 , Project 2472-03, Final
Report, September 1993
ANSI. 2001. American National Standard for Tree Care Operations – Tree, Shrub, and Other
Plant Maintenance – Standard Practices (Pruning). Part 1. American National Standards
Institute, NY
ANSI. 2006. American National Standard for Tree Care Operations – Tree, Shrub, and Other
Plant Maintenance – Standard Practices (Integrated Vegetation Management a. Electric
Utility Rights-of-way). Part 7. American National Standards Institute, NY.
Cieslewicz, S. and R. Novembri. 2004. Utility Vegetation Management Final Report. Federal
Energy Regulatory Commission. Commissioned to support the Federal Investigation of the
August 14, 2003 Northeast Blackout. Federal Energy Regulatory Commission, Washington,
DC. pg. 39.
Kempter, G.P. 2004. Best Management Practices: Utility Pruning of Trees. International
Society of Arboriculture, Champaign, IL
Miller, R.H. 2007. Best Management Practices: Integrated Vegetation Management. Society of
Arboriculture, Champaign, IL.
Yahner, R.H. and R.J. Hutnik. 2004. Integrated Vegetation Management on an electric
transmission right-of-way in Pennsylvania, U.S. Journal of Arboriculture. 30:295-300
Results-based Initiative Ad Hoc Group. Acceptance Criteria of a Reliability Standard.
FAC-003-2 Technical Reference
June 28December 17, 2010
50
Standards Announcement
Successive Ballot and Non-binding Poll Open
Project 2007-07 – Vegetation Management
February 18 – February 28, 2011
Now available at: https://standards.nerc.net/CurrentBallots.aspx
Project 2007-07 – Vegetation Management
A successive ballot window for FAC-003-2 – Transmission Vegetation Management and its associated
implementation plan is open through 8 p.m. on February 28, 2011.
In addition, members of this ballot pool will be able to vote in a concurrent non-binding poll on the standard’s
Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs). Members who joined the ballot pool to
vote on the standard were automatically entered in a separate pool to participate in the non-binding poll for the
VRFs and VSLs. The non-binding poll will appear in the list of current ballots, and is labeled accordingly.
Instructions
Members of the ballot pool associated with this project may log in and submit their votes from the following
page: https://standards.nerc.net/CurrentBallots.aspx
Background
FAC-003-1 is being revised to address several fill-in-the-blank requirements, directives from Order 693, and
issues raised by stakeholders. An initial ballot closed in July 2010 and achieved a quorum of 86.18 % and an
approval of 65.93 %. The drafting team has posted its consideration of comments received, both those
submitted with a ballot as well as those submitted with a comment form. In addition, a Quality Review was
conducted in November 2010, and the drafting team revised the draft standard and technical reference in
response to comments and input from the Quality Review.
Documents for this project, including clean and redline to the last posted versions of the standard,
implementation plan, and technical reference and an unofficial copy of the questions listed in the comment
forms are posted on the project web page at:
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
Next Steps
Voting results will be posted and announced after the ballot window closes, and the drafting team will consider
all comments, including those submitted with a comment form and those submitted with a ballot.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement
Project 2007-07 Transmission Vegetation Management
Successive Formal Comment Period Open
January 27, 2010 – February 28, 2011
Now available at:
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
A 30-day formal comment period for the proposed standard, FAC-003-2 – Transmission Vegetation
Management, its associated implementation plan, and supporting technical reference paper is now open until 8
p.m. Eastern on February 28, 2011.
Background
FAC-003-1 is being revised to address several fill-in-the-blank requirements, directives from Order 693, and
issues raised by stakeholders. An initial ballot closed in July 2010. The ballot achieved a quorum of 86.18 %
and an approval of 65.93 %. The drafting team has posted its Consideration of Comments received (those
submitted with a ballot as well as those submitted with a comment form). A Quality Review was conducted in
November 2010 and the drafting team has revised the draft standard and technical reference in response to
comments and input from the Quality Review.
Documents for this project, including clean and redline to the last posted versions of the standard,
implementation plan, and technical reference and an unofficial copy of the questions listed in the comment
forms are posted at the following site:
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
Instructions
Please use this electronic form to submit comments on FAC-003-2, its associated implementation plan, and
supporting technical reference paper. If you experience any difficulties in using the electronic form, please
contact Monica Benson at [email protected].
Next Steps – Successive Ballot and Non-binding Poll of VRFs and VSLs
A successive ballot will be conducted during the last 10 days of the formal comment period, from 8 a.m.
Eastern on Friday, February 18, 2011 until 8p.m. Eastern on Monday, February 28, 2011. All members of the
ballot pool must cast a new ballot since the votes and comments from the last ballot will not be carried over. In
addition, members of the ballot pool will need to cast a new opinion on the revised VRFs and VSLs. The
drafting team will consider all comments (those submitted with a comment form, and those submitted with a
ballot or with the non-binding poll) and will determine whether to make additional changes to the standard and
its implementation plan.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate. For more information or assistance, please contact Monica Benson at
[email protected].
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
NERC Standards
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2007-07 Vegetation Management_in
Password
Ballot Period: 2/18/2011 - 2/28/2011
Ballot Type: Initial
Log in
Total # Votes: 241
Register
Total Ballot Pool: 304
Quorum: 79.28 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
79.34 %
Vote:
Ballot Results: The standard will proceed to recirculation ballot.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
90
9
74
22
54
35
0
7
6
7
304
#
Votes
1
0.3
1
1
1
1
0
0.3
0.6
0.5
6.7
#
Votes
Fraction
59
3
45
9
31
18
0
2
6
4
177
Negative
Fraction
0.776
0.3
0.776
0.643
0.838
0.783
0
0.2
0.6
0.4
5.316
Abstain
No
# Votes Vote
17
0
13
5
6
5
0
1
0
1
48
0.224
0
0.224
0.357
0.162
0.217
0
0.1
0
0.1
1.384
2
1
5
4
2
0
0
2
0
0
16
12
5
11
4
15
12
0
2
0
2
63
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Baltimore Gas & Electric Company
Member
Rodney Phillips
Kirit S. Shah
Paul B. Johnson
Andrew Z Pusztai
Robert D Smith
John Bussman
Scott Kinney
Gregory S Miller
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a480c65e-d46a-4f11-9962-b0d59464b192[3/2/2011 9:25:14 AM]
Ballot
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Comments
View
View
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
BC Transmission Corporation
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
CenterPoint Energy
Central Maine Power Company
City of Vero Beach
City Utilities of Springfield, Missouri
Cleco Power LLC
Commonwealth Edison Co.
Consolidated Edison Co. of New York
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
E.ON U.S.
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Gainesville Regional Utilities
GDS Associates, Inc.
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lake Worth Utilities
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Long Island Power Authority
Manitoba Hydro
Metropolitan Water District of Southern
California
MidAmerican Energy Co.
National Grid
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Gordon Rawlings
Joseph S. Stonecipher
Eric Egge
Donald S. Watkins
Paul Rocha
Brian Conroy
Randall McCamish
Jeff Knottek
Danny McDaniel
Daniel Brotzman
Christopher L de Graffenried
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Larry Monday
George S. Carruba
Ralph Frederick Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Luther E. Fair
Claudiu Cadar
Harold Taylor, II
Gordon Pietsch
Ajay Garg
Bernard Pelletier
Ted E Hobson
Michael Gammon
Stan T. Rzad
Walt Gill
Larry E Watt
John W Delucca
Doug Bantam
Robert Ganley
Joe D Petaski
Ernest Hahn
Terry Harbour
Saurabh Saksena
Richard L. Koch
Arnold J. Schuff
Henry G. Masti
David H. Boguslawski
John Canavan
Robert Mattey
Marvin E VanBebber
Douglas G Peterchuck
Michael T. Quinn
Brad Chase
Lawrence R. Larson
Chifong L. Thomas
Mark Sampson
Ronald Schloendorn
John C. Collins
Frank F. Afranji
Richard J Kafka
Larry D. Avery
Brenda L Truhe
Sammy Roberts
Laurie Williams
Kenneth D. Brown
Chad Bowman
Tim Kelley
Robert Kondziolka
Terry L. Blackwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a480c65e-d46a-4f11-9962-b0d59464b192[3/2/2011 9:25:14 AM]
Affirmative
Negative
View
Affirmative
Negative
View
Negative
Affirmative
Negative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
View
View
View
View
View
View
View
View
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
SCE&G
Seattle City Light
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
BC Transmission Corporation
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Ameren Services
American Electric Power
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Blue Ridge Power Agency
Bonneville Power Administration
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Leesburg
Cleco Utility Group
ComEd
Consolidated Edison Co. of New York
Constellation Energy
Consumers Energy
Consumers Power Inc.
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Power Corporation
Gainesville Regional Utilities
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
Manitoba Hydro
Henry Delk, Jr.
Pawel Krupa
Richard McLeon
Dana Cabbell
Horace Stephen Williamson
William G. Hutchison
James L. Jones
Gary W Cox
Noman Lee Williams
Larry Akens
Keith V Carman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Faramarz Amjadi
Chuck B Manning
Kim Warren
Jason L Marshall
Alden Briggs
Gregory Campoli
Tom Bowe
Charles H Yeung
Richard J. Mandes
Bob Reeping
Mark Peters
Raj Rana
Steven Norris
James V. Petrella
Pat G. Harrington
Duane S Dahlquist
Rebecca Berdahl
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Phil Janik
Bryan Y Harper
Bruce Krawczyk
Peter T Yost
Carolyn Ingersoll
David A. Lapinski
Roman Gillen
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F Gildea
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Kevin Querry
Joe McKinney
Lee Schuster
Kenneth Simmons
Anthony L Wilson
R Scott S. Barfield-McGinnis
Sam Kokkinen
Gwen S Frazier
Michael D. Penstone
Charles Locke
Gregory David Woessner
Mace Hunter
Bruce Merrill
Kenneth Silver
Charles A. Freibert
Greg C. Parent
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a480c65e-d46a-4f11-9962-b0d59464b192[3/2/2011 9:25:14 AM]
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
Affirmative
Affirmative
Abstain
View
View
View
Affirmative
Affirmative
Affirmative
View
Affirmative
Affirmative
Affirmative
View
Negative
Affirmative
Abstain
Negative
Affirmative
Negative
Negative
Abstain
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
Affirmative
View
Affirmative
Affirmative
Affirmative
View
Negative
Negative
Affirmative
Affirmative
View
Affirmative
View
View
View
View
View
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
MEAG Power
MidAmerican Energy Co.
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
OTP Wholesale Marketing
PacifiCorp
PECO Energy an Exelon Co.
Platte River Power Authority
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Public Utility District No. 2 of Grant County
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
South Carolina Electric & Gas Co.
Southern California Edison Co.
Springfield Utility Board
Tampa Electric Co.
Turlock Irrigation District
Umatilla Electric Cooperative
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power - Ohio
American Public Power Association
City of Clewiston
City of New Smyrna Beach Utilities
Commission
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Madison Gas and Electric Co.
Modesto Irrigation District
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Wisconsin Energy Corp.
AEP Service Corp.
Amerenue
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Chelan County Public Utility District #1
City of Grand Island
City of Tallahassee
City Water, Light & Power of Springfield
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
Steven Grego
Thomas C. Mielnik
Don Horsley
Steven M. Jackson
John S Bos
Marilyn Brown
Michael Schiavone
William SeDoris
David T. Anderson
David Burke
Ballard Keith Mutters
Bradley Tollerson
John Apperson
Vincent J. Catania
Terry L Baker
Robert Reuter
Jeffrey Mueller
Kenneth R. Johnson
Greg Lange
James Leigh-Kendall
Ken Dizes
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
Hubert C. Young
David Schiada
Jeff Nelson
Ronald L Donahey
Casey Hashimoto
Steve Eldrige
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Allen Mosher
Kevin McCarthy
Timothy Beyrle
David Frank Ronk
Rick Syring
Daniel Herring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Bob C. Thomas
Joseph G. DePoorter
Spencer Tacke
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
Mike Ramirez
Hao Li
Steven R Wallace
Steve McElhaney
Anthony Jankowski
Brock Ondayko
Sam Dwyer
Edward F. Groce
Clement Ma
Francis J. Halpin
John Yale
Jeff Mead
Alan Gale
Karl E. Kohlrus
Wilket (Jack) Ng
James B Lewis
Bob Essex
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a480c65e-d46a-4f11-9962-b0d59464b192[3/2/2011 9:25:14 AM]
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
View
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
View
Abstain
Negative
Negative
Negative
View
Negative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Negative
View
View
View
View
View
View
View
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Dominion Resources, Inc.
Duke Energy
East Kentucky Power Coop.
Entergy Corporation
Exelon Nuclear
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
Public Service Enterprise Group Incorporated
Reedy Creek Energy Services
Sacramento Municipal Utility District
Salt River Project
Seattle City Light
Seminole Electric Cooperative, Inc.
South California Edison Company
South Carolina Electric & Gas Co.
South Mississippi Electric Power Association
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers Northwestern
Division
U.S. Bureau of Reclamation
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Bonneville Power Administration
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Eugene Water & Electric Board
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
New York Power Authority
Northern Indiana Public Service Co.
OTP Wholesale Marketing
PacifiCorp
Mike Garton
Robert Smith
Stephen Ricker
Stanley M Jaskot
Michael Korchynsky
Kenneth Dresner
David Schumann
Cynthia E Sulzer
Donald Gilbert
Scott Heidtbrink
Mike Blough
Dennis Florom
Charlie Martin
S N Fernando
David Gordon
Christopher Schneider
Gerald Mannarino
Michael K Wilkerson
Mahmood Z. Safi
Stacie Hebert
Richard J. Padilla
Sandra L. Shaffer
Gary L Tingley
Tim Hattaway
Mark A Heimbach
Wayne Lewis
Dominick Grasso
Bernie Budnik
Bethany Hunter
Glen Reeves
Michael J. Haynes
Brenda K. Atkins
Ahmad Sanati
Richard Jones
Jerry W Johnson
Scott M. Helyer
George T. Ballew
Barry Ingold
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
View
Negative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
Negative
Affirmative
Affirmative
Karl Bryan
Martin Bauer P.E.
Leonard Rentmeester
Liam Noailles
Edward P. Cox
Brenda S. Anderson
Matthew D Cripps
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Daniel Mark Bedbury
Pulin Shah
Mark S Travaglianti
Thomas E Washburn
Silvia P. Mitchell
Donna Stephenson
Thomas Saitta
Paul Shipps
Eric Ruskamp
Daryn Barker
Daniel Prowse
Thomas Papadopoulos
Joseph O'Brien
Bruce Glorvigen
Gregory D Maxfield
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a480c65e-d46a-4f11-9962-b0d59464b192[3/2/2011 9:25:14 AM]
Affirmative
Affirmative
Affirmative
Negative
Affirmative
View
View
View
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
View
View
View
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
9
9
9
9
9
9
10
10
10
10
10
10
10
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
RRI Energy
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
JDRJC Associates
Pacific Northwest Generating Cooperative
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Public Service Commission of South Carolina
Utah Public Service Commission
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool Regional Entity
Western Electricity Coordinating Council
John T Sturgeon
Peter Dolan
Hugh A. Owen
Trent Carlson
Mike Hummel
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Matt H Bullard
Marjorie S. Parsons
Affirmative
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
John Stonebarger
David F. Lemmons
Roger C Zaklukiewicz
James A Maenner
Jim D. Cyrulewski
Margaret Ryan
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William Mitchell Chamberlain
Affirmative
Affirmative
Affirmative
Donald E. Nelson
Affirmative
Diane J. Barney
Affirmative
Jerome Murray
Philip Riley
Ric Campbell
Dan R Schoenecker
Alan Adamson
Guy V. Zito
Jacquie Smith
Carter B. Edge
Stacy Dochoda
Louise McCarren
Affirmative
Affirmative
Affirmative
Abstain
Negative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a480c65e-d46a-4f11-9962-b0d59464b192[3/2/2011 9:25:14 AM]
View
Affirmative
Legal and Privacy : 609.452.8060 voice : 609.452.9550 fax : 116-390 Village Boulevard : Princeton, NJ 08540-5721
Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
Copyright © 2010 by the North American Electric Reliability Corporation. : All rights reserved.
View
Standards Announcement
Project 2007-07 Transmission Vegetation Management
Successive Ballot Results
Now available at: https://standards.nerc.net/Ballots.aspx
Ballot Results for Revisions to FAC-003
A successive ballot on revisions to FAC-003 - Transmission Vegetation Management, and a concurrent nonbinding poll of associated VRFs and VSLs concluded on February 28, 2011.
Voting statistics are listed below, and the Ballot Results Web page provides a link to the detailed results:
Quorum: 79.28 %
Approval: 79.34 %
Violation Risk Factor (VRF) and Violation Severity Level (VSL) Non-binding Poll Results
For the non-binding poll of VRFs and VSLs, 77% of those who registered to participate provided an opinion;
79% of those who provided an opinion indicated support for the VRFs and VSLs that were proposed.
Next Steps
The drafting team will post its consideration of all comments (those submitted with a comment form, and those
submitted with a ballot).
Background:
FAC-003-1 is being revised to address several fill-in-the-blank requirements, directives from Order 693, and
issues raised by stakeholders. An initial ballot closed in July 2010 and achieved a quorum of 86.18 % and an
approval of 65.93 %. The drafting team has posted its consideration of comments received, both those
submitted with a ballot as well as those submitted with a comment form. In addition, a Quality Review was
conducted in November 2010, and the drafting team revised the draft standard and technical reference in
response to comments and input from the Quality Review.
Further details are available on the project page: http://www.nerc.com/filez/standards/VegetationManagement_Project_2007-7.html
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Non-Binding Poll Results
Non-Binding Poll Project 2007-07 Vegetation Management Non-Binding Poll for VRFs
Name: and VSLs
Poll Period: 2/18/2011 - 2/28/2011
Total # Opinions: 187
Total Ballot Pool: 304
77% of those who registered to participate provided an opinion; 79% of those
Summary Results: who provided an opinion indicated support for the VRFs and VSLs that were
proposed.
Individual Ballot Pool Results
Segment
Organization
Member
Opinion
1
Allegheny Power
Rodney Phillips
Affirmative
1
Ameren Services
Kirit S. Shah
Affirmative
1
American Electric Power
Paul B. Johnson
Affirmative
1
American Transmission Company,
LLC
Andrew Z Pusztai
1
Arizona Public Service Co.
Robert D Smith
1
Associated Electric Cooperative, Inc. John Bussman
1
Avista Corp.
Scott Kinney
Affirmative
1
Baltimore Gas & Electric Company
Gregory S Miller
Affirmative
1
BC Transmission Corporation
Gordon Rawlings
Abstain
1
Beaches Energy Services
Joseph S. Stonecipher
1
Black Hills Corp
Eric Egge
1
Bonneville Power Administration
Donald S. Watkins
1
CenterPoint Energy
Paul Rocha
1
Central Maine Power Company
Brian Conroy
1
City of Vero Beach
Randall McCamish
1
City Utilities of Springfield, Missouri
Jeff Knottek
Comments
Abstain
Abstain
View
Negative
View
Affirmative
View
Negative
Negative
View
Affirmative
1
1
Cleco Power LLC
Danny McDaniel
Negative
1
Commonwealth Edison Co.
Daniel Brotzman
1
Consolidated Edison Co. of New York
Christopher L de
Graffenried
Affirmative
1
Dairyland Power Coop.
Robert W. Roddy
Affirmative
1
Dayton Power & Light Co.
Hertzel Shamash
Affirmative
1
Deseret Power
James Tucker
Affirmative
1
Dominion Virginia Power
Michael S Crowley
1
Duke Energy Carolina
Douglas E. Hils
1
E.ON U.S.
Larry Monday
1
East Kentucky Power Coop.
George S. Carruba
Affirmative
1
Empire District Electric Co.
Ralph Frederick Meyer
Affirmative
1
Entergy Corporation
George R. Bartlett
1
FirstEnergy Energy Delivery
Robert Martinko
1
Florida Keys Electric Cooperative
Assoc.
Dennis Minton
Negative
1
Gainesville Regional Utilities
Luther E. Fair
Abstain
1
GDS Associates, Inc.
Claudiu Cadar
Abstain
1
Georgia Transmission Corporation
Harold Taylor, II
Affirmative
1
Great River Energy
Gordon Pietsch
Affirmative
1
Hydro One Networks, Inc.
Ajay Garg
1
Hydro-Quebec TransEnergie
Bernard Pelletier
1
JEA
Ted E Hobson
1
Kansas City Power & Light Co.
Michael Gammon
Negative
View
1
Keys Energy Services
Stan T. Rzad
Negative
View
1
Lake Worth Utilities
Walt Gill
Negative
View
1
Lakeland Electric
Larry E Watt
View
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
2
1
Lee County Electric Cooperative
John W Delucca
Abstain
1
Lincoln Electric System
Doug Bantam
Affirmative
1
Long Island Power Authority
Robert Ganley
Negative
1
Manitoba Hydro
Joe D Petaski
Affirmative
1
Metropolitan Water District of
Southern California
Ernest Hahn
Abstain
1
MidAmerican Energy Co.
Terry Harbour
1
National Grid
Saurabh Saksena
Abstain
1
Nebraska Public Power District
Richard L. Koch
Abstain
1
New York Power Authority
Arnold J. Schuff
Affirmative
1
New York State Electric & Gas Corp. Henry G. Masti
1
Northeast Utilities
David H. Boguslawski
Affirmative
1
NorthWestern Energy
John Canavan
Affirmative
1
Ohio Valley Electric Corp.
Robert Mattey
Affirmative
1
Oklahoma Gas and Electric Co.
Marvin E VanBebber
1
Omaha Public Power District
Douglas G Peterchuck
Affirmative
1
Oncor Electric Delivery
Michael T. Quinn
Affirmative
1
Orlando Utilities Commission
Brad Chase
Affirmative
1
Otter Tail Power Company
Lawrence R. Larson
1
Pacific Gas and Electric Company
Chifong L. Thomas
1
PacifiCorp
Mark Sampson
1
PECO Energy
Ronald Schloendorn
1
Platte River Power Authority
John C. Collins
Abstain
1
Portland General Electric Co.
Frank F. Afranji
Affirmative
1
Potomac Electric Power Co.
David Thorne
Affirmative
1
PowerSouth Energy Cooperative
Larry D. Avery
Affirmative
Affirmative
Negative
View
Affirmative
3
1
PPL Electric Utilities Corp.
Brenda L Truhe
Abstain
1
Progress Energy Carolinas
Sammy Roberts
Affirmative
1
Public Service Company of New
Mexico
Laurie Williams
Abstain
1
Public Service Electric and Gas Co.
Kenneth D. Brown
1
Public Utility District No. 1 of Chelan
Chad Bowman
County
1
Sacramento Municipal Utility District Tim Kelley
Affirmative
1
Salt River Project
Robert Kondziolka
Affirmative
1
Santee Cooper
Terry L. Blackwell
Affirmative
1
SCE&G
Henry Delk, Jr.
Affirmative
1
Seattle City Light
Pawel Krupa
Affirmative
1
South Texas Electric Cooperative
Richard McLeon
Affirmative
1
Southern California Edison Co.
Dana Cabbell
Affirmative
1
Southern Company Services, Inc.
Horace Stephen
Williamson
1
Southern Illinois Power Coop.
William G. Hutchison
1
Southwest Transmission
Cooperative, Inc.
James L. Jones
Affirmative
1
Southwestern Power Administration
Gary W Cox
Affirmative
1
Sunflower Electric Power Corporation Noman Lee Williams
Affirmative
1
Tennessee Valley Authority
Larry Akens
Affirmative
1
Tri-State G & T Association, Inc.
Keith V Carman
Affirmative
1
Tucson Electric Power Co.
John Tolo
Affirmative
1
United Illuminating Co.
Jonathan Appelbaum
Affirmative
1
Westar Energy
Allen Klassen
1
Western Area Power Administration
Brandy A Dunn
1
Xcel Energy, Inc.
Gregory L Pieper
Affirmative
Abstain
Negative
View
Affirmative
4
2
Alberta Electric System Operator
Mark B Thompson
Abstain
2
BC Transmission Corporation
Faramarz Amjadi
2
Electric Reliability Council of Texas,
Inc.
Chuck B Manning
2
Independent Electricity System
Operator
Kim Warren
2
Midwest ISO, Inc.
Jason L Marshall
2
New Brunswick System Operator
Alden Briggs
2
New York Independent System
Operator
Gregory Campoli
2
PJM Interconnection, L.L.C.
Tom Bowe
2
Southwest Power Pool
Charles H Yeung
3
Alabama Power Company
Richard J. Mandes
Affirmative
3
Allegheny Power
Bob Reeping
Affirmative
3
Ameren Services
Mark Peters
Affirmative
3
American Electric Power
Raj Rana
3
APS
Steven Norris
3
Atlantic City Electric Company
James V. Petrella
Affirmative
3
BC Hydro and Power Authority
Pat G. Harrington
Abstain
3
Blue Ridge Power Agency
Duane S Dahlquist
Negative
3
Bonneville Power Administration
Rebecca Berdahl
Affirmative
3
City of Bartow, Florida
Matt Culverhouse
Negative
3
City of Clewiston
Lynne Mila
Negative
3
City of Green Cove Springs
Gregg R Griffin
3
City of Leesburg
Phil Janik
Negative
3
Cleco Utility Group
Bryan Y Harper
Negative
3
ComEd
Bruce Krawczyk
Affirmative
View
Affirmative
Abstain
Affirmative
Abstain
Abstain
5
3
Consolidated Edison Co. of New York Peter T Yost
Affirmative
3
Constellation Energy
Carolyn Ingersoll
Affirmative
3
Consumers Energy
David A. Lapinski
Negative
View
3
Consumers Power Inc.
Roman Gillen
3
Cowlitz County PUD
Russell A Noble
Negative
View
3
Delmarva Power & Light Co.
Michael R. Mayer
Affirmative
3
Detroit Edison Company
Kent Kujala
Affirmative
3
Dominion Resources Services
Michael F Gildea
3
Duke Energy Carolina
Henry Ernst-Jr
Affirmative
3
East Kentucky Power Coop.
Sally Witt
Affirmative
3
Entergy
Joel T Plessinger
Affirmative
3
FirstEnergy Solutions
Kevin Querry
Affirmative
3
Florida Municipal Power Agency
Joe McKinney
3
Florida Power Corporation
Lee Schuster
3
Gainesville Regional Utilities
Kenneth Simmons
3
Georgia Power Company
Anthony L Wilson
Affirmative
3
Georgia System Operations
Corporation
R Scott S. BarfieldMcGinnis
Affirmative
3
Great River Energy
Sam Kokkinen
Affirmative
3
Gulf Power Company
Gwen S Frazier
3
Hydro One Networks, Inc.
Michael D. Penstone
3
Kansas City Power & Light Co.
Charles Locke
Negative
3
Kissimmee Utility Authority
Gregory David
Woessner
Negative
3
Lakeland Electric
Mace Hunter
Affirmative
3
Lincoln Electric System
Bruce Merrill
Affirmative
3
Los Angeles Department of Water &
Abstain
Affirmative
View
View
Kenneth Silver
6
Power
3
Louisville Gas and Electric Co.
Charles A. Freibert
3
Manitoba Hydro
Greg C. Parent
Negative
3
MEAG Power
Steven Grego
Affirmative
3
MidAmerican Energy Co.
Thomas C. Mielnik
Affirmative
3
Mississippi Power
Don Horsley
Affirmative
3
Municipal Electric Authority of
Georgia
Steven M. Jackson
Affirmative
3
Muscatine Power & Water
John S Bos
3
New York Power Authority
Marilyn Brown
Affirmative
3
Niagara Mohawk (National Grid
Company)
Michael Schiavone
Affirmative
3
Northern Indiana Public Service Co.
William SeDoris
Negative
3
Ocala Electric Utility
David T. Anderson
Negative
3
Orange and Rockland Utilities, Inc.
David Burke
3
Orlando Utilities Commission
Ballard Keith Mutters
3
OTP Wholesale Marketing
Bradley Tollerson
3
PacifiCorp
John Apperson
3
PECO Energy an Exelon Co.
Vincent J. Catania
3
Platte River Power Authority
Terry L Baker
Negative
3
Potomac Electric Power Co.
Robert Reuter
Abstain
3
Public Service Electric and Gas Co.
Jeffrey Mueller
Affirmative
3
Public Utility District No. 1 of Chelan
Kenneth R. Johnson
County
3
Public Utility District No. 2 of Grant
County
3
Sacramento Municipal Utility District James Leigh-Kendall
3
Salmon River Electric Cooperative
Greg Lange
Abstain
Affirmative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Ken Dizes
7
3
Salt River Project
John T. Underhill
Affirmative
3
San Diego Gas & Electric
Scott Peterson
Affirmative
3
Santee Cooper
Zack Dusenbury
Affirmative
3
Seattle City Light
Dana Wheelock
Affirmative
3
South Carolina Electric & Gas Co.
Hubert C. Young
3
Southern California Edison Co.
David Schiada
3
Springfield Utility Board
Jeff Nelson
3
Tampa Electric Co.
Ronald L Donahey
3
Turlock Irrigation District
Casey Hashimoto
3
Umatilla Electric Cooperative
Steve Eldrige
3
Xcel Energy, Inc.
Michael Ibold
Abstain
4
Alliant Energy Corp. Services, Inc.
Kenneth Goldsmith
Abstain
4
American Municipal Power - Ohio
Kevin Koloini
4
American Public Power Association
Allen Mosher
4
City of Clewiston
Kevin McCarthy
Negative
4
City of New Smyrna Beach Utilities
Commission
Timothy Beyrle
Negative
4
Consumers Energy
David Frank Ronk
4
Cowlitz County PUD
Rick Syring
4
Detroit Edison Company
Daniel Herring
4
Florida Municipal Power Agency
Frank Gaffney
4
Fort Pierce Utilities Authority
Thomas W. Richards
4
Georgia System Operations
Corporation
Guy Andrews
4
Illinois Municipal Electric Agency
Bob C. Thomas
Abstain
4
Madison Gas and Electric Co.
Joseph G. DePoorter
Abstain
4
Modesto Irrigation District
Spencer Tacke
Affirmative
Abstain
Abstain
Negative
View
Negative
View
Abstain
Affirmative
Affirmative
8
4
Ohio Edison Company
Douglas Hohlbaugh
Affirmative
View
4
Old Dominion Electric Coop.
Mark Ringhausen
Negative
4
Public Utility District No. 1 of
Douglas County
Henry E. LuBean
Affirmative
4
Sacramento Municipal Utility District Mike Ramirez
Affirmative
4
Seattle City Light
Hao Li
Affirmative
4
Seminole Electric Cooperative, Inc.
Steven R Wallace
Affirmative
4
South Mississippi Electric Power
Association
Steve McElhaney
4
Wisconsin Energy Corp.
Anthony Jankowski
5
AEP Service Corp.
Brock Ondayko
Affirmative
5
Amerenue
Sam Dwyer
Affirmative
5
Avista Corp.
Edward F. Groce
Affirmative
5
BC Hydro and Power Authority
Clement Ma
5
Bonneville Power Administration
Francis J. Halpin
5
Chelan County Public Utility District
#1
John Yale
Abstain
5
City of Grand Island
Jeff Mead
Abstain
5
City of Tallahassee
Alan Gale
Abstain
5
City Water, Light & Power of
Springfield
Karl E. Kohlrus
5
Consolidated Edison Co. of New York Wilket (Jack) Ng
5
Consumers Energy
James B Lewis
Negative
View
5
Cowlitz County PUD
Bob Essex
Negative
View
5
Dominion Resources, Inc.
Mike Garton
5
Duke Energy
Robert Smith
5
East Kentucky Power Coop.
Stephen Ricker
Affirmative
5
Entergy Corporation
Stanley M Jaskot
Affirmative
Abstain
Abstain
Affirmative
View
Affirmative
Abstain
9
5
Exelon Nuclear
Michael Korchynsky
Affirmative
5
FirstEnergy Solutions
Kenneth Dresner
Affirmative
5
Florida Municipal Power Agency
David Schumann
Negative
5
Great River Energy
Cynthia E Sulzer
5
JEA
Donald Gilbert
5
Kansas City Power & Light Co.
Scott Heidtbrink
5
Kissimmee Utility Authority
Mike Blough
5
Lincoln Electric System
Dennis Florom
5
Louisville Gas and Electric Co.
Charlie Martin
5
Manitoba Hydro
S N Fernando
Affirmative
5
Massachusetts Municipal Wholesale
Electric Company
David Gordon
Abstain
5
MidAmerican Energy Co.
Christopher Schneider
Affirmative
5
New York Power Authority
Gerald Mannarino
Affirmative
5
Northern Indiana Public Service Co.
Michael K Wilkerson
5
Omaha Public Power District
Mahmood Z. Safi
5
Otter Tail Power Company
Stacie Hebert
5
Pacific Gas and Electric Company
Richard J. Padilla
Affirmative
5
PacifiCorp
Sandra L. Shaffer
Affirmative
5
Portland General Electric Co.
Gary L Tingley
Affirmative
5
PowerSouth Energy Cooperative
Tim Hattaway
Affirmative
5
PPL Generation LLC
Mark A Heimbach
5
Progress Energy Carolinas
Wayne Lewis
Affirmative
5
Public Service Enterprise Group
Incorporated
Dominick Grasso
Affirmative
5
Reedy Creek Energy Services
Bernie Budnik
Affirmative
5
Sacramento Municipal Utility District Bethany Hunter
View
Negative
Affirmative
Abstain
Affirmative
10
5
Salt River Project
Glen Reeves
Affirmative
5
Seattle City Light
Michael J. Haynes
Affirmative
5
Seminole Electric Cooperative, Inc.
Brenda K. Atkins
Affirmative
5
South California Edison Company
Ahmad Sanati
5
South Carolina Electric & Gas Co.
Richard Jones
5
South Mississippi Electric Power
Association
Jerry W Johnson
5
Tenaska, Inc.
Scott M. Helyer
5
Tennessee Valley Authority
David Thompson
Affirmative
5
Tri-State G & T Association, Inc.
Barry Ingold
Affirmative
5
U.S. Army Corps of Engineers
Melissa Kurtz
Affirmative
5
U.S. Bureau of Reclamation
Martin Bauer P.E.
5
Wisconsin Public Service Corp.
Leonard Rentmeester
5
Xcel Energy, Inc.
Liam Noailles
6
AEP Marketing
Edward P. Cox
Affirmative
6
Bonneville Power Administration
Brenda S. Anderson
Affirmative
6
Cleco Power LLC
Matthew D Cripps
6
Consolidated Edison Co. of New York Nickesha P Carrol
6
Constellation Energy Commodities
Group
Brenda Powell
6
Dominion Resources, Inc.
Louis S. Slade
Abstain
6
Duke Energy Carolina
Walter Yeager
Affirmative
6
Entergy Services, Inc.
Terri F Benoit
Affirmative
6
Eugene Water & Electric Board
Daniel Mark Bedbury
Affirmative
6
Exelon Power Team
Pulin Shah
Affirmative
6
FirstEnergy Solutions
Mark S Travaglianti
Affirmative
View
6
Florida Municipal Power Pool
Thomas E Washburn
Negative
View
Abstain
View
Negative
Affirmative
View
11
6
Florida Power & Light Co.
Silvia P. Mitchell
Abstain
6
Great River Energy
Donna Stephenson
6
Kansas City Power & Light Co.
Thomas Saitta
Negative
6
Lakeland Electric
Paul Shipps
Negative
6
Lincoln Electric System
Eric Ruskamp
6
Louisville Gas and Electric Co.
Daryn Barker
6
Manitoba Hydro
Daniel Prowse
6
New York Power Authority
Thomas Papadopoulos
6
Northern Indiana Public Service Co.
Joseph O'Brien
6
OTP Wholesale Marketing
Bruce Glorvigen
6
PacifiCorp
Gregory D Maxfield
6
Progress Energy
James Eckelkamp
6
PSEG Energy Resources & Trade LLC Peter Dolan
6
Public Utility District No. 1 of Chelan
Hugh A. Owen
County
6
RRI Energy
Trent Carlson
6
Salt River Project
Mike Hummel
6
Santee Cooper
Suzanne Ritter
Affirmative
6
Seattle City Light
Dennis Sismaet
Affirmative
6
Seminole Electric Cooperative, Inc.
Trudy S. Novak
Affirmative
6
South Carolina Electric & Gas Co.
Matt H Bullard
6
Tennessee Valley Authority
Marjorie S. Parsons
6
Western Area Power Administration John Stonebarger
UGP Marketing
6
Xcel Energy, Inc.
View
Affirmative
Affirmative
Negative
Affirmative
View
Affirmative
Affirmative
David F. Lemmons
8
Roger C Zaklukiewicz
Affirmative
8
James A Maenner
Affirmative
12
8
JDRJC Associates
Jim D. Cyrulewski
8
Pacific Northwest Generating
Cooperative
Margaret Ryan
8
Power Energy Group LLC
Peggy Abbadini
8
Utility Services, Inc.
Brian Evans-Mongeon
Abstain
8
Volkmann Consulting, Inc.
Terry Volkmann
Abstain
9
California Energy Commission
William Mitchell
Chamberlain
Affirmative
9
Commonwealth of Massachusetts
Department of Public Utilities
Donald E. Nelson
Affirmative
9
National Association of Regulatory
Utility Commissioners
Diane J. Barney
Affirmative
9
Oregon Public Utility Commission
Jerome Murray
Affirmative
9
Public Service Commission of South
Carolina
Philip Riley
Affirmative
9
Utah Public Service Commission
Ric Campbell
Affirmative
10
Midwest Reliability Organization
Dan R Schoenecker
10
New York State Reliability Council
Alan Adamson
Affirmative
10
Northeast Power Coordinating
Council, Inc.
Guy V. Zito
Affirmative
View
10
ReliabilityFirst Corporation
Anthony E Jablonski
Negative
View
10
SERC Reliability Corporation
Carter B. Edge
10
Southwest Power Pool Regional
Entity
Stacy Dochoda
10
Western Electricity Coordinating
Council
Louise McCarren
Abstain
Abstain
Affirmative
13
Individual or group. (41 Responses)
Name (27 Responses)
Organization (27 Responses)
Group Name (14 Responses)
Lead Contact (14 Responses)
Contact Organization (14 Responses)
Question 1 (40 Responses)
Question 1 Comments (41 Responses)
Question 2 (40 Responses)
Question 2 Comments (41 Responses)
Question 3 (40 Responses)
Question 3 Comments (41 Responses)
Question 4 (40 Responses)
Question 4 Comments (41 Responses)
Question 5 (40 Responses)
Question 5 Comments (41 Responses)
Individual
Jennifer Wright
SDG&E
Yes
Yes
Yes
Yes
Yes
Individual
JAMES SMITH
ASSET MANAGEMENET
Yes
Yes
Yes
Yes
Yes
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie (NCR07112)
Yes
Yes
Yes
Yes
No
The minimum frequency of Vegetation Inspection should be based upon an average growth rates of smaller
regions than all North America. Example, above the latitude of about 50 degrees North, the vegetation growth rates
is limited. We think that Vegetation Inspection frequency should be relaxed to 3 years for those areas in Canada.
As indicator of the minimum frequency requested in R6, we suggest to use a global vegetation index like the
Normalized Difference Vegetation Index (NDVI). The NDVI has been in use for many years to measure the vigor of
vegetation growth among other things. http://earthobservatory.nasa.gov/Features/MeasuringVegetation/
Individual
Michael Gammon
Kansas City Power & Light
Yes
No
These proposed Requirements, Measures and Violation Severity Levels as written do not give credit to the
Transmission Owners for effectively monitoring their systems and taking appropriate actions in regard to vegetation
clearing. Why does it make sense to punish and penalize a Transmission Owner for discovering an encroachment
when they take the appropriate actions to remedy the condition before any facility outage occurs that results in
compromising the reliability of the Bulk Electric System? These Requirements, Measures and VSL’s should
recognize the good practices of effective response to a vegetation condition and penalize ineffective response.
Recommend the SDT consider including appropriate language to recognize effective remedial actions by
Transmission Owners and by doing so, recognize effective efforts instead of punishing them. In addition, proving
encroachments have not occurred will pose audit challenges in determining that encroachments have not occurred
for the Auditors as well as Registered Entities. If no encroachments occur, then there is nothing to report or record.
This is a weak platform to stand compliance on. Facility interruption events caused by vegetation contacts is
definitively measurable and recordable. Recommend the SDT reconsider the concept of compliance with FAC-003
on the basis of sustained outages and remove the references regarding encroachments only. Recommend the
SDT remove the LOWER VSL language from Requirements R1 and R2 and revise the Requirements and
Measures to reflect the same.
Yes
Yes
No
1) R7 states “Each Transmission Owner shall complete 100% of its annual vegetation work plan...”. We suggest to
be consistent with all other sections of the rule that it should read, “Each Transmission Owner shall complete 100%
of its annual vegetation work plan for all applicable lines...”. Otherwise, leaves room for interpretation to include all
lines including those not defined as applicable. Also require these same revisions to row R7 of the table “Time
Horizons, Violation Risk Factors, and Violation Severity Levels”. 2) In the “Additional Compliance Information”
section Categories 1, 2, and 4 are each defined to have an A & B component to recognize the severity level
difference for “applicable transmission lines” identified versus not identified “as an element of an IROL or Major
WECC Transfer Path”. However, Category 3 does not separate these two scenarios however it appears that the
same distinction should apply. Additional comments: Vegetation Inspection Definition Recommend the SDT
consider removing the conditional language, “that are likely to pose a hazard to the line(s) prior to the next”.
Vegetation inspections are not dependent on a predisposed condition of vegetation. Suggest the SDT remove that
phrase and consider the following definition: The systematic examination of vegetation conditions on a maintained
transmission line Right-of-Way under the Transmission Owner’s control under a planned maintenance or inspection
which may be combined with a general line inspection.
Individual
Joe Petaski
Manitoba Hydro
Yes
Yes
Yes
Yes
Yes
Group
SERC Vegetation Management sub-committee
Joe Spencer
SERC Reliability Corporation
No
We agree with the proposed definition as a replacement for active transmission ROW, however, in a review of
NERC standards, the term ROW is not used except in FAC-003. It is therefore recommended that the term be
removed from the NERC glossary.
Yes
Yes
Yes
Yes
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
Arizona Public Service Company
Yes
No
This is a reliability standard and the TO should know what its clearance needs are at all rated conditions, especially
considering today’s technology. If the TO manages to this standard there is no need for R1 and R2.
No
The TO should be managing for reliability. The system is not static, like vegetation it moves and changes over time
and that fluctuation should be taken into account to maintain reliability at all rated conditions.
No
The TVMP shall demonstrate the TO’s ability to manage the system at all rated conditions to maintain reliability.
Yes
Individual
Weston Davis
Central Maine Power Company - IberdrolaUSA
No
The definition does not define transmission owner responsibility for areas covered by “danger tree” rights. This area
is outside the maintained width but for economic and social reasons the transmission owner can not remove all
danger trees. Utilities have procedures in place to remove the hazard trees but it is not practical to remove all
danger trees that have the potential to violate the MVCD should they fail. This area of the definition requires
clarification.
Yes
Yes
Yes
Yes
Group
Hydro One Networks
Sasa Maljukan
Hydro One Networks Inc.
No
The revised definition of ROW is unclear in regards to the application of standards and/or historic records as a
means of determining ROW width; is it necessary for a TO to select one method to apply in all cases, or can each
span be treated in the manner deemed most appropriate by the TO? Additionally “blowout Standard” has not been
defined in the document or in the technical paper, and therefore it is not clear exactly how this method would be
applied, and subsequently defended under scrutiny.
Yes
Yes
Yes
Yes
Group
Salt River Project
Cynthia Oder
Cynthia Oder
Yes
Yes
Yes
Yes
Yes
Individual
Gordon Rawlings
BC Hydro
Yes
Yes
Yes
Yes
You could also include the term “maintenance standards”.
Yes
You could also include other documentation such as monthly financial and program variance reports. Additional
Comments Table 1: R6 definitions could be clearer. Suggested clarification: VSL Lower – Greater than 95% of
annual inspections complete but less than 100% complete. VSL Moderate – Greater than 90 % of annual
inspections complete but less than 95% complete VSL High – Greater than 85% of annual inspections complete
but less than 90% complete VSL Severe – Less than 85% of annual inspections completed Table 1 R7 definitions
could be clearer. Suggested clarification: VSL Lower – Greater than 95% of annual work plan complete but less
than 100% complete. VSL Moderate – Greater than 90 % of annual work plan complete but less than 95%
complete VSL High – Greater than 85% of annual work plan complete but less than 90% complete VSL Severe –
Less than 85% of annual work plan completed Table 2: This table includes a number of common nominal system
voltages vs MVCD distances by altitude. However, some utilities have other non-standard voltages, in our case 287
kV, which forms a significant part of their system. It may be worthwhile for the standard to state what a utility should
follow when a standard voltage class is not present – i.e. go to the next higher voltage MVCD if a particular voltage
isn’t in the table, or direct the utility to do its own Gallett Equation calcuations for their unique voltage class.
Otherwise, different utilities may create a non-standard solution that wouldn’t address the risk.
Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
No
There was no definition of ROW listed in FAC-003-1. The revised definition of ROW in FAC-003-2 is unclear
regarding the application of standards and/or historic records as a means of determining ROW width. Is it
necessary for a TO to select one method to apply in all cases, or can each span be treated in the manner deemed
most appropriate by the TO? “Blowout standard” has not been defined in the document, technical paper, or NERC
Glossary and it is not clear what this method is, and exactly how it would be applied. It could not be defended
under scrutiny. It is still unclear whether Danger Tree rights are included in this definition. In the NERC Glossary of
Terms, Right-of-Way (ROW) is defined as “A corridor of land on which electric lines may be located. The
Transmission Owner may own the land in fee, own an easement, or have certain franchise, prescription, or license
rights to construct and maintain lines.” Propose keeping this definition. Is encroachment into the MVCD, or (MVCD
plus additional distance as defined by the TO)? MVCD, as specified within the body of FAC-003-2 "is a calculated
minimum distance stated in feet (meters) to prevent flashover between conductors and vegetation, for various
altitudes and operating voltages." MVCD should be “formally” defined in this document, and the NERC Glossary.
Can a list/database be established in 2011 that lists the widths for the pre-2007 vegetation management records?
Yes
Yes
Yes
No
There is no percentage language in M7. Is it R7 that is being referred to?
Individual
Andrew Pusztai
American Transmission Company, LLC
Yes
Yes
Yes
Yes
Yes
Individual
Thad Ness
American Electric Power
Yes
No
American Electric Power believes that the phrase "arboricultural activities or horticultural or agricultural activities"
was mistakenly introduced into Footnotes 2 and 4, and should be deleted from both footnotes. If the phrase
remains in the Standard, it may empower orchard growers, landowners and others to plant trees on the right of way
and challenge Transmission Owners' rights to perform maintenance on the presumption that the standard will
exempt the TO from violating the outage or encroachment requirements.
No
For increased clarity, AEP offers the following change to the second paragraph of M1, as well as the second
paragraph of M2. The original text “If a later confirmation of a Fault by the Transmission Owner shows that a
vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this shall be considered
the equivalent of a Real-time observation” should be replaced with ““If a later confirmation of a Fault by the
Transmission Owner shows that a vegetation encroachment within the MVCD has occurred from vegetation
growing into or blowing together with the conductor within the ROW, this shall be considered the equivalent of a
Real-time observation. A brief encroachment caused by falling vegetation passing through the MVCD is not
considered an encroachment in this requirement”.
Yes
Yes
Individual
William Rees
Baltimore Gas and Electric Co.
Yes
Yes
No
M1 & M2 bullet: “Real-time observation of any MVCD encroachments.” implies that real-time observation of
vegetation encroachment ensures reliable operation the Bulk Electric System. The reliability standard objective
states; “To improve the reliability of the electric Transmission system by preventing those vegetation related
outages that could lead to Cascading.” However, real time observation of current operating conditions provides no
assurance that vegetation will not lead to outages since it doesn’t take into consideration the full conductor range of
motion including maximum sag. BGE recommends removing the language. If an inspector finds vegetation
encroaching into the MVCD during a visual inspection he / she should immediately initiate an Immediate Threat
Notification. Therefore, this measure has no value.
Yes
Yes
Individual
Jason Regg
TVA
No
I suggest that "arboricultural activities or horticultural or agricultural activities be removed and changed to
installation, removal or digging of vegetation.
Yes
Yes
Yes
No
I suggest that footnote 4 be changed by removing the reference to arbicultural, horticultural or agricultural activities.
Individual
Michael Schiavone
Niagara Mohawk Power Corporation (dba National Grid)
No
It is still unclear whether Danger Tree rights are included in this definition. Additional question: Can we establish a
list/database in 2011 stating the widths for the pre-2007 vegetation management records? There is no definition of
ROW listed in FAC-003-1, however in the NERC Glossary of Terms, Right-of-Way (ROW) is defined as “A corridor
of land on which electric lines may be located. The Transmission Owner may own the land in fee, own an
easement, or have certain franchise, prescription, or license rights to construct and maintain lines.” We propose
keeping this definition.
Yes
Yes
Yes
No
There is currently no percentage language in M7. If they are referring to R7, then YES it is adequate.
Individual
Michael Pakeltis
CenterPoint Energy
No
CenterPoint Energy agrees with the removal of “Active Transmission Line ROW” as a defined term. The change in
the NERC Glossary definition for Right-of-Way (ROW) alone, however, does not address all of the remaining
interpretation issues within the Standard that still exist. The following issues still require resolution: 1. The “force
majeure” was moved from the Applicability section to a footnote, and is no longer an encompassing exception for
each Requirement. Therefore, the “force majeure” footnote needs to be applied not only to R1, R2, R6, and R7 but
also R4 and R5. For R4, notification to the control center would likely be restricted during a natural disaster. For
R5, correction action by the control center may not be possible during a natural disaster. 2. The exception for
applicability beyond the “Rating and all Rated Electrical Operating Conditions” should be included not only in R1,
R2, and R3, but also R5 and R7. For R5 and R7, the encroachment into the MVCD should consider whether the
line is operating within its design limits. 3. The use of the term “Fault” in M1 and M2 should be revised to
“Sustained Outage”. A “Fault” can be associated with a Momentary Outage or a Sustained Outage. The scope of
R1 and R2 is specific to Sustained Outages only. The Periodic Data Submittal is specific to Sustained Outages
only as well. If a later confirmation of a “Fault” by the Transmission Owner indicates that a vegetation
encroachment into the MVCD was due to a fall-in from inside the ROW, yet caused only a Momentary Outage, the
Transmission Owner would be in violation of R1 because M1 considers it to be the equivalent of a Real-time
observation. The current scope of the Standard is not intended to include Momentary Outages. If it was, the
Periodic Data Submittal would capture this type of outage, which it does not. 4. In the Introduction Section 5 Background, fall-ins are characterized as “statistically intermittent” and “these types of events are highly unlikely to
cause large-scale grid failures”. CenterPoint Energy agrees and therefore recommends that fall-ins be excluded
from the Requirements R1, R2, and Periodic Data Submittal of outages. This would negate the need for
determining the limits of the ROW, thus simplifying the Standard to a great margin while not sacrificing the
emphasis of the Standard. The Draft 5 Background Information states the criteria for developing a results-based
reliability standard such that “each requirement should identify a clear and measurable expected outcome.” When
the determination of the limits of the ROW goes beyond the interpretation of the legal limits of the ROW, it adds a
level of complexity that may be unclear and not deterministically measurable. 5. For R6, CenterPoint Energy
believes the detailed rationale and studies used for the determination of the required one year inspection cycle
should be included in the Guidelines and Technical Basis. The explanation provided in the Rationale that it is
“based upon average growth rates across North America and on common utility practice” are unfounded and
arbitrary without a specific reference to a North American study. 6. R7 contains the phrase, “provided they do not
put the transmission system at risk of a vegetation encroachment”. CenterPoint Energy recommends this phrase
be replaced with the more specific terminology used in the Rationale for R7 and R3: “provided they do not allow
encroachment of vegetation into the MVCD.” 7. CenterPoint Energy believes the Periodic Data Submittal should be
clarified as to the specific conditions under which Sustained Outages are reported. There is a reference to footnote
2 regarding the exclusion for the “force majeure”; however, the exclusion for lines operating outside their design
limits as mentioned in R1, R2, and R3 is missing. CenterPoint Energy believes the wording should be changed to
include all applicable exclusions for added clarity and recommends the following wording: “The Transmission
Owner will submit a quarterly report to its Regional Entity, or Regional Entity’s designee, identifying all Sustained
Outages of applicable transmission lines operating within their Facility Rating and all Rated Electrical Operating
Conditions as determined by the Transmission Owner to have been caused by vegetation, except as excluded in
footnote 2, which includes as a minimum, the following:” 8. The Guidelines and Technical Basis and the Technical
Reference with the Gallet Equation should be combined into one document as a supplement to the Standard to
avoid duplication in wording and misinterpretation of context. 9. The Guideline and Technical Basis under
Requirement R6 refers to the “percentage of the required ROW inspections completed” and should be revised to
match the wording of R6 and the VSL for R6 as the “percentage of applicable transmission line inspections
completed.” 10. CenterPoint Energy agrees that the Rationale test boxes should be deleted from the Standard and
applicable explanatory text be included within the Guidelines and Technical Basis. 11. The Guidelines and
Technical Basis should contain specific examples for determining if a fall-in is considered inside or outside the
ROW. 12. CenterPoint Energy recommends modifying the Technical Reference section regarding “Selecting a
Maintenance Approach” to delete the sentences beginning with, “If constraints cannot be overcome and if design
clearances are sufficient…” and continuing through to, “identified early for rectification.” This example may lead the
public to inappropriately ask the utilities for exceptions to allow vegetation beneath the transmission lines, and it
also does not address the dynamics of future modifications to the transmission lines (e.g. higher operating
temperatures or new conductors) that may necessitate reduced clearances to ground, thus requiring removal of
now mature vegetation. The example should not be included in a Standard intended to reduce vegetation risks to
the transmission system. It is also in conflict with later statements in the Technical Reference regarding Set
Objectives which emphasize maintaining access and clear lines of sight. 13. In general, CenterPoint Energy
strongly believes the proposed FAC-003-2 has gone far beyond what was contemplated by the Commission in
FERC Order 693. The Commission's determination dealt with the following areas: (1) applicability; (2) inspection
cycles; and (3) minimum clearances on National Forest Service lands. For instance, in Paragraph 729, the
Commission states, “As proposed in the NOPR, the Commission approves Reliability Standard FAC-003-1 with no
proposed modification on the issue of clearances. The Commission reaffirms its interpretation that FAC-003-1
requires sufficient clearances to prevent outages due to vegetation management practices under all applicable
conditions….” Rewriting the minimum clearances introduces a new set of confusing definitions, and further burdens
the Transmission Owners with new documentation requirements while providing little, if any, benefit when
compared to the Clearance 2 concept in the existing Standard. A preferred approach would be to incorporate the
following few items into the existing Standard FAC-003-1: (1) the RC versus the RRO; (2) the designation of a
specific inspection frequency; (3) the Gallet equation; and (4) the applicability to National Forest Service lands.
Yes
Yes
Yes
No
CenterPoint Energy could not find any reference to an example percentage complete calculation for the annual
work plan in the Standard for M7, in the Guideline and Technical Basis for M7, nor in the Technical Reference for
M7. There was such an example for M6 which was helpful. CenterPoint Energy recommends such an example be
included for M7.
Individual
Greg Rowland
Duke Energy
Yes
Yes
We agree with the drafting team’s approach, and also agree with reinstating reporting of Category 3 (Fall-ins from
outside the ROW) in the Additional Compliance Information section. The SDT responded to comments submitted
with the last ballot that: “Zero tolerance for vegetation caused outages is a stated goal of FERC and NERC as it
relates to this standard. This policy is part of FAC-003-1 and in concept did not change with the proposed version.
The SDT recognizes this concern and has developed gradation taking into account line criticality in VRF’s and type
of outage not contained in the current version FAC-003-1. Finally, it is also important to note that each and every
incident or potential violation is investigated and addressed based on the specific circumstances surrounding the
particular event. These investigations should necessarily take into consideration and recognize the utility's
individual efforts in responding to an encroachment situation.” In addition, we believe that clarifying changes need
to be made to footnotes 2 and 4. Clarify footnote 2 by removing the phrase “arboricultural activities or horticultural
or agricultural activities” and replacing it with the phrase “installation of”. Similarly, clarify footnote 4 by removing
the phrase “arboricultural, horticultural or agricultural activities”, and replacing it with the phrase “or human activities
such as installation, or removal or digging of vegetation.”
Yes
However, this change was not completely made in paragraph five of the Guideline and Technical Basis document.
There the phrase “an investigation” should be replaced by the phrase “a later confirmation”
Yes
Yes
Group
Platte River Power Authority Substation Maintenance Group
Deborah Schaneman
Platte River Power Authority
No
We agree that the ROW width in no case exceeds the TO’s legal rights but may be less. We do not agree that the
revised NERC Glossary definition for Right-of-Way addresses paragraph 734 of FERC Order 693 “that rights-ofway be defined to encompass the required clearance areas instead of the corresponding legal rights, and that the
standards should not require clearing the entire right-of-way when the required clearance for an existing line does
not take up the entire right-of-way”. The engineering or construction standards for establishing the width of the
corridor outlined in the definition are in most cases not useful. We will continue to rely on our easements and legal
rights with this definition. We believe the Active Transmission Line ROW definition in the previous version more
clearly addressed paragraph 734 of FERC Order 693.
Yes
Yes
Yes
Yes
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Yes
Yes
Yes
Yes
Yes
Group
Bonneville Power Administration
Denise Koehn
BPA, Transmission Reliability Program
Yes
Yes
BPA prefers the stratified levels of violation severity presented in the table for R1 and R2. Foot note #2 on page 8
needs to be clarified with respect to arboricultural activities or horticultural or agricultural activities. What specifically
does this phrase refer to? Foot note #4 on page 12 needs to be clarified with respect to arboricultural activities or
horticultural or agricultural activities. What specifically does this phrase refer to?
Yes
Yes
The TO procedures / policies and specifications shall demonstrate the TO’s ability to manage the system at all
rated conditions to maintain reliability. BPA believes that the intent is clear, but the fundamental approach of using
the MVCD (table 2) to manage a vegetation program is still problematic. These values are flashover distances and
are way too close. This is acknowledged in a footnote to table 2 but no identification of allowable buffers/distances
between energized phase conductors at rated temperatures and vegetation is discussed (this is left up the
transmission owners). Clarity is needed on this topic. Setting a finite distance limit based on recognized standards,
good science and risk avoidance should be done for the industry. BPA previously made this comment during the
drafting of the standard. It was not addressed then, nor has it been addressed now.
Yes
Group
Tampa Electric Company
Luke Diruzza
Tampa Electric Company
Yes
This provides a more flexible definition than previous drafts.
Yes
Adds clarity to the VSL from an audit perspective, this is an improved description to the Standard.
Yes
Confirmation allows for the potential of a greater number of “action items” than just investigation.
Yes
Good addition, adds clarity and improves overall understanding of the requirement.
Yes
This allows flexibility for the T.O. to determine the type of “unit” used in calculating the percentage complete.
Group
NextEra Energy
Silvia Parada Mitchell
Corporate Compliance
Yes
Yes
Although NextEra Energy Inc. (NextEra), including Florida Power & Light Company, agrees with the changes
referenced for R1 and R2, NextEra is concerned that the exemptions identified in footnote 2 for “…arboricultural
activities or horticultural or agricultural activities…,” and similar language in footnote 4, are too broad. For example,
this language appears to include an exemption for a landowner, who, during arboricultural activities or horticultural
or agricultural activities, causes a vegetation contact with a transmission line (e.g., cutting or lifting a tree into a
transmission line). This places the Transmission Owner in the difficult position of a landowner arguing it is exempt
from a controllable risk. Thus, the “…arboricultural activities or horticultural or agricultural activities…” references
should be removed from footnote 2, and the similar language in footnote 4
Yes
Yes
Yes
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
Yes
Yes
Yes
Yes
Yes
Individual
Kirit Shah
Ameren
Yes
Yes
This is more in alignment with a results-based reliability standard.
Yes
Yes
This clearly defines “intent”.
Yes
This is directed toward R7 rather than M7.
Individual
Amy Kupferberg
Individual
My Comments do not relate to the question asked, however, I saw no other place to add my comment. I would like
to thank NERC for allowing the public to participate in the process of improving the reliability standard FAC-003-1. I
became interested in Vegetation Management requirements for Transmission Lines, after Con Edison clear cut the
ROW behind my home. I appreciate the importance of safe and reliable electrical service, and recognize how an
effective TVMP contributes to this goal. In this whole process, what has dispirited me the most, is the inaccurate
information being conveyed about why the clear cutting was necessary and, the causes of the August 14th, 2003
blackout. The narrative goes something like..”a tree falling onto transmission lines caused the black out of 2003.” I
find it harmful because it misdirects the focus from the grid’s short fallings, and impedes upgrading the system to
improve reliability. I found this same philosophy in the initial pages of CN Utility’s document, UTILITY
VEGETATION MANAGEMENT FINAL REPORT MARCH 2004. It suggests that had the trees been adequately
maintained, the blackout would have most “likely” not happened. Now I am aware of the qualification of the word
“likely,” but the document is heavily weighted on the contribution of tree contact to the blackout. We know that deregulation and the physical nature of A.C. current had more to do with the causes of the blackout, than tree contact.
The timeline shows a range of cascading system failures that created the catastrophic event. The trouble began at
1:58 p.m. when First Energy generating plant in Eastlake, Ohio, shuts down. At 3:06 p.m. a First Energy 345-kV
transmission line fails. As a result, at 3:17 p.m voltage dips temporarily on the Ohio portion of the grid. Controllers
take no action, but power shifted onto another power line, overloading it and, causing it to sag into a tree and go
offline at 3:32 p.m. Mid West ISO and First Energy controllers fail to inform system controllers in nearby states. At
3:41 and 3:46 p.m., two breakers connecting First Energy s grid with American Electric Power are tripped. 4:05
p.m., a sustained power surge on some Ohio lines signals more trouble building. At 4:09:02 p.m., voltage sags
deeply, as Ohio draws 2 GW of power from Michigan. 4:10:34 p.m., many transmission lines trip out, beginning in
Michigan and then in Ohio, blocking the eastward flow of power. Generators go down, creating a huge power
deficit, in seconds, power surges out of the East, tripping East coast generators, and the rest is history. The U.S.Canada Power System Outage Task Force: Final Report on Implementation of Recommendations, September
2006, states that “Inadequate reactive supply was a factor in most of the events.” and “the assumed contribution of
dynamic reactive output of system generators was greater than the generators actually produced, resulting in more
significant voltage problems.” The backup generators were not adequate to handle the amperage load or voltage
needed. A lack of coordination of System Protection Programs(relays tripping), inadequate communication
between Utilities/TOs, and lack of "training of operating personnel in dealing with severe system disturbances" are
all the causes for the blackout. With respect to vegetation management, the findings from The U.S.-Canada Power
System Outage Task Force: Final Report on Implementation of Recommendations, September 2006, clearly did
not intend for transmission owners to develop a one-size-fits-all standard. The Energy Policy Act of 2005, initiated
NERC to draft and adopt the standard FAC-003-1. When I read through the standard, it all seems very reasonable.
I can understand the stiff penalties for noncompliance because it seems, like an easy fix, compared to the
necessary, major changes in infrastructure. The principles further outlined in ANSI A300 VII, and “Best Practices”
IVM, seem very reasonable too. There is mention of the environment, property owners, even proper pruning
techniques. The wire zone clearance of 10 feet and, allowing low growing compatible vegetation in the boarder
zone, seems to retain more vegetation, than remove. However, in practice, the TOs are simply clear cutting the
ROW, with no regard for the enviroment, the trees that they are cutting, or the abutting properties. It took Con
Edison 2 1/2 half days to clear 450 tress form behind our home. We are now forced to see and hear 93,000 cars a
day from the Sprain Parkway. Following the clearing, our real estate broker dropped the asking price by 30%. The
house remains empty and unsold. Apparently, no one is interested in spending 32,000K a year in property taxes to
look at transmission towers/lines and live on a highway. This has been devastating to our family, and thousands of
others in Westchester County. They removed a buffer of trees that were 150 feet away from wires and towers, on a
downward slope. These trees would have never made contact with conductors. Con Edison’s defense is that they
did it because it was in their right to. Moreover, they use the NERC fine structure to defend their behavior. I went
through the Notice of Penalties that NERC has issued from 6/2/08-2/01/11. Out of 646 Notice of Penalties, 1700
violations were sited, 36 out of 1700 penalties were issued for violations to the FAC- 003-1 standard. Some NOPs
had multiple violations-18 R1 violations were cited and 29 penalties were issued for R2 violations. Out of the 29 R2
penalties, 20 involved tree contact. Some outages were caused by sagging wires, some were caused by arcing
electricity looking for a ground fault, but none were caused by a tree falling onto the transmissions wires. The
numbers should put into perspective how immaterial the problem of tree contact really is. Think about it... 20 out of
1700 involved tree contact, and none of then resulted in a sustained outage. That means 1680 violations were
issued due to other system failures. To use these penalties as an excuse is a complete over exaggeration. What is
missing from the standard and the fine structure, are penalties for over cutting and violations to other stipulations,
such as proper communication, training, and aftercare of the affected areas. The problems that have arisen from
current TVMP activities being executed nationally on our ROWs, is not a public perception problem. Rather, TOs
are not complying with standards that are meant protect the environment and they are not respecting the property
rights of the neighboring homeowners. I appreciate the opportunity to share my views, and would take any
opportunity to further participate in protecting the rights of property owners, and the environment, while working to
secure safe and reliable electrical service. Most respectfully, Amy M Kupferberg Utility Whisperer
Individual
George Czerniewski
Consolidated Edison Company of New York, Inc. - Transmission Line Maintenance
Yes
Yes
Yes
Yes
Yes
The added language for the annual work plan percentage complete calculation is shown in R7 not M7 as stated in
the question. In the Guideline and Technical Basis Section for Requirement R6, there is a sample calculation
shown for the amount of lines the TO failed to inspect. An example should also be included for Requirement R7
since there is some confusion regarding how modifications to the work plan affect the calculation. In the Lower VSL
column for R7, it states that the TO failed to complete up to 5% of its annual vegetation work plan (including
modifications if any). If a TO operates 100 lines and submits a justified modification that affects 10 miles of lines,
the total number of units in the final amended plan is 90 miles. When you read the VSL, it is somewhat confusing
since the information in parenthesis says that the calculation 'includes' the modifications. Should it state 'excludes
modifications if any' or the VSLs can simply be re-written to state that ..The TO failed to complete up to x% of the
final amended plan.' Also, the VSLs in R6 and R7 should be consistent with each other: R6 says '...TO failed to
inspect 5% or less.....' and R7 says '...TO failed to complete up to 5%....' They both should use the same verbiage
in each VSL whether it is 'x% or less' or 'up to and including x%.'
Individual
andres lopez
USACE
Yes
Yes
Yes
No
Yes
Individual
CJ Ingersoll
CECD
Yes
Yes
No
Suggested Modification to the Measure - "If an after-the-fact analysis of a Fault by the Transmission Owner
determines that a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this
shall be considered the equivalent of observing an encroachment in Real-Time." CECD would also like to comment
on the Evidence Retention section, as it relates to Measures. The Evidence Retention section states that the
Transmission Owner retains data or evidence to show compliance with Requirement R1, R2, R3, R5, and R7,
Measures M1, M2, M3, M5, M6 and M7 for three calendar years...." Measures provide examples of evidence that a
Transmission Owner can produce to show compliance with the associated Requirement but are not separate
Requirements to be managed so reference to Measures should be deleted from the Evidence Retention section of
the standard.
Yes
Because Requirement 5 and 7 use the phrase annual work plan, and there is not a Requirement to develop a work
plan, this Requirement should include a relationship between the document that is developed for maintenance
strategies and the annual work plan.
Yes
Individual
Edward J Davis
Entergy Services, Inc
Yes
The revised Glossary definition of ROW helps to clarify the intent of what is expected and/or considered ROW
stipulations. This is a beneficial addition/clarification.
Yes
Yes
Yes
Yes
The actual clarifying language seems to have been added to R7 instead of M7 (as stated above). The clarifying
language provides benefit as added to R7, and should remain in R7. Additionally, we feel that, in an effort to
promote consistency with the other 6 Requirements, the term "on applicable Transmission lines" should be added
at the end of the first sentence of R7, as it is listed in all other R's. The first sentence of R7 currently reads: "Each
Transmission Owner shall complete 100% of its annual vegetation work plan to ensure no vegetation
encroachments occur within the MVCD". We feel the first sentence should read "Each Transmission Owner shall
complete 100% of its annual vegetation work plan to ensure no vegetation encroachments occur within the MVCD
on applicable transmission lines".
Individual
David Burke
Orange and Rockland Utilities, Inc.
Yes
Yes
Yes
Yes
Yes
The added language for the annual work plan percentage complete calculation is shown in R7 not M7 as stated in
the question. In the Guideline and Technical Basis Section for Requirement R6, there is a sample calculation
shown for the amount of lines the TO failed to inspect. An example should also be included for Requirement R7
since there is some confusion regarding how modifications to the work plan affect the calculation. In the Lower VSL
column for R7, it states that the TO failed to complete up to 5% of its annual vegetation work plan (including
modifications if any). If a TO operates 100 lines and submits a justified modification that affects 10 miles of lines,
the total number of units in the final amended plan is 90 miles. When you read the VSL, it is somewhat confusing
since the information in parenthesis says that the calculation 'includes' the modifications. Should it state 'excludes
modifications if any' or the VSLs can simply be re-written to state that ..The TO failed to complete up to x% of the
final amended plan.' Also, the VSLs in R6 and R7 should be consistent with each other: R6 says '...TO failed to
inspect 5% or less.....' and R7 says '...TO failed to complete up to 5%....' They both should use the same verbiage
in each VSL whether it is 'x% or less' or 'up to and including x%.'
Group
NERC Staff
Doug Keegan
NERC
No
NERC supports a revised definition and prefers the definition in Draft 5 over the Active Transmission Line ROW
definition used in Draft 4. NERC believes the use of the term “pre-2007 vegetation maintenance records” in the
proposed definition is ambiguous and will likely be interpreted differently throughout the industry. Therefore, NERC
supports this change subject to removing the aforementioned term.
No
The sentence was added to the rationale but the phrase “in order of increasing severity” is not in the requirement or
their associated VSLs. NERC staff does not support the language in the rationale box which differentiates the VSL
based on skill level of maintenance personnel rather than the impact to reliability of the encroachment. The VSL
should be based on whether or not the owner managed the vegetation to prevent encroachment and therefore be
binary. See additional comments submitted separately regarding combining R1 and R2.
No
Concur with restating as mentioned above. Other issues remain regarding data reports indicating no sustained
outages or real-time observations. These measures appear to indicate that if the outages or real-time observations
are not documented then an encroachment didn’t occur. What will compel an entity to document these
occurrences? In addition, the last two paragraphs of the Measure are not really measures. They would be better
served as part of the Requirement.
No
Adding the term “maintenance strategies” is not helpful in the requirement. NERC staff recommends the following:
“Each Transmission Owner shall have a documented vegetation management plan that includes maintenance
strategies, procedures, processes, and specifications it uses to prevent the encroachment of vegetation into the
MVCD of its applicable lines that include(s) the following:”
Yes
Actually, R7 contains the clarifying language. It should be noted that although R7 indicates the TO shall complete
100% of the VM work plan, there is no requirement in this draft that a plan is actually developed.
Individual
Saurabh Saksena
National Grid
No
The revised ROW definition emphasizes the ROW width needed to operate the transmission line(s). It is National
Grid’s interpretation that the width established when the line was constructed is the width to be maintained. This
width is documented in engineering drawings, per-2007 vegetation records or blow-out standards. This definition
does not imply that danger tree rights beyond the constructed and maintained width are incorporated in the
definition; therefore fallins - from outside the ROW but within within an area with danger tree rights would not be
considered fallin-ins from within the ROW. National Grid would like the SDT to comment on this interpretation in its
response to these comments.
Yes
Yes
Yes
No
There is currently no percentage language in M7. If they are referring to R7, then YES it is adequate.
Group
Pepco Holdings Inc and Affiliates
David Thorne
Pepco Holdings Inc
Yes
Yes
Yes
Yes
Yes
Group
FirstEnergy
Sam Ciccone
FirstEnergy Corp.
No
Although for the most part we agree with the changes to the definition of ROW, we suggest the following changes.
1. The last sentence of the definition states "The ROW width in no case exceeds the Transmission Owner's legal
rights but may be less based on the aforementioned criteria." We do not agree with the phrase "in no case exceeds
the Transmission Owner's legal rights" because there could be instances where special permission has been
granted by landowners to the TO. We suggest revising this statement to "The ROW width may be less than the
Transmission Owner’s granted rights based on the aforementioned criteria." 2. Regarding the phrase "blowout
standard" used in the definition, we are assuming this is in reference to the company specific calculations for sag
and sway on not on any one specific industry standard. We suggest clarification such as "Transmission Owner's
specific blowout or sag and sway analysis in effect when the line was built".
No
For the Requirement R1 and R2 VSLs, we suggest that the proposed Moderate (fall-ins) and High (blowing
together) VSL be interchanged. We believe that fall-ins are more severe encroachments than blowing together and
the categories listed in the compliance section support this point. Category 1 (grow-ins) is most severe, followed by
Category 2 & 3 (fall-ins) and Category 4 (blowing together).
Yes
Yes
Yes
Although we generally agree with Requirements R7 and its measure M7, we suggest adding clarifying wording to
bullet 4 which states "Crew or contractor availability/ Mutual assistance agreements". In addition to availability,
contractor performance may be another issue that requires modification to the work plan. We suggest adding
another bullet that reads "Crew or contractor performance". The rationale behind this addition is to address poor
safety, productivity and/or quality issues with a crew or contractor assigned to perform vegetation management.
FirstEnergy provides the following additional comments and suggestions not related to the specific questions asked
in this posting: 1. Requirement R5 – We appreciate this requirement which recognizes that the TO may face
situations in which it is constrained from performing its vegetation management and are permitted to seek
alternative methods. However, there may be instances where the TO has exhausted all course of action to perform
vegetation and must utilize other means to prevent vegetation encroachment into the MVCD. Therefore, in these
instances, "continued vegetation management" as stated in the requirement is not possible, but other methods
such as line deratings and deenergizing of lines may have to be used. We ask that the phrase "to ensure continued
vegetation management to prevent encroachments" be changed to read “to ensure continued reliability of the
BES”. 2. Compliance Section – Category 3 – We suggest removing this category from the standard. Since fall-ins
from outside the ROW are not considered a violation of this standard per Requirements R1 and R2, the entity
should not have to report these fall-ins. 3. Objectives – We do not believe that is necessary for the Objectives
statement to include the "defense-in-depth" concept which is actually an overarching goal of results-based
standards in general and not specific to FAC-003-2. We suggest removing this phrase. 4. Background Section 5 –
Similar to our comment above regarding defense-in-depth in the objectives statement, this is an overarching goal of
results based standard and not specific to FAC-003-2. Therefore, we suggest removing the explanation of defensein-depth from the background section. 5. Vegetation Inspection Definition – We suggest replacing the word
"hazard" with "risk". 6. Requirement R4 – We do not agree with the phrase "without any intentional time delay" and
suggest it be removed. This phrase is not measurable. Also, other drafting teams have attempted to incorporate
this statement but industry comments have persuaded them to remove it; for example, the Reliability Coordination
drafting team (Project 2006-06) initially proposed the same phrase but later removed it in their development of the
COM/IRO standards. At the very least standards development should be consistent throughout the NERC
standards drafting teams. We suggest the following as wording for Requirement R7: "Each Transmission Owner
shall ensure the control center holding switching authority for the applicable transmission line is promptly notified
when the Transmission Owner has confirmed the existence of a vegetation condition that can potentially cause a
Fault."
Individual
Steve Rueckert
Western Electricity Coordinating Council
Yes
Yes
Yes
Yes
Yes
We support the clarifying languae in M7 However, since there is no generic "Any other Comments" section
associated with this on-line comment form, we raise a question here. On December 24, 2008, NERC issued an email to all Transmission Owners in which it referenced its December 17, 2008 Public Notice – NERC Compliance
Process #2008- 001, Vegetation-related Transmission Outage Reporting. The notice stated that: "Due to the
potential severity of transmission outages caused by vegetation associated with Standard FAC-003-1, NERC is
encouraging each Transmission Owner to self-report all Category 1 and Category 2 transmission outages related
to vegetation to the Regional Entity within 48 hours utilizing the 48-hour vegetation reporting notice form provided
by your appropriate Regional Entity." We do not see any reference to a 48-hour reporting notice in lthis version of
the standard. Is this still a requirement? The only reference to reporting is in the Additional Compliance Information
section and references quarterly reporting only.
Group
Dominion Electric Market Policy
Mike Garton
Dominion Resources Services, Inc.
Yes
Yes
Yes
Yes
No
The red-line revision does not indicated changes to M7; therefore, Dominion is unable to evaluate the clarifying
language identified in this question. If the SDT meant to reference R7, we agree that the clarification is adequate.
Individual
Jody Nelson
Georgia Transmission Corp.
Yes
Yes
Yes
Yes
Yes
Group
Southern Company Transmission
JT Wood
Southern Company Services
Yes
While we prefer the Active ROW definition, we are willing to accept the newly proposed definition.
Yes
No
We would recommend the middle paragraph of M1 and M2 be revised as follows: “If a later confirmation of a Fault
by the TO shows that vegetation encroachment within the MVCD has occurred from vegetation growing into or
blowing into the conductor within the ROW, this shall be considered the equivalent of a Real-time observation. Brief
encroachments caused by a falling tree going through the MVCD is not considered an encroachment.”
Yes
Yes
Individual
T. Wiley
Northern Indiana Public Service Company
Yes
No
While there are some enhancements to the organization and content of the standard such as the addition of the
Guidelines and Technical Basis section, clarification of what constitutes evidence of compliance, and tailoring of
VSL severity levels for the requirements based on the risk each poses to the likelihood of contributing to a cascade,
too many elements present in FAC-003-1 and which are vital to preventing vegetation caused outages and
maximizing system reliability, have been eliminated from FAC-003-2. Specifically, the elimination of concrete,
declared and audited clearance standards between vegetation and conductors (the existing Clearance 1 and
Clearance 2 (R1.2)) Requirements) in the revised standard is a major defect that will decrease system reliability. It
has been indispensable for NIPSCO when communicating with stake holders (governments, interest groups, land
owners, the public, etc.) to point to these clearance standards to give credibility and support to the kind of tree
removal and trimming that is necessary to achieve the stated objective of zero preventable tree caused outages.
Without these declared clearance standards in the NERC standard, utility vegetation managers will constantly be
challenged by stake holders to show them that such work is required rather than an elective choice on the utility's
part. One of the key lessons learned from the 2003 blackout and First Energy's overgrown ROW tree problem was
that individual land owners, local governments, and interest groups will exert pressure on the utility to only do the
minimum amount of vegetation management. Without external and enforceable Vegetation Clearance Standards
and by returning to a pre-2003 regime where the extent of vegetation clearing is left to the individual discretion and
pressures at each utility, there is no doubt that tree clearance conditions will deteriorate over time and put system
reliability at greater risk of vegetation contact.
Yes
No
Yes
FAC-003-2 Vegetation Management Draft 5
NERC Staff Comments in Addition To Those Submitted On Comment Form
2.28.11
In addition to the comments NERC submitted to the five questions on the official comment form,
NERC staff has numerous other comments to make with regard to this Draft 5. Before that,
NERC staff first wants to acknowledge the significant effort and talent that the industry brought
to attempt to improve upon Reliability Standard FAC-003-1 – Vegetation Management. This
Draft 5 of FAC-003-2 – Vegetation Management entailed significant industry work towards
understanding the issue, compromising on proposals and attempting to reach consensus utilizing
the NERC Standards Development Process. While NERC staff believes this draft represents
some improvements to the existing standard, it does not believe the draft in its totality represents
an improvement to the existing standard. FERC Order 693 approved the existing Vegetation
Management Standard and it provided a number of directives for NERC with regard to further
developing the Standard in order to improve it. Such directives and NERC comments regarding
how the directives were addressed included:
•
FERC Directive - Develop compliance audit procedures, using relevant industry experts,
which would identify appropriate inspection cycles based on local factors. The
Commission is dissuaded from requiring the ERO to create a backstop inspection cycle at
this time.
NERC Comment – Compliance audit procedures are outside the scope of the SDT and
this Draft 5. Although not required by the Commission, the SDT added an annual
inspection cycle to the Standard, with a maximum of 18 months between inspections.
NERC believes this requirement represents an improvement to the existing Standard and
does not believe it is overly burdensome on utilities.
•
FERC Directive - Remove the general limitation on lines 200kV and above to include
lines that have an impact on reliability.
o Do not reduce facilities included
o Develop an acceptable definition for the applicability of this Reliability Standard
that covers facilities that impact reliability while not unreasonably increasing the
burden on transmission owners.
o Evaluate the suggestions proposed by LPPC, APPA and Avista that regional
entities should determine which facilities this standard applies to
NERC Comment – NERC believes Draft 5 partially addresses this issue by increasing
applicable facilities to IROL lines under 200kV. NERC staff is also concerned about
o The possibility that this very addition could limit a regional entity’s desire to
include additional lines.
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o The exclusion of facilities inside the fenced area of switching stations, stations
and substations. These excluded areas still pose a vegetation related outage risk
and the rationale for excluding them is not compelling enough.
o The separation of IROL (any voltage level) and non-IROL (200 kV and above)
Transmission Lines into separate requirements with different VRFs. NERC
believes all Transmission Lines subject to this standard should be under the same
requirement and associated VRFs. IROL lines are relatively few and do not
warrant their own requirement. By having lower VRFs for non-IROL lines, this
version of the standard is weaker than the existing standard. These two
requirements should be a single requirement with high VRFs
•
FERC Directive - Develop a Reliability Standard that defines the minimum clearance
needed as an improvement to IEEE 516 which FERC does not believe is appropriately
used for purposes of reliability and/or safety.
NERC Comment – Draft 5 makes a change from IEEE 516 and utilizes Gallet equations
for industry clearances. While NERC believes these equations are technically accurate,
NERC is concerned about the usefulness of the clearances determined under this
methodology as put forth in this draft. NERC is not aware of any utility which would
maintain clearances as specified in this draft as it has no built in safety factor. NERC is
further concerned that utilities could be mandated by courts of law to reduce existing
maintained clearances to values much closer to those determined by the methodology in
this draft.
•
FERC Directive - Define rights-of-way to encompass the required clearance areas instead
of the corresponding legal rights, and the standards should not require clearing the entire
right-of-way when the required clearance for an existing line does not take up the entire
right-of-way.
NERC Comment – NERC staff believes this directive was met and is addressed in
question 1 of the comment form.
•
FERC Directive – NERC should address the proposed modifications through its
Reliability Standards development process.
NERC Comment – NERC staff believes this directive was met in preparing this draft
standard.
•
FERC Directive - Collect outage data for transmission outages, analyze it, and use the
results of this analysis and information in the development of the Reliability Standard.
NERC Comment – NERC staff believes more work needs to be done in this area. NERC
staff believes the drafting team should consider modifying the Periodic Data Submittal to
include if outages occur on Federal land.
2
Other Draft 5 Issues
•
Removal of a formal transmission vegetation management program, of Clearance 1 and
of a documented vegetation management plan.
NERC Comment – NERC does not support the removal of these items. NERC does not
believe these changes represent an improvement to the standard and does not believe this
existing requirement is overly burdensome to utilities. NERC does not understand why
industry would not be willing to be held accountable to their vegetation management
plans. NERC is concerned that the removal of these items could make it difficult for
utilities to obtain permissions needed to maintain clearances between inspection cycles
which are prudent for reliability and safety due to intervener or landowners exercising
their rights and then pointing to this new standard as a the basis for smaller clearances. .
Requirement 3 in this draft needs to include a documented plan and to clearly identify the
specifics to be included in the plan and provide clarity of expectations. The SDT may not
support such specifics as not being consistent with results-based standards development
but NERC staff believes otherwise.
•
Objectives: A qualifier in the standard Objective that it should apply to preventing the
risk of vegetation related outages that could lead to cascading outages.
NERC Comment – This qualifier limits the purpose of the standard, which should be to
prevent vegetation related outages, not cascading outages. The more outages there are,
the less the overall system reliability. An outage does not necessarily have to lead to a
cascading outage to be significant and represent a reasonable risk to the BES. References
to cascading outages should be removed.
•
Background: This section excludes vegetations fall-ins and blow-ins from outside the
ROW on the basis that they are not preventable.
NERC Comment – Many fall-ins and blow-ins from outside the ROW are preventable.
Trees outside the ROW must be managed adequately to prevent outages on the BES. The
work to remove and/or prune trees outside the ROW may be more difficult and costly
than such work inside the ROW, but that is not sufficient reason to exclude this work. In
addition, utilities wishing to perform such work might be prevented from doing so by
regulatory bodies based upon the lack of a specific requirement in this standard.
•
Requirement 1 & 2: These requirements discuss preventing encroachments into the
MVCD of an applicable line that is operating within its Rating.
NERC Comments –NERC staff would like confirmation that “Rating” is intended to
include all published ratings issued by the facility owner, such as Normal, Emergency,
etc.
3
•
Requirement 4: R4 states that “Each Transmission Owner, without any intentional time
delay, shall notify…”
NERC Comments: The previous version of the standard included a time limit of 15
minutes once communications became available. This should be reinstated.
•
Requirement 7: R7 sets the requirement for each Transmission Owner to complete 100
percent of its annual vegetation work plan.
NERC Comments – NERC is concerned that the draft doesn’t have a requirement for a
Transmission Owner to have a documented annual plan making Requirement 7
unenforceable. In addition, Requirement 7 has a number of other qualifiers that would
seem to allow manipulation of the annual plan to ensure compliance.
•
Draft 5 document quality
NERC Comments – this draft has some typographical errors which need to be fixed. For
example, on page 28, reference to use of Table 5 versus Table 7 based on knowledge of
maximum transient over-voltage factor is reversed. These edits could probably be
handled through a recirculation ballet.
•
Previously raised NERC issues
•
NERC Comments – NERC staff posted several comments on the Draft 4 version of this
standard in July 2010. NERC believes most of the concerns it raised in those comments
are not addressed in Draft 5 and continue to be a concern for NERC.
General compliance and audit issues
NERC Comments –
o The whole “sustained outage” concept in R1 (for fall ins and blow ins) is
unworkable from an enforcement perspective.
o The difference between a violation and a non-violation in Draft 5 is whether the
registered entity was fortunate with regard to an encroachment. This part should
be rewritten to say that any tree contact is a violation. VRFs and VSLs could then
be used to address whether the violation was minor or serious.
o There could be a lot of litigation over whether “circumstances” were really
“beyond the control” of the TO. NERC had previously objected to the
implementation of a force majeure clause in the standard. If an entity failed to
carry out its annual plan, that should be treated as a violation, and any excuses for
failing to do so or for changing the plan mid-year all go to whether the penalty
should be $0 or substantial.
o For the evidence retention period, the entity really should retain evidence of
compliance until the next compliance audit. Since some TOs may be on a 6 year
audit schedule, the 3 year retention period is not sufficient.
4
Successive Ballot (February 18-28, 2011) Consideration of
Comments Report
Project 2007-07 Vegetation Management — September 30, 2011
Summary Consideration:
In order to be consistent with the latest version of NERC’s Results Based Standards template, the heading “Objective” was replaced
with “Purpose,” and the numbering, headings, and sections were reformatted as necessary.
Several entities expressed concern with the use of the Minimum Vegetation Clearance Distance (MVCD) and elimination of
Clearance 1. With respect to comments about the MVCD, R3 does not suggest the MVCD be used as a distance to manage
vegetation. The MVCD was established as a beginning of a series of “building blocks” for a program to ensure reliability of a
Transmission line within its rating and all rated electrical operating conditions. R3 requires that a Transmission Owner consider the
MVCD distances, as well as variables of conductor movement and vegetation growth, when designing the Transmission Owner’s
overall vegetation management approach. The net result of this “building block” approach is that when entities implement R7, their
efforts will result in vegetation management at clearance distances greater than the MVCD. In a performance-based standard,
requirements are focused on “what” needs to be accomplished to achieve desired results and avoids prescriptive requirements of
“how” to achieve that result. TO’s are in the best position to determine the appropriate management approach suited for their
system, rather than a “one size fits all” or “fill in the blank” requirement that could suppress best practices for vegetation
management.
Other entities questioned whether the goal of the standard was to “prevent outages” or to “manage vegetation.” In Order 693, FERC
was very specific that “…FAC-003-1 is designed to minimize transmission outages from vegetation located on or near transmission
rights-of-way by maintaining safe clearances between transmission lines and vegetation.” The drafting team followed that concept
and used R1 and R2 to move the clearance from a documentation requirement to a performance requirement. Item 1 in the
requirements defines how an encroachment without an outage would be documented. Each Transmission Owner is also required to
conduct inspections in which clearances are evaluated.
Some entities expressed concern with the mandatory inspection intervals proposed in the standard. The SDT recognizes that a
number of Transmission Owners in North America may prefer to set their own inspection intervals. Because there is substantial
industry support for an annual inspection interval the SDT believes that the industry is best served with this approach.
Several entities suggested making minor changes to clarify the footnotes. The team did so.
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment
serious consideration in this process. If you feel there has been an error or omission, you can contact the Vice President and Director
of Standards, Herb Schrayshuen, at 404-446-2563 or at [email protected]. In addition, there is a NERC Reliability Standards
Appeals Process.1
Voter
Paul B.
Johnson
Entity
American
Electric Power
Segment
1
Vote
Affirmative
Comment
American Electric Power believes that the phrase
"arboricultural activities or horticultural or agricultural
activities" was mistakenly introduced into Footnotes 2 and
4, and should be deleted from both footnotes. If the phrase
remains in the Standard, it may empower orchard growers,
landowners and others to plant trees on the right of way
and challenge Transmission Owners' rights to perform
maintenance on the presumption that the standard will
exempt the TO from violating the outage or encroachment
requirements.
For increased clarity, AEP offers the following change to the
second paragraph of M1, as well as the second paragraph of
M2. The original text “If a later confirmation of a Fault by
the Transmission Owner shows that a vegetation
encroachment within the MVCD has occurred from
vegetation within the ROW, this shall be considered the
equivalent of a Real-time observation” should be replaced
1
The appeals process is in the Reliability Standards Development Procedure: http://www.nerc.com/files/RSDP_V6_1_12Mar07.pdf.
Consideration of Comments on Successive Ballot of FAC-003-2
2
Voter
Entity
Segment
Vote
Comment
with “If a later confirmation of a Fault by the Transmission
Owner shows that a vegetation encroachment within the
MVCD has occurred from vegetation growing into or
blowing together with the conductor within the ROW, this
shall be considered the equivalent of a Real-time
observation. A brief encroachment caused by falling
vegetation passing through the MVCD is not considered an
encroachment in this requirement”.
Response: Thank you for your comments. The SDT made suggested changes to the footnotes as proposed.
Regarding the issue of fall-ins, the SDT is sympathetic to your concern. In fact, the SDT had originally crafted language similar to
that which you suggested. However, due to concerns expressed by regulators and others, the exemption for encroachment
violations due to falling vegetation from inside the right of way was removed.
Robert D
Smith
Arizona Public
Service Co.
1
Negative
Overall comment: The objective, as written, is about
outages that can lead to cascading and not about reliability.
Recommended change to Standard Objective: To maintain a
reliable electric transmission system, implement a defensein-depth strategy to manage vegetation located on
transmission rights of way (ROW) and minimize
encroachments from vegetation located adjacent to the
ROW.
Response: The SDT thanks you for your comment. With respect to the Purpose as written in the proposed standard, the
language clearly states “To improve the reliability of the electric Transmission system…” The SDT made it a point to keep the
Purpose as concise as possible without getting into issues that are covered further in the body of the standard.
John
Bussman
Associated
Electric
Cooperative,
Inc.
1
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
R1 - “Each Transmission Owner shall manage vegetation to
prevent encroachments of the types shown below, into the
Minimum Vegetation Clearance Distance (MVCD) of any of
its applicable line(s) identified as an element of an
Interconnection Reliability Operating Limit (IROL) in the
planning horizon by the Planning Coordinator; or Major
Western Electricity Coordinating Council (WECC) transfer
3
Voter
Entity
Segment
Vote
Comment
path(s); operating within its Rating and all Rated Electrical
Operating Conditions...”
The following is my preliminary comment on this
requirement. R1 - Associated Electric Cooperative Inc wants
to thank the SDT for their hard work and all the effort
associated with this standard. However we currently
disagrees with the inclusion in this requirement of any and
all IROLs identified within the entire planning horizon
(typically 10 years or more). Associated Electric certainly
agrees that in real time and in the near term sub 200 kV
elements of an IROL should be subject to R1. It seems
unreasonable, however, to include a sub 200 kV
transmission line that might become an IROL element 10
years in the future. Perhaps the time frame could be limited
to the Transmission Owner’s planned maintenance cycle.
Response: The SDT thanks you for your comment, and has revised the Standard’s effective dates (exceptions) accordingly.
Gregory S
Miller
Baltimore Gas
& Electric
Company
1
Affirmative
There seems to be a marginal level of improvement over the
previous drafts.
Negative
R1 and R2 Requirement reads: "Each Transmission Owner
shall manage to prevent encroachment ....". The results of
manage would be invoices of tree trimming actually
performed, documentation of a vegetation management
program that would be managed to, etc. However, the
Measures proposed are all actual outages which are neither
Response: The SDT thanks you for your comment.
Joseph S.
Stonecipher
Beaches
Energy
Services
1
Consideration of Comments on Successive Ballot of FAC-003-2
4
Voter
Entity
Segment
Vote
Comment
evidence of management nor evidence of encroachment
since there can be encroachment without an outage, and in
fact, many if not most encroachments do not result in
outages. Hence, the Measures are inconsistent with the
Requirements.
Further, there is ambiguity of the action required in
requirements R1 and R2 - e.g., do entities need evidence
that they: 1) "manage", or 2) "prevent encroachment"; or 3)
as implied by the Measures, prevent vegetation related
outages? In other words, what needs to be proven through
evidence? Certainly the third, prevent vegetation related
outages, is not in the Requirement; yet, that us what is
proposed for the Measures, highlighting the inconsistency
between Requirements and Measures. But, how would the
ambiguity between "manage" and "prevent encroachment"
be resolved? One auditor could interpret that the
Requirement is to "manage" and accept a vegetation
management program and plan and proof that the plan was
executed as appropriate evidence. Another auditor could
interpret that "prevent" is the key word and look for
evidence proving that there was never a vegetation
encroachment. How would evidence be produced to
provide the auditor that vegetation never encroached?
Would video cameras and other surveillance measures need
to operate 24 hours a day? Would we cause an entity to
survey the lines periodically? One can easily see that
"prevent encroachment" is inappropriate here since it is
infeasible to create evidence of compliance.
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
Consideration of Comments on Successive Ballot of FAC-003-2
5
Voter
Entity
Segment
Vote
Comment
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Donald S.
Watkins
Bonneville
Power
Administration
1
Affirmative
R2. Do you agree? If answer is no, please explain.
BPA prefers the stratified levels of violation severity
presented in the table for R1 and R2. Foot note # 2 on page
8 needs to be clarified with respect to arboricultural
activities or horticultural or agricultural activities. Foot note
# 4 on page 12 needs to be clarified with respect to
arboricultural activities or horticultural or agricultural
activities.
In response to comments received that requirement R3 is
unclear with respect to intent, the SDT added “maintenance
strategies.” Do you agree this clarifies the intent? If answer
is no, please offer alternative language.
The TO procedures / policies and specifications shall
demonstrate the TO’s ability to manage the system at all
rated conditions to maintain reliability. BPA believes that
the intent is clear, but the fundamental approach of using
the MVCD (table 2) to manage a vegetation program is still
problematic. These values are flashover distances and are
way too close. This is acknowledged in a footnote to table 2
but no identification of allowable buffers/distances
between energized phase conductors at rated temperatures
and vegetation is discussed (this is left up the transmission
owners). Clarity is needed on this topic. Setting a finite
distance limit based on recognized standards, good science
and risk avoidance should be done for the industry. BPA has
previously made this comment during the drafting of the
Consideration of Comments on Successive Ballot of FAC-003-2
6
Voter
Entity
Segment
Vote
Comment
standard. It was not addressed then, nor has it been
addressed now.
Response: The SDT thanks you for your comments. The footnotes were changed to conform with your suggestions.
With respect to comments about the MVCD, R3 does not suggest the MVCD be used as a distance to manage vegetation. The
MVCD was established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line
within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD
In a performance based standard, requirements are focused on “what” needs to be accomplished to achieve desired results
and avoids prescriptive requirements of “how” to achieve that result. TO’s are in the best position to determine the
appropriate management approach suited for their system, rather than a “one size fits all” that could suppress best practices
for vegetation management.
Randall
McCamish
City of Vero
Beach
1
Negative
Vero Beach's concern is that entities may not be able prove
compliance with the standard. R1 and R2 say that: "Each
Transmission Owner shall manage vegetation to prevent
encroachments ...". If the requirements were interpreted
such that "manage" is the operative word, then, we are OK
because we can provide evidence of managing a program,
such as a vegetation management plan and evidence of
executing that plan (which does not align with the
Measures). However, that 1) would cause the standard to
not be performance based, and 2) it would be duplicative of
the other requirements of the standard.
If the requirements were interpreted with "prevent
encroachment" as the operative phrase (which would be an
Consideration of Comments on Successive Ballot of FAC-003-2
7
Voter
Entity
Segment
Vote
Comment
incorrect interpretation from the construct of the sentence)
there is no way to provide sufficient evidence that
encroachment was prevented during the audit-period. The
suggested Measures are not sufficient evidence to prove
compliance with that interpretation of the requirement. For
instance, most encroachments do not result in outages;
hence, lack of outages cannot prove that there were no
encroachments, and real time observations are insufficient
because it is a spot-check that does not cover the audit
period.
There are other weaknesses in the standard, such as R4
being un-measurable therefore unenforceable. However, in
the guilty until proven innocent paradigm we live in, FMPA's
primary concern is that industry could be put into a no-win
situation of not being able to prove compliance with the
standard if R1 and R2 are interpreted as "prevent
encroachment", and if R1 and R2 are interpreted as
"manage" then it is not a performance based standard as
advertised. Vero Beach suggests one of two approaches:
1. Performance based focused on preventing vegetation
related outages. For instance: "Each Transmission Owner
shall prevent vegetation related outages (except as noted in
Footnote 2) of any of its applicable line(s) ..." Evidence of
outages is practical to gather and provide, evidence of
encroachment is not.
2. Modify the standard to be similar to the currently
mandatory non-results based standard and focus on the
word "manage". This would essentially mean eliminating R1
Consideration of Comments on Successive Ballot of FAC-003-2
8
Voter
Entity
Segment
Vote
Comment
and R2 since the rest of the standard focuses on having a
plan and managing to that plan.
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Danny
McDaniel
Cleco Power
LLC
1
Negative
Cleco disagrees with the SDT revising the definition for
Right-of-Way (ROW). Right-of-Way is a term that has had a
consistent meaning throughout history. If NERC tries to
redefine the term, it will only add confusion because most
entities will not reference the NERC glossary for a term
which is widely used in the industry. In lieu of "Active
Transmission Line ROW", please use another term such as
Transmission Corridor. No assumptions would be made
when reading in the Standard the the Entity is to maintain
vegetation located within the Transmission Corridor. Since
the term is not commonly used, the NERC glossary would be
referenced.
Also, Cleco disagrees that an encroachment into the MCVD
that does not cause an outage should be considered noncompliant as stated in R1 and R2. The encroachment should
only be reportable similar to misoperations as is in the PRC004 standard.
Response: Thank you for your comments.
The existing ROW definition in the glossary was created by and for the FAC-003-1 and was moved there when that standard
was adopted. The definition includes a series of options that give the Transmission Owner latitude in establishing ROW width.
It does not require selecting a single method for its system. The term “blowout standard” is not capitalized and is not a defined
Consideration of Comments on Successive Ballot of FAC-003-2
9
Voter
Entity
Segment
Vote
Comment
term. This phrase in the definition allows a Transmission Owner to use its internal engineering standards or the general
engineering standards that were in effect when the line was constructed to determine the ROW width. The SDT has limited the
definition of Right-of-Way to a corridor of land with a defined width to operate a transmission line. This does not include
danger tree rights.
The definition of the MVCD is now added to this Standard. While use of the pre-2007 records is a compliance issue and is not in
the purview of the SDT, it is the intent of the language in the definition that you could use this information.
Regarding your second comment, R3 does not suggest the MVCD be used as a distance to manage vegetation. The MVCD was
established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line within its
rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD
Other related requirements of this “Defense in Depth” Standard serve to address any number of scenarios which may arise or
hinder the TO’s ability to always strictly adhere to the management approach(s) established within R3. Thus the other
requirements of this Standard provide the latitude for appropriate actions to remedy the condition without penalty. Further,
trees which have encroached inside the MVCD are evidence of a deficiency in vegetation maintenance.
Christopher
L de
Graffenried
Consolidated
Edison Co. of
New York
1
Affirmative
Reply to Question 5 on Comment Form: The added language
for the annual work plan percentage complete calculation is
shown in R7 not M7 as stated in the question. In the
Guideline and Technical Basis Section for Requirement R6,
there is a sample calculation shown for the amount of lines
the TO failed to inspect. An example should also be included
for Requirement R7 since there is some confusion regarding
how modifications to the work plan affect the calculation.
In the Lower VSL column for R7, it states that the TO failed
to complete up to 5% of its annual vegetation work plan
(including modifications if any). If a TO operates 100 lines
and submits a justified modification that affects 10 miles of
Consideration of Comments on Successive Ballot of FAC-003-2
10
Voter
Entity
Segment
Vote
Comment
lines, the total number of units in the final amended plan is
90 miles. When you read the VSL, it is somewhat confusing
since the information in parenthesis says that the
calculation 'includes' the modifications. Should it state
'excludes modifications if any' or the VSLs can simply be rewritten to state that ..The TO failed to complete up to x% of
the final amended plan.'
Also, the VSLs in R6 and R7 should be consistent with each
other: R6 says '...TO failed to inspect 5% or less.....' and R7
says '...TO failed to complete up to 5%....' They both should
use the same verbiage in each VSL whether it is 'x% or less'
or 'up to and including x%.'
Response: The SDT thanks you for your comments.
The percentage should be based on the plan as modified. The SDT has changed the language in the standard to reflect this
more clearly, and has modified the VSLs to be consistent as you have suggested.
Robert
Martinko
FirstEnergy
Energy
Delivery
1
Affirmative
FirstEnergy supports standard FAC-003-2 and would
appreciate consideration of our comments submitted
through the formal comment period.
Response: The SDT thanks you for your comments. Please see our consideration of your comments within the responses to
the formal comments.
Luther E.
Fair
Gainesville
Regional
Utilities
1
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
1. It would seem that the impetus for FAC003 is to eliminate
vegetation related outages within the rights-of-way as
defined and subject to the exclusions as stated in footnote
2. Thus the requirement is to manage the ROW to prevent
vegetation related sustained outages with the measure
being no outages. With grow-ins and fall-ins from within the
defined ROW being controllable factors.
11
Voter
Entity
Segment
Vote
Comment
2. Including encroachments leaves the door open for fines
to be imposed with no actual outage(s) having occurred.
This may be like being found guilty of a crime that has not
yet taken place.
3. Combine vegetation related sustained outages by “growins” and “blowing together of lines and vegetation located
inside the ROW” as one item as they are both consequences
of the growth of vegetation either vertically and
horizontally.
4. Leave vegetation related sustained outages by “fall-in” as
a standalone as this will be related to structural problems
occurring from a variety of sources.
5. Combine R3 and R7 to R1 (development and
implementation of a Transmission Vegetation Management
Plan which shall include documented maintenance
strategies or procedures or processes or specifications,
delineation of an annual work plan and completion of
same). Thus this would be the competency based
requirements as a program without execution is
meaningless.
6. R1 and R2 become R2 and R3.
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
Consideration of Comments on Successive Ballot of FAC-003-2
12
Voter
Entity
Segment
inspections in which clearances are evaluated.
Ted E
Hobson
JEA
1
Vote
Negative
Comment
Need to align the "measures" with the standard
requirement language and the performance-based
philosophy.
Response: The SDT thanks you for your comments. We are not quite clear as to what misalignment you refer to between the
standard language and the measures. The SDT went to great lengths to ensure continuity between the requirements and the
measures. While this standard was a first attempt at a "Results Based" approach, the SDT did have limitation in deciding what
could be excluded from the standard. This standard has a mixture of the three types of requirements that comprise a results
based approach: 1) Performance Based 2) Risk Based and 3) Competency Based. Having only performance-based requirements
would not have resulted in a comprehensive, proactive standard.
Michael
Gammon
Kansas City
Power & Light
Co.
1
Negative
The Standard lacks clarity regarding the facilities that are
subject to Requirement 7. It is important that a Standard be
clear and not introduce ambiguity or confusion. There are
several references throughout the Standard to "for all
applicable lines" and it should be made clear the work plan
is specific to "all applicable lines".
Response: The SDT thanks you for your comments. The team has made the appropriate modifications where necessary.
Stan T. Rzad
Keys Energy
Services
1
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
Concern is that entities may not be able prove compliance
with the standard. R1 and R2 say that: "Each Transmission
Owner shall manage vegetation to prevent encroachments
...". If the requirements were interpreted such that
"manage" is the operative word, then, we are OK because
we can provide evidence of managing a program, such as a
vegetation management plan and evidence of executing
that plan (which does not align with the Measures).
However, that 1) would cause the standard to not be
performance based, and 2) it would be duplicative of the
13
Voter
Entity
Segment
Vote
Comment
other requirements of the standard.
If the requirements were interpreted with "prevent
encroachment" as the operative phrase (which would be an
incorrect interpretation from the construct of the sentence)
there is no way to provide sufficient evidence that
encroachment was prevented during the audit-period. The
suggested Measures are not sufficient evidence to prove
compliance with that interpretation of the requirement. For
instance, most encroachments do not result in outages;
hence, lack of outages cannot prove that there were no
encroachments, and real time observations are insufficient
because it is a spot-check that does not cover the audit
period.
There are other weaknesses in the standard, such as R4
being un-measurable therefore unenforceable. However, in
the guilty until proven innocent paradigm we live in, FMPA's
primary concern is that industry could be put into a no-win
situation of not being able to prove compliance with the
standard if R1 and R2 are interpreted as "prevent
encroachment", and if R1 and R2 are interpreted as
"manage" then it is not a performance based standard as
advertised. One of two approaches are suggested:
Performance based focused on preventing vegetation related
outages. For instance: "Each Transmission Owner shall
prevent vegetation related outages (except as noted in
Footnote 2) of any of its applicable line(s) ..." Evidence of
outages is practical to gather and provide, evidence of
encroachment is not.
Modify the standard to be similar to the currently mandatory
Consideration of Comments on Successive Ballot of FAC-003-2
14
Voter
Entity
Segment
Vote
Comment
non-results based standard and focus on the word
"manage". This would essentially mean eliminating R1 and
R2 since the rest of the standard focuses on having a plan
and managing to that plan.
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Walt Gill
Lake Worth
Utilities
1
Negative
CLWU's concern is that entities may not be able prove
compliance with the standard. R1 and R2 say that: "Each
Transmission Owner shall manage vegetation to prevent
encroachments ...". If the requirements were interpreted
such that "manage" is the operative word, then, we are OK
because we can provide evidence of managing a program,
such as a vegetation management plan and evidence of
executing that plan (which does not align with the
Measures). However, that 1) would cause the standard to
not be performance based, and 2) it would be duplicative of
the other requirements of the standard.
If the requirements were interpreted with "prevent
encroachment" as the operative phrase (which would be an
incorrect interpretation from the construct of the sentence)
there is no way to provide sufficient evidence that
encroachment was prevented during the audit-period. The
suggested Measures are not sufficient evidence to prove
compliance with that interpretation of the requirement. For
instance, most encroachments do not result in outages;
hence, lack of outages cannot prove that there were no
Consideration of Comments on Successive Ballot of FAC-003-2
15
Voter
Entity
Segment
Vote
Comment
encroachments, and real time observations are insufficient
because it is a spot-check that does not cover the audit
period.
There are other weaknesses in the standard, such as R4
being un-measurable therefore unenforceable. However, in
the guilty until proven innocent paradigm we live in, FMPA's
primary concern is that industry could be put into a no-win
situation of not being able to prove compliance with the
standard if R1 and R2 are interpreted as "prevent
encroachment", and if R1 and R2 are interpreted as
"manage" then it is not a performance based standard as
advertised. CLWU suggests one of two approaches:
1. Performance based focused on preventing vegetation
related outages. For instance: "Each Transmission Owner
shall prevent vegetation related outages (except as noted in
Footnote 2) of any of its applicable line(s) ..." Evidence of
outages is practical to gather and provide, evidence of
encroachment is not.
2. Modify the standard to be similar to the currently
mandatory non-results based standard and focus on the
word "manage". This would essentially mean eliminating R1
and R2 since the rest of the standard focuses on having a
plan and managing to that plan..
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Consideration of Comments on Successive Ballot of FAC-003-2
16
Voter
Saurabh
Saksena
Entity
National Grid
Segment
1
Vote
Affirmative
Comment
The revised ROW definition emphasizes the ROW width
needed to operate the transmission line(s). It is National
Grid’s interpretation that the width established when the
line was constructed is the width to be maintained. This
width is documented in engineering drawings, per-2007
vegetation records or blow-out standards. This definition
does not imply that danger tree rights beyond the
constructed and maintained width are incorporated in the
definition; therefore fallins - from outside the ROW but
within an area with danger tree rights would not be
considered fallin-ins from within the ROW. National Grid
would like the SDT to comment on this interpretation in its
response to these comments.
Response: Your interpretation is consistent with the intent of the definition that the SDT provided. However the definition
includes a series of options that give the Transmission Owner latitude in establishing ROW width. It does not require selecting a
single method for its system. This phrase in the definition allows a TO to use its internal engineering standards or the general
engineering standards that were in effect when the line was constructed to determine the ROW width. The SDT has limited the
definition of Right-of-Way to a corridor of land with a defined width to operate a transmission line. This does not include
danger tree rights.
Michael T.
Quinn
Oncor Electric
Delivery
1
Affirmative
In footnote 2 (pg. 8) and 4 (page 10), the wording
“arboricultural activities or horticultural or agricultural
activities” should be deleted and replaced with “or removal
of, installation of, or digging around vegetation.”
Response: The SDT thanks you for your comments. The footnotes have been changed.
John C.
Collins
Platte River
Power
Authority
1
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
Vegetation Inspection: Is the intent of “... and those
vegetation conditions under the TO’s control” to clarify that
an entity must have ownership of the transmission line and
right-of-way in addition to maintenance or operational
responsibility (control), or something different? In situations
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where a TO owns one circuit on a double circuit, but the
other circuit, facilities and ROW belong to another TO who
has maintenance, and vegetation management
responsibility, who would be responsible for violations? If
the definition was modified to allow both maintenance and
vegetation inspections to be performed concurrently, the
intent might be clearer if it read: “This may be combined
with other line inspections”, or “This may be combined with
a maintenance inspection” opposed to a general line
inspection.
R1 and R2: Does R1 correlate to facilities in 4.2.2. and 4.2.3.
(overhead transmission lines operated below 200 kV) and
R2 correlate to facilities in 4.2.1. (overhead transmission
lines operated at 200kV or higher)? It isn’t clear why the
two requirements are split. Could it be one requirement
which reads “...identified as a facility in Section 4.2”?
R4: Our current imminent threat procedure requires a call
to the Manager who confirms the existence of a vegetation
condition that is likely to cause a Fault at any moment prior
to notifying the control center. We assume notification,
without any intentional time delay, would take place after
managerial confirmation but feel like the enforcement
authorities could interpret this differently based on how it is
written in R4. If the intent of the requirement is how we
interpret it, the requirement might be clearer if it read:
After a Transmission Owner has confirmed a vegetation
condition likely to cause a Fault at any moment, they shall
notify the control center holding switching authority for the
associated applicable transmission line, without any
Consideration of Comments on Successive Ballot of FAC-003-2
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intentional delay.
Response: The SDT thanks you for your comment. With regard to responsibility for a violation, the TO is the accountable party
even if it has an agreement with another TO to inspect and manage vegetation.
With regard to your suggestion in changing the definition of Vegetation Inspection, the SDT does not believe the proposed
changes are necessary for the definition to be clear.
With regard to R1 and R2, they applicability applies to 4.2.1 thru 4.2.3. The distinction between the requirement is R1 applies to
all lines designated as having an Interconnection Reliability Operating Limit (IROL) in the planning horizon by the Planning
Coordinator; or lines designated as Major Western Electricity Coordinating Council (WECC) transfer path(s).
With regard to your imminent threat procedure, the standard is not prescriptive to define a TO’s imminent threat procedure.
So, if your procedure includes managerial confirmation, then this would not be considered intentional delay.
Sammy
Roberts
Progress
Energy
Carolinas
1
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “or installation of."
Response: The SDT thanks you for your comments. The footnotes have been changed.
Laurie
Williams
Public Service
Company of
New Mexico
1
Negative
PNM is voting negative but offers the following comments
to improve the standard.
1. The last sentence of the Background on page 7 states:
Thus, this Standard’s emphasis is on vegetation grow-ins.
However, R1 says that we shall manage encroachments as
follows: R1. Each Transmission Owner shall manage
vegetation to prevent encroachment that could result in a
Sustained Outage encroachments of the types shown
Consideration of Comments on Successive Ballot of FAC-003-2
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below, into the Minimum Vegetation Clearance Distance
(MVCD) of....... 2. An encroachment due to a fall-in from
inside the active transmission line Right-of-Way (ROW) that
caused a vegetation-related Sustained Outage, This seems
contradictory.
2. Fac-003-2 makes reference to FAC-014 and a “Planning
Coordinator” in section 4.2.2 of Applicability: pg 5 see
below:
4.2.2. Overhead transmission lines operated below 200kV
having been identified as included in the definition of an
Interconnection Reliability Operating Limit (IROL) under
NERC Standard FAC-014 by the Planning Coordinator.
In addition, on pg 8, R1 of FAC-003-2 makes reference to the
“planning coordinator” However, FAC-014 makes no
reference, or at least it is inconsistent, to a “Planning
Coordinator” See below:
Taken from FAC-014
4. Applicability
4.1. Reliability Coordinator
4.2. Planning Authority
4.3. Transmission Planner
4.4. Transmission Operator
The terminology and definitions seem to be inconsistent.
Consideration of Comments on Successive Ballot of FAC-003-2
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3. R1 and R2 are the same requirements with different
applicabilities. R1 applies to lines that are connected to
WECC, IROL, etc. R2 applies to all other applicable lines that
are NOT an element of WECC or IROL. My Question is: If the
line is not part of WECC or IROL or any other connection
then, how is it applicable to the Standard?
4. R7 says the TO shall complete a %100 of annual plan but
allows for modifications that include:
Change in expected growth rate/ environmental factors
Major storms
Circumstances that are beyond the control of a Transmission
Owner5
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance
agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the
landowner
Funding adjustments (increase or decrease)
Emerging technologies
[VRF - Medium] [Time Horizon - Operations Planning]
The requirement says we shall complete a %100 of the
annual plan however, some of the modifications have
historically taken over a year to mitigate. SHALL should be
Consideration of Comments on Successive Ballot of FAC-003-2
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replaced with SHOULD with acceptable modifications and
without compromising integrity of system.
Response: The SDT thanks you for your comments.
Item 1: It is intended that the Standard will cover any situation within the ROW that causes an encroachment into the MVCD
including fall-ins, grow-ins or blowing-together. The arrangement of the Violation Severity Levels for R1. and R2. emphasize
that a grow-in results in the greatest risk to a power system, and also is the most egregious and severe failure to meet the
intent of these requirements.
Item 2: The term Planning Authority (PA) included in FAC-014 was replaced by NERC in the functional model Version 5 with
Planning Coordinator. Where references to PA are included in legacy Standards, Planning Coordinator is now used as follows
Planning Coordinator (Planning Authority). Obviously, proposed new Standards or versions must use the currently accepted
terms.
Item 3: R1 and R2 are dealing with the differentiation between lines that fall into IROL/WECC Transfer Path definition and
those lines that do not. Keep in mind that this standard refers to all transmission lines over 200-kV.
Item 4: The SDT believes replacing the word “shall” with the word “should” in Requirement 7 changes the requirement to a
recommendation.
Pawel
Krupa
Seattle City
Light
1
Affirmative
The revisions to the proposed FAC-003-2 Standards
produced a better version through greater clarity,
appropriate pragmatism, and technical foundation; A few
good points that highlight this follow:
1. Definition of Terms Used in Standard: The revised
definition of Right-of-Way (ROW) establishes the width of
the corridor from a technical basis with the following
statement "The width of the corridor is established by
engineering or construction standards..."
2. Introduction, Applicability, Section 4.2 Facilities: Section
4.2.4 which pertains to substations clarifies that this
standard does not apply to applicable transmission lines,
inside the substation, just to "any portion of the span of the
Consideration of Comments on Successive Ballot of FAC-003-2
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transmission line that is crossing the substation fence".
3. Requirements and Measures: Requirement 1 underscores
sensible purpose by replacing the wording of "preventing
outages from vegetation" to "manage vegetation to prevent
encroachments..."
4. Guideline and Technical Basis Section: Requirement 7
contains a great practicle reference explanation as it
pertains to the annual work plan. Requirement 7 explains:
..." the vegetation management approach should use the
full extent of the Transmission Owner's easement, fee
simple and other legal rights allowed. A comprehensive
approach that exercises the full extent of legal rights on the
ROW is superior to incremental management in the long
term because it reduces the overall potential for
encroachment, and it ensures that future planned work and
future planned inspection cycles are sufficient".
Response: The SDT thanks you for your comments.
William G.
Hutchison
Southern
Illinois Power
Coop.
1
Negative
I beleive that the reliability region should have the right to
exclude lines below 200KV. Not all lines above 100KV
negative impact the BES.
Response: The SDT thanks you for your comment. This issue is presently before FERC and NERC and is outside the scope of the
SDT.
Keith V
Carman
Tri-State G & T
Association,
Inc.
1
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “ installation of”.
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Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Brandy A
Dunn
Western Area
Power
Administration
1
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “ installation of”
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Gregory L
Pieper
Xcel Energy,
Inc.
1
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
Xcel Energy still believes the requirement in R6 that
mandates an annual inspection is an ineffective approach
and may actually go against the Commission’s
determination in FERC Order No. 693. The drafting team’s
response to our last round of comments on this issue was
that “...the SDT was directed by Order 693 to set a minimum
inspection criteria”. It is clear in Order 693 that the
Commission is not satisfied with allowing entities to choose
their own inspection cycles, as the standard currently
allows. However, we fail to see where the Commission
mandated a minimum inspection cycle to be uniformly
applied continent-wide. We urge the drafting team to revisit
paragraphs 719 through 721 of Order 693. According to
paragraph 721, the Commission recognizes that unique
intervals by region, “based on local factors”, are reasonable
and appropriate. By use of the plural term “cycles”, FERC
anticipates the resolution may include multiple inspection
cycles. Furthermore, in paragraph 719, FERC acknowledges
that a minimum inspection cycle may not be the only way to
address their concern. In fact, mandating an annual
inspection cycle may actually go against the Commission’s
guidance in paragraph 720. Here is an excerpt: “...the
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Commission is dissuaded from requiring the ERO to create a
backstop inspection cycle at this time. Instead, the
Commission agrees that an entity’s vegetation management
program should be tailored to anticipated growth in the
region and take into account other environmental factors.
The goal is to assure that transmission owners conduct
inspections at reasonable intervals.”
As an alternative, we propose a mid-cycle inspection. A midcycle inspection is based on an interval that is justified with
data and technical expertise. A mid-cycle inspection would
still require entities to conduct inspections at a specified
interval, while allowing for differences based upon “physical
and geographic factors”. Not only would this approach fully
address the Commissions concerns, but it would take into
account the interests of stakeholders, landowners and ratepayers. We recognize that a mid-cycle inspection interval is
not as easy to audit as an annual requirement, but it is a far
more practical and cost-effective approach that, when
applied based on an entity’s expertise with its own facilities,
ensures reliability.
Response: The SDT thanks you for your comments. The SDT recognizes that a number of Transmission Owners in North
America may prefer to set their own inspection intervals. The SDT can also see attractiveness for a mid-cycle inspection
concept; however, this introduces new complexities in planning, documentation and auditing. Because there is substantial
industry support for an annual inspection interval the SDT believes that the industry is best served with this approach.
Mark B
Thompson
Alberta
Electric
System
Operator
2
Consideration of Comments on Successive Ballot of FAC-003-2
Abstain
Due to slow vegetation growth rates in many parts of
Alberta, not all transmission right-of-ways require annual
inspection as required in R6. TOs should be able to include
planned inspection cycles in their Transmission Vegetation
Management Plan.
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Response: The SDT thanks you for your comments. In FERC Order 693, para. 721, FERC stated, “The Commission continues to
be concerned with leaving complete discretion to the transmission owners in determining inspection cycles, which limits the
effectiveness of the Reliability Standard.”
The SDT established an inspection cycle at least once per calendar year and with no more than 18 calendar months between
inspections on the same ROW. There was a survey of the industry in a previous request for comments to this standard. The
response to that survey is the basis for the use of the 1-year period. While there was a range of growth rates across the
continent, the SDT had sufficient feedback to recommend the 1-year cycle. The inspection also would cover inspecting for fallin threats. Please note that vegetation inspections can also be combined with other line inspections.
Alden Briggs
New
Brunswick
System
Operator
2
Affirmative
The term “encroachment” has to be defined, and the use of
that term and the clearances required clarification. The
Table listing the clearances also needed clarification.
Response: The SDT thanks you for your comment. The SDT endorses the standard dictionary definition of the term
“encroachment” and as such it does not require a NERC-specific definition. The use of encroachment regarding the clearance
table is explained in detail in the Technical Reference Document.”
Richard J.
Mandes
Alabama
Power
Company
3
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “ installation of”.
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Steven
Norris
APS
3
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
The objective, as written, is about outages that can lead to
cascading and not about reliability. Recommended change
to Standard Objective: To maintain a reliable electric
transmission system, implement a defense-in-depth
strategy to manage vegetation located on transmission
rights of way (ROW) and minimize encroachments from
vegetation located adjacent to the ROW.
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Response: The SDT thanks you for your comment. With respect to the Purpose as written in the proposed standard, the
language clearly states “To improve the reliability of the electric Transmission system…”. The SDT made it a point to keep the
Purpose as concise as possible without getting into issues that are covered further in the body of the standard.
Rebecca
Berdahl
Bonneville
Power
Administration
3
Affirmative
In R1 and R2 and their associated VSLs, the SDT added the
phrase “in order of increasing severity” and added the
sentence, “The types of encroachments are listed in order
of increasing degrees of severity in non-compliant
performance as it relates to a failure of a TO’s vegetation
maintenance program.” to the Rationale boxes for R1/R2.
Do you agree? If answer is no, please explain.
BPA prefers the stratified levels of violation severity
presented in the table for R1 and R2.
Foot note # 2 on page 8 needs to be clarified with respect to
arboricultural activities or horticultural or agricultural
activities.
Foot note # 4 on page 12 needs to be clarified with respect
to arboricultural activities or horticultural or agricultural
activities.
In response to comments received that requirement R3 is
unclear with respect to intent, the SDT added “maintenance
strategies.” Do you agree this clarifies the intent? If answer
is no, please offer alternative language.
The TO procedures / policies and specifications shall
demonstrate the TO’s ability to manage the system at all
rated conditions to maintain reliability. BPA believes that
the intent is clear, but the fundamental approach of using
the MVCD (table 2) to manage a vegetation program is still
Consideration of Comments on Successive Ballot of FAC-003-2
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problematic. These values are flashover distances and are
way too close. This is acknowledged in a footnote to table 2
but no identification of allowable buffers/distances
between energized phase conductors at rated temperatures
and vegetation is discussed (this is left up the transmission
owners). Clarity is needed on this topic. Setting a finite
distance limit based on recognized standards, good science
and risk avoidance should be done for the industry. BPA has
previously made this comment during the drafting of the
standard. It was not addressed then, nor has it been
addressed now.
Response: The SDT thanks you for your comments.
Footnotes #2 and #4 have been changed to reflect your suggestion to clarify arboricultural or horticultural or agricultural
activities.
With respect to comments about the MVCD, R3 does not suggest the MVCD be used as a distance to manage vegetation. The
MVCD was established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line
within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD
In a performance based standard, requirements are focused on “what” needs to be accomplished to achieve desired results
and avoids prescriptive requirements of “how” to achieve that result. TO’s are in the best position to determine the
appropriate management approach suited for their system, rather than a “one size fits all” or “fill in the blank” requirement
that could suppress best practices for vegetation management.
Matt
Culverhouse
City of Bartow,
Florida
3
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
The suggested Measures are not sufficient evidence to
prove compliance with that interpretation of the
requirement. For instance, most encroachments do not
result in outages; hence, lack of outages cannot prove that
there were no encroachments, and real time observations
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are insufficient because it is a spot-check that does not
cover the audit period.
There are other weaknesses in the standard, such as R4
being un-measurable therefore unenforceable. However, in
the guilty until proven innocent paradigm we live in, FMPA's
primary concern is that industry could be put into a no-win
situation of not being able to prove compliance with the
standard if R1 and R2 are interpreted as "prevent
encroachment", and if R1 and R2 are interpreted as
"manage" then it is not a performance based standard as
advertised.
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated. Also please reference footnote 3.
Bryan Y
Harper
Cleco Utility
Group
3
Negative
Cleco disagrees with the SDT revising the definition for
Right-of-Way (ROW). Right-of-Way is a term that has had a
consistent meaning throughout history. If NERC tries to
redefine the term, it will only add confusion because most
entities will not reference the NERC glossary for a term
which is widely used in the industry. In lieu of "Active
Transmission Line ROW", please use another term such as
Transmission Corridor. No assumptions would be made
when reading in the Standard the the Entity is to maintain
vegetation located within the Transmission Corridor. Since
the term is not commonly used, the NERC glossary would be
referenced.
Also, Cleco disagrees that an encroachment into the MCVD
Consideration of Comments on Successive Ballot of FAC-003-2
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that does not cause an outage should be considered noncompliant as stated in R1 and R2. The encroachment should
only be reportable similar to misoperations as is in the PRC004 standard.
Response: Thanks for your comments. The existing ROW definition in the glossary was created by and for the FAC-003-1 and
was moved there when that standard was adopted. The definition includes a series of options that give the Transmission
Owner latitude in establishing ROW width. It does not require selecting a single method for its system. The term blowout
standard is not capitalized and is not a defined term. This phrase in the definition allows a Transmission Owner to use its
internal engineering standards or the general engineering standards that were in effect when the line was constructed to
determine the ROW width. The SDT has limited the definition of Right-of-Way to a corridor of land with a defined width to
operate a transmission line. This does not include danger tree rights. The definition of the MVCD is now added to this Standard.
While use of the pre-2007 records is a compliance issue and is not in the purview of the SDT, it is the intent of the language in
the definition that you could use this information.
Regarding your second comment, the MVCD was established as a beginning of a series of “building blocks” for a program to
ensure reliability of a Transmission line within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD.
Other related requirements of this “Defense in Depth” Standard serve to address any number of scenarios which may arise or
hinder the TO’s ability to always strictly adhere to the management approach(s) established within R3. Thus the other
requirements of this Standard provide the latitude for appropriate actions to remedy the condition without penalty. Further,
trees which have encroached inside the MVCD are evidence of a deficiency in vegetation maintenance.
Peter T Yost
Consolidated
Edison Co. of
New York
3
Affirmative
Reply to Question 5 on Comment Form: The added language
for the annual work plan percentage complete calculation is
shown in R7 not M7 as stated in the question.
In the Guideline and Technical Basis Section for
Requirement R6, there is a sample calculation shown for the
amount of lines the TO failed to inspect. An example should
Consideration of Comments on Successive Ballot of FAC-003-2
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also be included for Requirement R7 since there is some
confusion regarding how modifications to the work plan
affect the calculation. In the Lower VSL column for R7, it
states that the TO failed to complete up to 5% of its annual
vegetation work plan (including modifications if any). If a TO
operates 100 lines and submits a justified modification that
affects 10 miles of lines, the total number of units in the
final amended plan is 90 miles. When you read the VSL, it is
somewhat confusing since the information in parenthesis
says that the calculation 'includes' the modifications. Should
it state 'excludes modifications if any' or the VSLs can simply
be re-written to state that ..The TO failed to complete up to
x% of the final amended plan.'
Also, the VSLs in R6 and R7 should be consistent with each
other: R6 says '...TO failed to inspect 5% or less.....' and R7
says '...TO failed to complete up to 5%....' They both should
use the same verbiage in each VSL whether it is 'x% or less'
or 'up to and including x%.'
Response: The SDT thanks you for your comments. Your correction is accurate.
The percentage should be based on the plan as modified. The SDT has changed the language in the standard to reflect this
more clearly.
The VSLs have been modified to be consistent as suggested.
David A.
Lapinski
Consumers
Energy
3
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
Comments on FAC-003-2 February 25, 2011
Consumers Energy submits the following comments on FAC003-2: In general we are please with FAC-003-2 and the
many clarifications that the STD has made in this version of
the standard. However, we do have one major
disagreement with the STD and cannot support this
standard as drafted.
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We disagree with the use of the Minimum Vegetation
Clearance Distance (MVCD) developed by the drafting team
for Requirements R1 and R2. These distances are not the
design distances used for designing and constructing
transmission facilities as stated in the document for
minimum distances between conductors and grounded
objects. The proposed Table 2 provides a distance of 3.12
feet as the acceptable distance for an alternate current
345kV line at sea level. This distance is considerably less
than the distance used for line design to separate the
grounded tower structure from the energized conductor. If
the distance in Table 2 is acceptable to prevent energized
portions of a transmission line from grounding to a tree why
then is this distance not the design criteria used for tower
design to prevent flashover from conductor to tower? The
STD needs to explain why a ground tree should have a
different standard that a grounded steel tower or wood
pole structure.
The STD erroneously viewed the possibility of transient over
voltage as only occurring during re-energizing and not from
natural events such as a lightning strike that can occur and
does occur to energized operating lines. Secondly, the
proposed distances in Table 2 are considerably less than the
distances specified in OSHA requirements for air gap
clearance required by tree workers to safely remove trees
or limbs from conductors energized at the voltages
specified. A transmission owner/operator could let a tree
grow to within 3.5 feet of a 345 kV line and not be in
violation of this proposed standard. To remove the tree, the
Consideration of Comments on Successive Ballot of FAC-003-2
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line would have to be de-energized, tagged, tested deenergized, and grounded. Working clearance would have to
be established by the operating entity and then the tree
crew could remove the tree. The net result is the loss of the
capacity of the line because an outage was forced on the
line in order to remove the tree that did not trigger a
violation of FAC-003-2. This situation, in our opinion, is a
violation of the intent of the standard, which is to ensure
the continued operation of the line. Therefore, the
minimum distance any tree should be able to approach a
conductor is more than the minimum requirement for air
gap distance between the tree and conductor as required by
OSHA worker standards. The STD did not like referring to
another standard to provide the distance requirements for
R1 and R2. This can be alleviated by putting in a table with
the IEEE 516 distances but not reference it as the IEEE 516
standard. The distances provided in the current draft do not
adequately provide or ensure the continued safe operation
of the transmission facilities in the United States and the
reasoning for the distances provided is unfounded and not
based on current design practices.
Response: The SDT thanks you for your comments. You are correct that these distances do not represent complete design
specifications for towers, nor define and describe safe worker approach distances. These practices are correctly specified in the
other standards you referenced. The SDT feels the standard is clear in that regard. The footnote associated with the Table 2
distances clearly states that these are only distances to prevent flashover under appropriate conditions. The SDT would also
like to point out that the transient overvoltage factors used to derive these distances are the maximums normally seen with a
transmission line in steady state service. Thus, a tower design would have to account for the larger overvoltage factors that are
possible while taking lines out of service.
As has been stated before, these distances were derived using a known set of line design equations and only represent
distances that will prevent spark-over from the transmission line to a grounded object. These are not distances to be managed
to – they have been established as a beginning of a series of “building blocks” for a program to ensure reliability of a
Consideration of Comments on Successive Ballot of FAC-003-2
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Comment
Transmission line within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner’ consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD.
These distances are smaller than safety standard distances that have many other factors involved in the determination, such as
inadvertent human movement and larger safety factors. In regard to the over-voltages caused by lightning, even the maximum
overvoltage factors contained in the IEEE-516 tables do not account for these.
Russell A
Noble
Cowlitz
County PUD
3
Negative
Referring back to Cowlitz’ negative vote made on the 7/919/2010 ballot, Cowlitz tried to convey the problem that the
statement in R4 “without intentional time delay” will
require subjective judgment on the part of the auditor. In
other words, maintaining equal auditing standard
throughout the interconnection will be impossible with this
verbiage in a requirement. Cowlitz agrees with the SDT that
establishing an equitable time frame is very difficult (it may
be impossible!); however leaving it to the judgment of the
auditor to determine whether an intentional delay was
made is most disagreeable. Cowlitz respectfully points out
that the SDT did not adequately address the subjective
nature the auditor is forced into with this requirement. If
establishing “[t]he time required by the to report an issue is
subject to many variables...” and “[f]or this reason it is
difficult to establish a time period which would fairly apply
to all TO’s,” how does leaving this to the auditor to decide
going to make it any better?
Response: The SDT believes that it was not prudent to suggest a quantitative time element for notification in R4. The technical
reference offers examples of acceptable unintentional delays for your review. The SDT notes that this language is already
embodied in at least one other FERC-approved, in-force Standard.
Consideration of Comments on Successive Ballot of FAC-003-2
34
Voter
Kevin
Querry
Entity
FirstEnergy
Solutions
Segment
3
Vote
Affirmative
Comment
FirstEnergy supports standard FAC-003-2 and would
appreciate consideration of our comments submitted
through the formal comment period.
Response: The SDT thanks you for your comments. Please see our consideration of your comments within the responses to
the formal comments.
Lee
Schuster
Florida Power
Corporation
3
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “installation of."
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Anthony L
Wilson
Georgia Power
Company
3
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “ installation of”.
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Charles
Locke
Kansas City
Power & Light
Co.
3
Negative
The Standard lacks clarity regarding the facilities that are
subject to Requirement 7. It is important that a Standard be
clear and not introduce ambiguity or confusion. There are
several references throughout the Standard to "for all
applicable lines" and it should be made clear the work plan
is specific to "all applicable lines".
Response: The SDT thanks you for your comments. The team has made the appropriate modifications where necessary.
Mace
Hunter
Lakeland
Electric
3
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
R1. Each Transmission Owner shall manage vegetation to
prevent encroachments of the types shown below, -----------35
Voter
Entity
Segment
Vote
Comment
---- and all Rated Electrical Operating Conditions.2 1. An
encroachment into the MVCD as shown in FAC-003-Table 2,
observed in Real-time, absent a Sustained Outage, that is
not corrected within 5 working days of discovery, Make the
same change to R2 Type 1 encroachment and reflect the
changes in Table 1. Rational: This condition would enable a
entity to discover an encroachment and clear it without
having to self report a possible violation as long as the
conditions was corrected within 5 working days. The change
should encourage extra inspections for problem areas more
often than annually as required in R6. There should be no
negative consequences for diligent inspection of lines as
long as the problem is clear with a defined time such as 5 or
10 working days.
Response: The SDT thanks you for your comment. As a general rule, a revised standard should not be less stringent than the
existing standard it replaces. In the existing standard, a violation occurs when the encroachment occurs. A ‘find and fix’ of five
days would be viewed as a lowering of the level of required performance established by the current standard.
Bruce
Merrill
Lincoln
Electric
System
3
Affirmative
While supportive of the drafting team’s efforts, LES believes
a change is warranted in Footnote 2 and Footnote 4 to
remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace with the
term “installation of”. As currently drafted, the wording
could potentially be construed to mean that the TO would
or could be constrained or refused permission to prune and
remove any and all vegetation in the ROW in accordance
with the full legal rights of the ROW agreement(s).
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Don Horsley
Mississippi
Power
3
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
36
Voter
Entity
Segment
Vote
Comment
horticultural or agricultural activities” and replace it with
the term “ installation of”.
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Terry L
Baker
Platte River
Power
Authority
3
Negative
FAC-003-2 Comments Vegetation Inspection: Is the intent of
“... and those vegetation conditions under the TO’s control”
to clarify that an entity must have ownership of the
transmission line and right-of-way in addition to
maintenance or operational responsibility (control), or
something different? In situations where a TO owns one
circuit on a double circuit, but the other circuit, facilities and
ROW belong to another TO who has maintenance, and
vegetation management responsibility, who would be
responsible for violations?
If the definition was modified to allow both maintenance
and vegetation inspections to be performed concurrently,
the intent might be clearer if it read: “This may be combined
with other line inspections”, or “This may be combined with
a maintenance inspection” opposed to a general line
inspection.
R1 and R2: Does R1 correlate to facilities in 4.2.2. and 4.2.3.
(overhead transmission lines operated below 200 kV) and
R2 correlate to facilities in 4.2.1. (overhead transmission
lines operated at 200kV or higher)? It isn’t clear why the
two requirements are split. Could it be one requirement
which reads “...identified as a facility in Section 4.2”?
R4: Our current imminent threat procedure requires a call
Consideration of Comments on Successive Ballot of FAC-003-2
37
Voter
Entity
Segment
Vote
Comment
to the Manager who confirms the existence of a vegetation
condition that is likely to cause a Fault at any moment prior
to notifying the control center. We assume notification,
without any intentional time delay, would take place after
managerial confirmation but feel like the enforcement
authorities could interpret this differently based on how it is
written in R4. If the intent of the requirement is how we
interpret it, the requirement might be clearer if it read:
After a Transmission Owner has confirmed a vegetation
condition likely to cause a Fault at any moment, they shall
notify the control center holding switching authority for the
associated applicable transmission line, without any
intentional delay.
Response: The SDT thanks you for your comment. With regard to responsibility for a violation, the TO is the accountable party
even if it has an agreement with another TO to inspect and manage vegetation.
With regard to your suggestion in changing the definition of Vegetation Inspection, the SDT does not believe the proposed
changes are necessary for the definition to be clear.
With regard to R1 and R2, they applicability applies to 4.2.1 thru 4.2.3. The distinction between the requirement is R1 applies to
all lines designated as having an Interconnection Reliability Operating Limit (IROL) in the planning horizon by the Planning
Coordinator; or lines designated as Major Western Electricity Coordinating Council (WECC) transfer path(s).
With regard to your imminent threat procedure, the standard is not prescriptive to define a TO’s imminent threat procedure.
So, if your procedure includes managerial confirmation, then this would not be considered intentional delay.
Dana
Wheelock
Seattle City
Light
3
Affirmative
The revisions to the proposed FAC-003-2 Standards
produced a better version through greater clarity,
appropriate pragmatism, and technical foundation; A few
good points that highlight this follow:
1. Definition of Terms Used in Standard: The revised
definition of Right-of-Way (ROW) establishes the width of
the corridor from a technical basis with the following
Consideration of Comments on Successive Ballot of FAC-003-2
38
Voter
Entity
Segment
Vote
Comment
statement "The width of the corridor is established by
engineering or construction standards..."
2. Introduction, Applicability, Section 4.2 Facilities: Section
4.2.4 which pertains to substations clarifies that this
standard does not apply to applicable transmission lines,
inside the substation, just to "any portion of the span of the
transmission line that is crossing the substation fence".
3. Requirements and Measures: Requirement 1 underscores
sensible purpose by replacing the wording of "preventing
outages from vegetation" to "manage vegetation to prevent
encroachments..."
4. Guideline and Technical Basis Section: Requirement 7
contains a great practicle reference explanation as it
pertains to the annual work plan. Requirement 7 explains:
..." the vegetation management approach should use the
full extent of the Transmission Owner's easement, fee
simple and other legal rights allowed. A comprehensive
approach that exercises the full extent of legal rights on the
ROW is superior to incremental management in the long
term because it reduces the overall potential for
encroachment, and it ensures that future planned work and
future planned inspection cycles are sufficient".
Response: The SDT thanks you for your comments.
Michael
Ibold
Xcel Energy,
Inc.
3
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
Xcel Energy still believes the requirement in R6 that
mandates an annual inspection is an ineffective approach
and may actually go against the Commission’s
39
Voter
Entity
Segment
Vote
Comment
determination in FERC Order No. 693. The drafting team’s
response to our last round of comments on this issue was
that “...the SDT was directed by Order 693 to set a minimum
inspection criteria”. It is clear in Order 693 that the
Commission is not satisfied with allowing entities to choose
their own inspection cycles, as the standard currently
allows. However, we fail to see where the Commission
mandated a minimum inspection cycle to be uniformly
applied continent-wide. We urge the drafting team to revisit
paragraphs 719 through 721 of Order 693. According to
paragraph 721, the Commission recognizes that unique
intervals by region, “based on local factors”, are reasonable
and appropriate. By use of the plural term “cycles”, FERC
anticipates the resolution may include multiple inspection
cycles. Furthermore, in paragraph 719, FERC acknowledges
that a minimum inspection cycle may not be the only way to
address their concern. In fact, mandating an annual
inspection cycle may actually go against the Commission’s
guidance in paragraph 720. Here is an excerpt: “...the
Commission is dissuaded from requiring the ERO to create a
backstop inspection cycle at this time. Instead, the
Commission agrees that an entity’s vegetation management
program should be tailored to anticipated growth in the
region and take into account other environmental factors.
The goal is to assure that transmission owners conduct
inspections at reasonable intervals.”
As an alternative, we propose a mid-cycle inspection. A midcycle inspection is based on an interval that is justified with
data and technical expertise. A mid-cycle inspection would
still require entities to conduct inspections at a specified
interval, while allowing for differences based upon “physical
Consideration of Comments on Successive Ballot of FAC-003-2
40
Voter
Entity
Segment
Vote
Comment
and geographic factors”. Not only would this approach fully
address the Commissions concerns, but it would take into
account the interests of stakeholders, landowners and ratepayers. We recognize that a mid-cycle inspection interval is
not as easy to audit as an annual requirement, but it is a far
more practical and cost-effective approach that, when
applied based on an entity’s expertise with its own facilities,
ensures reliability.
Response: The SDT thanks you for your comments. The SDT recognizes that a number of Transmission Owners in North
America may prefer to set their own inspection intervals. The SDT can also see attractiveness for a mid-cycle inspection
concept; however, this introduces new complexities in planning, documentation and auditing. Because there is substantial
industry support for an annual inspection interval the SDT believes that the industry is best served with this approach.
Rick Syring
Cowlitz
County PUD
4
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
Referring back to Cowlitz’ negative vote made on the 7/919/2010 ballot, Cowlitz tried to convey the problem that the
statement in R4 “without intentional time delay” will
require subjective judgment on the part of the auditor. In
other words, maintaining equal auditing standard
throughout the interconnection will be impossible with this
verbiage in a requirement. Cowlitz agrees with the SDT that
establishing an equitable time frame is very difficult (it may
be impossible!); however leaving it to the judgment of the
auditor to determine whether an intentional delay was
made is most disagreeable. Cowlitz respectfully points out
that the SDT did not adequately address the subjective
nature the auditor is forced into with this requirement. If
“[t]he time required by the entity to report an issue is
subject to many variables...” and “[f]or this reason it is
difficult to establish a time period which would fairly apply
to all TO’s,” how does leaving this to the auditor to decide
going to make it any better? You will be forcing the audited
entity to "prove the negative."
41
Voter
Entity
Segment
Vote
Comment
Response: The SDT believes that it was not prudent to suggest a quantitative time element for notification in R4. The technical
reference offers examples of acceptable unintentional delays for your review. The SDT notes that this language is already
embodied in at least one other FERC-approved, in-force Standard.
Frank
Gaffney
Florida
Municipal
Power Agency
4
Negative
R1 and R2 requirement reads: "Each Transmission Owner
shall manage to prevent encroachment ....". The results of
manage would be invoices of tree trimming actually
performed, documentation of a vegetation management
program that would be managed to, etc. However, the
Measures proposed are all actual outages which are neither
evidence of management nor evidence of encroachment
since there can be encroachment without an outage, and in
fact, many if not most encroachments do not result in
outages. Hence, the Measures are inconsistent with the
requirements.
Further, there is ambiguity of the action required in
requirements R1 and R2 - e.g., do entities need evidence
that they: 1) "manage", or 2) "prevent encroachment"; or 3)
as implied by the Measures, prevent vegetation related
outages?. In other words, what needs to be proven through
evidence? Certainly the third, prevent vegetation related
outages, is not in the Requirement; yet, that us what is
proposed for the Measures, highlighting the inconsistency
between Requirements and Measures. But, how would the
ambiguity between "manage" and "prevent encroachment"
be resolved? One auditor could interpret that the
requirement is to "manage" and accept a vegetation
management program and plan and proof that the plan was
executed as appropriate evidence. Another auditor could
interpret that "prevent" is the key word and look for
evidence proving that there was never a vegetation
Consideration of Comments on Successive Ballot of FAC-003-2
42
Voter
Entity
Segment
Vote
Comment
encroachment. How would evidence be produced to
provide the auditor that vegetation never encroached?
Would video cameras and other surveillance measures need
to operate 24 hours a day? Would we cause an entity to
survey the lines periodically? One can easily see that
"prevent encroachment" is inappropriate here since it is
infeasible to create evidence of compliance.
FMPA suggests one of two approaches:
Eliminate the word manage, but do not focus on
encroachment and instead focus on outages. For instance:
"Each Transmission Owner shall prevent vegetation related
outages (except as noted in Footnote 2) of any of its
applicable line(s) ..." Evidence of outages is practical to
gather and provide, evidence of encroachment is not.
Focus on the word "manage", similar to the existing FAC003 standard, and move R3 to a new R1 to develop a
management plan, and then the existing R1 and R2 become
R2 an R3 and require execution of that plan in the words of
R7, which would in turn enables elimination of R7.
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Thomas W.
Richards
Fort Pierce
Utilities
4
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
R1 and R2 requirement reads: "Each Transmission Owner
shall manage to prevent encroachment ....". The results of
43
Voter
Entity
Authority
Segment
Vote
Comment
manage would be invoices of tree trimming actually
performed, documentation of a vegetation management
program that would be managed to, etc. However, the
Measures proposed are all actual outages which are neither
evidence of management nor evidence of encroachment
since there can be encroachment without an outage, and in
fact, many if not most encroachments do not result in
outages. Hence, the Measures are inconsistent with the
requirements.
Further, there is ambiguity of the action required in
requirements R1 and R2 - e.g., do entities need evidence
that they: 1) "manage", or 2) "prevent encroachment"; or 3)
as implied by the Measures, prevent vegetation related
outages?. In other words, what needs to be proven through
evidence? Certainly the third, prevent vegetation related
outages, is not in the Requirement; yet, that us what is
proposed for the Measures, highlighting the inconsistency
between Requirements and Measures. But, how would the
ambiguity between "manage" and "prevent encroachment"
be resolved? One auditor could interpret that the
requirement is to "manage" and accept a vegetation
management program and plan and proof that the plan was
executed as appropriate evidence. Another auditor could
interpret that "prevent" is the key word and look for
evidence proving that there was never a vegetation
encroachment. How would evidence be produced to
provide the auditor that vegetation never encroached?
Would video cameras and other surveillance measures need
to operate 24 hours a day? Would we cause an entity to
survey the lines periodically? One can easily see that
"prevent encroachment" is inappropriate here since it is
Consideration of Comments on Successive Ballot of FAC-003-2
44
Voter
Entity
Segment
Vote
Comment
infeasible to create evidence of compliance.
FPUA suggests one of two approaches:
1. Eliminate the word manage, but do not focus on
encroachment and instead focus on outages. For instance:
"Each Transmission Owner shall prevent vegetation related
outages (except as noted in Footnote 2) of any of its
applicable line(s) ..." Evidence of outages is practical to
gather and provide, evidence of encroachment is not.
2. Focus on the word "manage", similar to the existing FAC003 standard, and move R3 to a new R1 to develop a
management plan, and then the existing R1 and R2 become
R2 an R3 and require execution of that plan in the words of
R7, which would in turn enables elimination of R7.
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Joseph G.
DePoorter
Madison Gas
and Electric
Co.
4
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
“While supportive of the drafting team’s efforts, The MGE
believes a change is warranted in Footnote 2 and Footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace with the
term “installation of”. As currently drafted, the wording
could potentially be construed to mean that the TO would
or could be constrained or refused permission to prune and
remove any and all vegetation in the ROW in accordance
45
Voter
Entity
Segment
Vote
Comment
with the full legal rights of the ROW agreement(s).”
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Douglas
Hohlbaugh
Ohio Edison
Company
4
Affirmative
FirstEnergy supports standard FAC-003-2 and would
appreciate consideration of our comments submitted
through the formal comment period.
Response: The SDT thanks you for your comments. Please see our consideration of your comments within the responses to
the formal comments.
Hao Li
Seattle City
Light
4
Affirmative
The revisions to the proposed FAC-003-2 Standards
produced a better version through greater clarity,
appropriate pragmatism, and technical foundation; A few
good points that highlight this follow:
1. Definition of Terms Used in Standard: The revised
definition of Right-of-Way (ROW) establishes the width of
the corridor from a technical basis with the following
statement "The width of the corridor is established by
engineering or construction standards..."
2. Introduction, Applicability, Section 4.2 Facilities: Section
4.2.4 which pertains to substations clarifies that this
standard does not apply to applicable transmission lines,
inside the substation, just to "any portion of the span of the
transmission line that is crossing the substation fence".
3. Requirements and Measures: Requirement 1 underscores
sensible purpose by replacing the wording of "preventing
outages from vegetation" to "manage vegetation to prevent
encroachments..."
Consideration of Comments on Successive Ballot of FAC-003-2
46
Voter
Entity
Segment
Vote
Comment
4. Guideline and Technical Basis Section: Requirement 7
contains a great practicle reference explanation as it
pertains to the annual work plan. Requirement 7 explains:
..." the vegetation management approach should use the
full extent of the Transmission Owner's easement, fee
simple and other legal rights allowed. A comprehensive
approach that exercises the full extent of legal rights on the
ROW is superior to incremental management in the long
term because it reduces the overall potential for
encroachment, and it ensures that future planned work and
future planned inspection cycles are sufficient".
Response: The SDT thanks you for your comments.
Brock
Ondayko
AEP Service
Corp.
5
Affirmative
American Electric Power believes that the phrase
"arboricultural activities or horticultural or agricultural
activities" was mistakenly introduced into Footnotes 2 and
4, and should be deleted from both footnotes. If the phrase
remains in the Standard, it may empower orchard growers,
landowners and others to plant trees on the right of way
and challenge Transmission Owners' rights to perform
maintenance on the presumption that the standard will
exempt the TO from violating the outage or encroachment
requirements.
For increased clarity, AEP offers the following change to the
second paragraph of M1, as well as the second paragraph of
M2. The original text “If a later confirmation of a Fault by
the Transmission Owner shows that a vegetation
encroachment within the MVCD has occurred from
vegetation within the ROW, this shall be considered the
Consideration of Comments on Successive Ballot of FAC-003-2
47
Voter
Entity
Segment
Vote
Comment
equivalent of a Real-time observation” should be replaced
with “If a later confirmation of a Fault by the Transmission
Owner shows that a vegetation encroachment within the
MVCD has occurred from vegetation growing into or
blowing together with the conductor within the ROW, this
shall be considered the equivalent of a Real-time
observation. A brief encroachment caused by falling
vegetation passing through the MVCD is not considered an
encroachment in this requirement”.
Response: Thanks you for your comments. The SDT made suggested changes.
Regarding the issue of fall-ins, the SDT is sympathetic to your concern. In fact, the SDT had originally crafted language similar to
that which you suggested. However, due to concerns expressed by regulators and others, the exemption for encroachment
violations due to falling vegetation from inside the right of way was removed.
Francis J.
Halpin
Bonneville
Power
Administration
5
Affirmative
In R1 and R2 and their associated VSLs, the SDT added the
phrase “in order of increasing severity” and added the
sentence, “The types of encroachments are listed in order
of increasing degrees of severity in non-compliant
performance as it relates to a failure of a TO’s vegetation
maintenance program.” to the Rationale boxes for R1/R2.
Do you agree? If answer is no, please explain.
BPA prefers the stratified levels of violation severity
presented in the table for R1 and R2.
Foot note # 2 on page 8 needs to be clarified with respect to
arboricultural activities or horticultural or agricultural
activities.
Foot note # 4 on page 12 needs to be clarified with respect
to arboricultural activities or horticultural or agricultural
activities.
Consideration of Comments on Successive Ballot of FAC-003-2
48
Voter
Entity
Segment
Vote
Comment
In response to comments received that requirement R3 is
unclear with respect to intent, the SDT added “maintenance
strategies.” Do you agree this clarifies the intent? If answer
is no, please offer alternative language. The TO procedures /
policies and specifications shall demonstrate the TO’s ability
to manage the system at all rated conditions to maintain
reliability.
BPA believes that the intent is clear, but the fundamental
approach of using the MVCD (table 2) to manage a
vegetation program is still problematic. These values are
flashover distances and are way too close. This is
acknowledged in a footnote to table 2 but no identification
of allowable buffers/distances between energized phase
conductors at rated temperatures and vegetation is
discussed (this is left up the transmission owners). Clarity is
needed on this topic. Setting a finite distance limit based on
recognized standards, good science and risk avoidance
should be done for the industry. BPA has previously made
this comment during the drafting of the standard. It was not
addressed then, nor has it been addressed now.
Response: The SDT thanks you for your comments. The footnotes were changed to conform with your suggestions.
With respect to comments about the MVCD, R3 does not suggest the MVCD be used as a distance to manage vegetation. The
MVCD was established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line
within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD distances.
Consideration of Comments on Successive Ballot of FAC-003-2
49
Voter
Entity
Segment
Vote
Comment
In a performance based standard, requirements are focused on “what” needs to be accomplished to achieve desired results
and avoids prescriptive requirements of “how” to achieve that result. TO’s are in the best position to determine the
appropriate management approach suited for their system rather than a “one size fits all” or “fill in the blanks” requirements
that could suppress best practices for vegetation management.
Wilket
(Jack) Ng
Consolidated
Edison Co. of
New York
5
Affirmative
Reply to Question 5 on Comment Form: The added language
for the annual work plan percentage complete calculation is
shown in R7 not M7 as stated in the question. In the
Guideline and Technical Basis Section for Requirement R6,
there is a sample calculation shown for the amount of lines
the TO failed to inspect. An example should also be included
for Requirement R7 since there is some confusion regarding
how modifications to the work plan affect the calculation. In
the Lower VSL column for R7, it states that the TO failed to
complete up to 5% of its annual vegetation work plan
(including modifications if any). If a TO operates 100 lines
and submits a justified modification that affects 10 miles of
lines, the total number of units in the final amended plan is
90 miles. When you read the VSL, it is somewhat confusing
since the information in parenthesis says that the
calculation 'includes' the modifications. Should it state
'excludes modifications if any' or the VSLs can simply be rewritten to state that ..The TO failed to complete up to x% of
the final amended plan.'
Also, the VSLs in R6 and R7 should be consistent with each
other: R6 says '...TO failed to inspect 5% or less.....' and R7
says '...TO failed to complete up to 5%....' They both should
use the same verbiage in each VSL whether it is 'x% or less'
or 'up to and including x%.'
Consideration of Comments on Successive Ballot of FAC-003-2
50
Voter
Entity
Segment
Vote
Comment
Response: The SDT thanks you for your comments.
The percentage should be based on the plan as modified. The SDT has changed the language in the standard to reflect this
more clearly, and has modified the VSLs to be consistent as you have suggested.
James B
Lewis
Consumers
Energy
5
Negative
Consumers Energy submits the following comments on FAC003-2: In general we are please with FAC-003-2 and the
many clarifications that the STD has made in this version of
the standard. However, we do have one major
disagreement with the STD and cannot support this
standard as drafted.
We disagree with the use of the Minimum Vegetation
Clearance Distance (MVCD) developed by the drafting team
for Requirements R1 and R2. These distances are not the
design distances used for designing and constructing
transmission facilities as stated in the document for
minimum distances between conductors and grounded
objects. The proposed Table 2 provides a distance of 3.12
feet as the acceptable distance for an alternate current
345kV line at sea level. This distance is considerably less
than the distance used for line design to separate the
grounded tower structure from the energized conductor. If
the distance in Table 2 is acceptable to prevent energized
portions of a transmission line from grounding to a tree why
then is this distance not the design criteria used for tower
design to prevent flashover from conductor to tower? The
STD needs to explain why a ground tree should have a
different standard that a grounded steel tower or wood
pole structure.
The STD erroneously viewed the possibility of transient over
Consideration of Comments on Successive Ballot of FAC-003-2
51
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Entity
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Consideration of Comments on Successive Ballot of FAC-003-2
Vote
Comment
voltage as only occurring during re-energizing and not from
natural events such as a lightning strike that can occur and
does occur to energized operating lines. Secondly, the
proposed distances in Table 2 are considerably less than the
distances specified in OSHA requirements for air gap
clearance required by tree workers to safely remove trees
or limbs from conductors energized at the voltages
specified. A transmission owner/operator could let a tree
grow to within 3.5 feet of a 345 kV line and not be in
violation of this proposed standard. To remove the tree, the
line would have to be de-energized, tagged, tested deenergized, and grounded. Working clearance would have to
be established by the operating entity and then the tree
crew could remove the tree. The net result is the loss of the
capacity of the line because an outage was forced on the
line in order to remove the tree that did not trigger a
violation of FAC-003-2. This situation, in our opinion, is a
violation of the intent of the standard, which is to ensure
the continued operation of the line. Therefore, the
minimum distance any tree should be able to approach a
conductor is more than the minimum requirement for air
gap distance between the tree and conductor as required by
OSHA worker standards. The STD did not like referring to
another standard to provide the distance requirements for
R1 and R2. This can be alleviated by putting in a table with
the IEEE 516 distances but not reference it as the IEEE 516
standard. The distances provided in the current draft do not
adequately provide or ensure the continued safe operation
of the transmission facilities in the United States and the
reasoning for the distances provided is unfounded and not
based on current design practices.
52
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Response: The SDT thanks you for your comments. You are correct that these distances do not represent complete design
specifications for towers, nor define and describe safe worker approach distances. These practices are correctly specified in the
other standards you referenced. The SDT feels the standard is clear in that regard. The footnote associated with the Table 2
distances clearly states that these are only distances to prevent flashover under appropriate conditions. The SDT would also
like to point out that the transient overvoltage factors used to derive these distances are the maximums normally seen with a
transmission line in steady state service. Thus, a tower design would have to account for the larger overvoltage factors that are
possible while taking lines out of service.
As has been stated before, these distances were derived using a known set of line design equations and only represent
distances that will prevent spark-over from the transmission line to a grounded object. These are not distances to be managed
to – they have been established as a beginning of a series of “building blocks” for a program to ensure reliability of a
Transmission line within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD.
These distances are smaller than safety standard distances that have many other factors involved in the determination, such as
inadvertent human movement and larger safety factors. In regard to the over-voltages caused by lightning, even the maximum
overvoltage factors contained in the IEEE-516 tables do not account for these.
Bob Essex
Cowlitz
County PUD
5
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
Referring back to Cowlitz’ negative vote made on the 7/919/2010 ballot, Cowlitz tried to convey the problem that the
statement in R4 “without intentional time delay” will
require subjective judgment on the part of the auditor. In
other words, maintaining equal auditing standard
throughout the interconnection will be impossible with this
verbiage in a requirement. Cowlitz agrees with the SDT that
establishing an equitable time frame is very difficult (it may
be impossible!); however leaving it to the judgment of the
auditor to determine whether an intentional delay was
made is most disagreeable. Cowlitz respectfully points out
that the SDT did not adequately address the subjective
nature the auditor is forced into with this requirement. If
53
Voter
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Segment
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Comment
establishing “[t]he time required by the to report an issue is
subject to many variables...” and “[f]or this reason it is
difficult to establish a time period which would fairly apply
to all TO’s,” how does leaving this to the auditor to decide
going to make it any better?
Response: The SDT believes that it was not prudent to suggest a quantitative time element for notification in R4. The technical
reference offers examples of acceptable unintentional delays for your review. The SDT notes that this language is already
embodied in at least one other FERC-approved, in-force Standard.
Kenneth
Dresner
FirstEnergy
Solutions
5
Affirmative
FirstEnergy supports standard FAC-003-2 and would
appreciate consideration of our comments submitted
through the formal comment period.
Response: The SDT thanks you for your comments. Please see our consideration of your comments within the responses to
the formal comments.
David
Schumann
Florida
Municipal
Power Agency
5
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
R1 and R2 requirement reads: "Each Transmission Owner
shall manage to prevent encroachment ....". The results of
manage would be invoices of tree trimming actually
performed, documentation of a vegetation management
program that would be managed to, etc. However, the
Measures proposed are all actual outages which are neither
evidence of management nor evidence of encroachment
since there can be encroachment without an outage, and in
fact, many if not most encroachments do not result in
outages. Hence, the Measures are inconsistent with the
requirements.
Further, there is ambiguity of the action required in
requirements R1 and R2 - e.g., do entities need evidence
that they: 1) "manage", or 2) "prevent encroachment"; or 3)
as implied by the Measures, prevent vegetation related
outages?. In other words, what needs to be proven through
evidence? Certainly the third, prevent vegetation related
54
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outages, is not in the Requirement; yet, that us what is
proposed for the Measures, highlighting the inconsistency
between Requirements and Measures. But, how would the
ambiguity between "manage" and "prevent encroachment"
be resolved? One auditor could interpret that the
requirement is to "manage" and accept a vegetation
management program and plan and proof that the plan was
executed as appropriate evidence. Another auditor could
interpret that "prevent" is the key word and look for
evidence proving that there was never a vegetation
encroachment. How would evidence be produced to
provide the auditor that vegetation never encroached?
Would video cameras and other surveillance measures need
to operate 24 hours a day? Would we cause an entity to
survey the lines periodically? One can easily see that
"prevent encroachment" is inappropriate here since it is
infeasible to create evidence of compliance. FMPA suggests
one of two approaches: Eliminate the word manage, but do
not focus on encroachment and instead focus on outages.
For instance: "Each Transmission Owner shall prevent
vegetation related outages (except as noted in Footnote 2)
of any of its applicable line(s) ..." Evidence of outages is
practical to gather and provide, evidence of encroachment
is not. Focus on the word "manage", similar to the existing
FAC-003 standard, and move R3 to a new R1 to develop a
management plan, and then the existing R1 and R2 become
R2 an R3 and require execution of that plan in the words of
R7, which would in turn enables elimination of R7.
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
Consideration of Comments on Successive Ballot of FAC-003-2
55
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Entity
Segment
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Comment
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Richard J.
Padilla
Pacific Gas
and Electric
Company
5
Affirmative
There needs to be a change in the footnotes 2 and 4 to
remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “ installation of"
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Wayne
Lewis
Progress
Energy
Carolinas
5
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “installation of.
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Liam
Noailles
Xcel Energy,
Inc.
5
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
Xcel Energy still believes the requirement in R6 that
mandates an annual inspection is an ineffective approach
and may actually go against the Commission’s
determination in FERC Order No. 693. The drafting team’s
response to our last round of comments on this issue was
that “...the SDT was directed by Order 693 to set a minimum
inspection criteria”. It is clear in Order 693 that the
Commission is not satisfied with allowing entities to choose
their own inspection cycles, as the standard currently
allows. However, we fail to see where the Commission
mandated a minimum inspection cycle to be uniformly
applied continent-wide. We urge the drafting team to revisit
paragraphs 719 through 721 of Order 693. According to
paragraph 721, the Commission recognizes that unique
intervals by region, “based on local factors”, are reasonable
and appropriate. By use of the plural term “cycles”, FERC
anticipates the resolution may include multiple inspection
56
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Segment
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Comment
cycles. Furthermore, in paragraph 719, FERC acknowledges
that a minimum inspection cycle may not be the only way to
address their concern. In fact, mandating an annual
inspection cycle may actually go against the Commission’s
guidance in paragraph 720. Here is an excerpt: “...the
Commission is dissuaded from requiring the ERO to create a
backstop inspection cycle at this time. Instead, the
Commission agrees that an entity’s vegetation management
program should be tailored to anticipated growth in the
region and take into account other environmental factors.
The goal is to assure that transmission owners conduct
inspections at reasonable intervals.”
As an alternative, we propose a mid-cycle inspection. A midcycle inspection is based on an interval that is justified with
data and technical expertise. A mid-cycle inspection would
still require entities to conduct inspections at a specified
interval, while allowing for differences based upon “physical
and geographic factors”. Not only would this approach fully
address the Commissions concerns, but it would take into
account the interests of stakeholders, landowners and ratepayers. We recognize that a mid-cycle inspection interval is
not as easy to audit as an annual requirement, but it is a far
more practical and cost-effective approach that, when
applied based on an entity’s expertise with its own facilities,
ensures reliability.
Response: The SDT thanks you for your comments. The SDT recognizes that a number of Transmission Owners in North
America may prefer to set their own inspection intervals. The SDT can also see attractiveness for a mid-cycle inspection
concept; however, this introduces new complexities in planning, documentation and auditing. Because there is substantial
industry support for an annual inspection interval , the SDT believes that the industry is best served with this approach.
Consideration of Comments on Successive Ballot of FAC-003-2
57
Voter
Edward P.
Cox
Entity
AEP Marketing
Segment
6
Vote
Affirmative
Comment
American Electric Power believes that the phrase
"arboricultural activities or horticultural or agricultural
activities" was mistakenly introduced into Footnotes 2 and
4, and should be deleted from both footnotes. If the phrase
remains in the Standard, it may empower orchard growers,
landowners and others to plant trees on the right of way
and challenge Transmission Owners' rights to perform
maintenance on the presumption that the standard will
exempt the TO from violating the outage or encroachment
requirements.
For increased clarity, AEP offers the following change to the
second paragraph of M1, as well as the second paragraph of
M2. The original text “If a later confirmation of a Fault by
the Transmission Owner shows that a vegetation
encroachment within the MVCD has occurred from
vegetation within the ROW, this shall be considered the
equivalent of a Real-time observation” should be replaced
with “If a later confirmation of a Fault by the Transmission
Owner shows that a vegetation encroachment within the
MVCD has occurred from vegetation growing into or
blowing together with the conductor within the ROW, this
shall be considered the equivalent of a Real-time
observation. A brief encroachment caused by falling
vegetation passing through the MVCD is not considered an
encroachment in this requirement”.
Response: Thanks you for your comments. The SDT made the suggested changes to the footnotes.
Regarding the issue of fall-ins, the SDT is sympathetic to your concern. In fact, the SDT had originally crafted language similar to
that which you suggested. However, due to concerns expressed by regulators and others, the exemption for encroachment
violations due to falling vegetation from inside the right of way was removed.
Consideration of Comments on Successive Ballot of FAC-003-2
58
Voter
Brenda S.
Anderson
Entity
Bonneville
Power
Administration
Segment
6
Vote
Affirmative
Comment
BPA Comments with Yes Vote: In R1 and R2 and their
associated VSLs, the SDT added the phrase “in order of
increasing severity” and added the sentence, “The types of
encroachments are listed in order of increasing degrees of
severity in non-compliant performance as it relates to a
failure of a TO’s vegetation maintenance program.” to the
Rationale boxes for R1/R2. Do you agree? If answer is no,
please explain.
BPA prefers the stratified levels of violation severity
presented in the table for R1 and R2.
Foot note # 2 on page 8 needs to be clarified with respect to
arboricultural activities or horticultural or agricultural
activities.
Foot note # 4 on page 12 needs to be clarified with respect
to arboricultural activities or horticultural or agricultural
activities.
In response to comments received that requirement R3 is
unclear with respect to intent, the SDT added “maintenance
strategies.” Do you agree this clarifies the intent? If answer
is no, please offer alternative language. The TO procedures /
policies and specifications shall demonstrate the TO’s ability
to manage the system at all rated conditions to maintain
reliability.
BPA believes that the intent is clear, but the fundamental
approach of using the MVCD (table 2) to manage a
vegetation program is still problematic. These values are
Consideration of Comments on Successive Ballot of FAC-003-2
59
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Segment
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Comment
flashover distances and are way too close. This is
acknowledged in a footnote to table 2 but no identification
of allowable buffers/distances between energized phase
conductors at rated temperatures and vegetation is
discussed (this is left up the transmission owners). Clarity is
needed on this topic. Setting a finite distance limit based on
recognized standards, good science and risk avoidance
should be done for the industry. BPA has previously made
this comment during the drafting of the standard. It was not
addressed then, nor has it been addressed now.
Response: The SDT thanks you for your comments. The footnotes were changed to conform with your suggestions.
With respect to comments about the MVCD, R3 does not suggest the MVCD be used as a distance to manage vegetation. The
MVCD was established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line
within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD distances.
In a performance based standard, requirements are focused on “what” needs to be accomplished to achieve desired results
and avoids prescriptive requirements of “how” to achieve that result. TO’s are in the best position to determine the
appropriate management approach suited for their system rather than a “one size fits all” or “fill in the blanks” requirements
that could suppress best practices for vegetation management.
Matthew D
Cripps
Cleco Power
LLC
6
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
Cleco disagrees with the SDT revising the definition for
Right-of-Way (ROW). Right-of-Way is a term that has had a
consistent meaning throughout history. If NERC tries to
redefine the term, it will only add confusion because most
entities will not reference the NERC glossary for a term
which is widely used in the industry. In lieu of "Active
Transmission Line ROW", please use another term such as
Transmission Corridor. No assumptions would be made
when reading in the Standard the the Entity is to maintain
60
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Segment
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Comment
vegetation located within the Transmission Corridor. Since
the term is not commonly used, the NERC glossary would be
referenced.
Also, Cleco disagrees that an encroachment into the MCVD
that does not cause an outage should be considered noncompliant as stated in R1 and R2. The encroachment should
only be reportable similar to misoperations as is in the PRC004 standard.
Response: Thanks for your comments. The existing ROW definition in the glossary was created by and for the FAC-003-1 and
was moved there when that standard was adopted. The definition includes a series of options that give the Transmission
Owner latitude in establishing ROW width. It does not require selecting a single method for its system. The term blowout
standard is not capitalized and is not a defined term. This phrase in the definition allows a Transmission Owner to use its
internal engineering standards or the general engineering standards that were in effect when the line was constructed to
determine the ROW width. The SDT has limited the definition of Right-of-Way to a corridor of land with a defined width to
operate a transmission line. This does not include danger tree rights. The definition of the MVCD is now added to this Standard.
While use of the pre-2007 records is a compliance issue and is not in the purview of the SDT, it is the intent of the language in
the definition that you could use this information.
Regarding your second comment (begins with Also,): the MVCD was established as a beginning of a series of “building blocks”
for a program to ensure reliability of a Transmission line within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD.
Other related requirements of this “Defense in Depth” Standard serve to address any number of scenarios which may arise or
hinder the TO’s ability to always strictly adhere to the management approach(s) established within R3. Thus the other
requirements of this Standard provide the latitude for appropriate actions to remedy the condition without penalty. Further,
trees which have encroached inside the MVCD are evidence of a deficiency in vegetation maintenance.
Nickesha P
Carrol
Consolidated
Edison Co. of
6
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
Reply to Question 5 on Comment Form: The added language
for the annual work plan percentage complete calculation is
61
Voter
Entity
New York
Segment
Vote
Comment
shown in R7 not M7 as stated in the question. In the
Guideline and Technical Basis Section for Requirement R6,
there is a sample calculation shown for the amount of lines
the TO failed to inspect. An example should also be included
for Requirement R7 since there is some confusion regarding
how modifications to the work plan affect the calculation. In
the Lower VSL column for R7, it states that the TO failed to
complete up to 5% of its annual vegetation work plan
(including modifications if any). If a TO operates 100 lines
and submits a justified modification that affects 10 miles of
lines, the total number of units in the final amended plan is
90 miles. When you read the VSL, it is somewhat confusing
since the information in parenthesis says that the
calculation 'includes' the modifications. Should it state
'excludes modifications if any' or the VSLs can simply be rewritten to state that ..The TO failed to complete up to x% of
the final amended plan.'
Response: The SDT thanks you for your comments. The percentage should be based on the plan as modified. The SDT has
changed the language in the standard to reflect this more clearly.
Mark S
Travaglianti
FirstEnergy
Solutions
6
Affirmative
FirstEnergy supports standard FAC-003-2 and would
appreciate consideration of our comments submitted
through the formal comment period.
Response: The SDT thanks you for your comments. Please see our consideration of your comments within the responses to
the formal comments.
Thomas E
Washburn
Florida
Municipal
Power Pool
6
Consideration of Comments on Successive Ballot of FAC-003-2
Negative
The concern is that entities may not be able prove
compliance with the standard. R1 and R2 say that: "Each
Transmission Owner shall manage vegetation to prevent
encroachments ...". If the requirements were interpreted
such that "manage" is the operative word, then, we are OK
because we can provide evidence of managing a program,
62
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Segment
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Comment
such as a vegetation management plan and evidence of
executing that plan (which does not align with the
Measures). However, that 1) would cause the standard to
not be performance based, and 2) it would be duplicative of
the other requirements of the standard.
If the requirements were interpreted with "prevent
encroachment" as the operative phrase (which would be an
incorrect interpretation from the construct of the sentence)
there is no way to provide sufficient evidence that
encroachment was prevented during the audit-period. The
suggested Measures are not sufficient evidence to prove
compliance with that interpretation of the requirement. For
instance, most encroachments do not result in outages;
hence, lack of outages cannot prove that there were no
encroachments, and real time observations are insufficient
because it is a spot-check that does not cover the audit
period.
There are other weaknesses in the standard, such as R4
being un-measurable therefore unenforceable. However, in
the guilty until proven innocent paradigm we live in, FMPA's
primary concern is that industry could be put into a no-win
situation of not being able to prove compliance with the
standard if R1 and R2 are interpreted as "prevent
encroachment", and if R1 and R2 are interpreted as
"manage" then it is not a performance based standard as
advertised.
Performance based focused on preventing vegetation
related outages. For instance: "Each Transmission Owner
Consideration of Comments on Successive Ballot of FAC-003-2
63
Voter
Entity
Segment
Vote
Comment
shall prevent vegetation related outages (except as noted in
Footnote 2) of any of its applicable line(s) ..." Evidence of
outages is practical to gather and provide, evidence of
encroachment is not.
Modify the standard to be similar to the currently
mandatory non-results based standard and focus on the
word "manage". This would essentially mean eliminating R1
and R2 since the rest of the standard focuses on having a
plan and managing to that plan..
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Silvia P.
Mitchell
Florida Power
& Light Co.
6
Affirmative
1. The SDT proposes a revised NERC Glossary definition for
Right-of-Way (ROW). This revised definition will be used in
lieu of the Active Transmission Line ROW. Do you agree? If
answer is no, please explain. Yes
2. In R1 and R2 and their associated VSLs, the SDT added the
phrase “in order of increasing severity” and added the
sentence “The types of encroachments are listed in order of
increasing degrees of severity in non-compliant
performance as it relates to a failure of a TO’s vegetation
maintenance program.” to the Rationale boxes for R1/R2.
Do you agree? If answer is no, please explain. Yes Although
NextEra Energy Inc. (NextEra), including Florida Power &
Light Company, agrees with the changes referenced for R1
Consideration of Comments on Successive Ballot of FAC-003-2
64
Voter
Entity
Segment
Vote
Comment
and R2, NextEra is concerned that the exemptions identified
in footnote 2 for “...arboricultural activities or horticultural
or agricultural activities...,” and similar language in footnote
4, are too broad. For example, this language appears to
include an exemption for a landowner, who, during
arboricultural activities or horticultural or agricultural
activities, causes a vegetation contact with a transmission
line (e.g., cutting or lifting a tree into a transmission line).
This places the Transmission Owner in the difficult position
of a landowner arguing it is exempt from a controllable risk.
Thus, the “...arboricultural activities or horticultural or
agricultural activities...” references should be removed from
footnote 2, and the similar language in footnote 4
3. In response to comments received regarding the term
“investigation” in M1/M2, the SDT substituted
“confirmation...by the Transmission Owner..” in its place,
among other minor edits to these measures. Do you agree?
If answer is no, please explain. Yes
4. In response to comments received that requirement R3 is
unclear with respect to intent, the SDT added “maintenance
strategies”. Do you agree this clarifies the intent? If answer
is no, please offer alternative language. Yes
5. The SDT added clarifying language in M7 to explain how
the annual work plan percentage complete calculation is to
be performed. Is this adequate? If no, please provide
improved examples. Yes
Consideration of Comments on Successive Ballot of FAC-003-2
65
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Segment
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Comment
Response: The SDT thanks you for your comments. The team has made the appropriate modifications to the footnotes as you
suggested.
Thomas
Saitta
Kansas City
Power & Light
Co.
6
Negative
The Standard lacks clarity regarding the facilities that are
subject to Requirement 7. It is important that a Standard be
clear and not introduce ambiguity or confusion. There are
several references throughout the Standard to "for all
applicable lines" and it should be made clear the work plan
is specific to "all applicable lines".
Response: The SDT thanks you for your comments. The phrase, “applicable lines” was added to R7 in support of your
suggestion.
Eric
Ruskamp
Lincoln
Electric
System
6
Affirmative
While supportive of the drafting team’s efforts, LES believes
a change is warranted in Footnote 2 and Footnote 4 to
remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace with the
term “installation of”. As currently drafted, the wording
could potentially be construed to mean that the TO would
or could be constrained or refused permission to prune and
remove any and all vegetation in the ROW in accordance
with the full legal rights of the ROW agreement(s).
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
John T
Sturgeon
Progress
Energy
6
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “installation of.
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
David F.
Lemmons
Xcel Energy,
Inc.
6
Consideration of Comments on Successive Ballot of FAC-003-2
Affirmative
Xcel Energy still believes the requirement in R6 that
mandates an annual inspection is an ineffective approach
and may actually go against the Commission’s
66
Voter
Entity
Segment
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Comment
determination in FERC Order No. 693. The drafting team’s
response to our last round of comments on this issue was
that “...the SDT was directed by Order 693 to set a minimum
inspection criteria”. It is clear in Order 693 that the
Commission is not satisfied with allowing entities to choose
their own inspection cycles, as the standard currently
allows. However, we fail to see where the Commission
mandated a minimum inspection cycle to be uniformly
applied continent-wide. We urge the drafting team to revisit
paragraphs 719 through 721 of Order 693. According to
paragraph 721, the Commission recognizes that unique
intervals by region, “based on local factors”, are reasonable
and appropriate. By use of the plural term “cycles”, FERC
anticipates the resolution may include multiple inspection
cycles. Furthermore, in paragraph 719, FERC acknowledges
that a minimum inspection cycle may not be the only way to
address their concern. In fact, mandating an annual
inspection cycle may actually go against the Commission’s
guidance in paragraph 720. Here is an excerpt: “...the
Commission is dissuaded from requiring the ERO to create a
backstop inspection cycle at this time. Instead, the
Commission agrees that an entity’s vegetation management
program should be tailored to anticipated growth in the
region and take into account other environmental factors.
The goal is to assure that transmission owners conduct
inspections at reasonable intervals.”
As an alternative, we propose a mid-cycle inspection. A midcycle inspection is based on an interval that is justified with
data and technical expertise. A mid-cycle inspection would
still require entities to conduct inspections at a specified
interval, while allowing for differences based upon “physical
Consideration of Comments on Successive Ballot of FAC-003-2
67
Voter
Entity
Segment
Vote
Comment
and geographic factors”. Not only would this approach fully
address the Commissions concerns, but it would take into
account the interests of stakeholders, landowners and ratepayers. We recognize that a mid-cycle inspection interval is
not as easy to audit as an annual requirement, but it is a far
more practical and cost-effective approach that, when
applied based on an entity’s expertise with its own facilities,
ensures reliability.
Response The SDT thanks you for your comments. The SDT recognizes that a number of Transmission Owners in North America
may prefer to set their own inspection intervals. The SDT can also see attractiveness for a mid-cycle inspection concept;
however, this introduces new complexities in planning, documentation and auditing. Because there is substantial industry
support for an annual inspection interval and due to the vastly simpler auditing associated with an annual interval, the SDT
believes that the industry is best served with this approach.
Jacquie
Smith
ReliabilityFirst
Corporation
10
Negative
ReliabilityFirst votes “No” on the proposed FAC-003-2
because ReliabilityFirst believes that the currently effective
FAC-003-1, despite any weaknesses it may have, better
ensures the reliability of the bulk electric system.
First, under the proposed FAC-003-2, Requirements 1 and 2,
the minimum clearances are reduced.
Second, under the proposed structure of FAC-003-2,
Requirements 1 and 2, violations would only occur where an
encroachment of the Minimum Vegetation Clearance
Distance (“MVCD”) is observed in real time or after
vegetation contact, i.e., after actual harm has occurred.
Consequently, the proposed structure appears to convert a
preventative maintenance standard into a standard that is
essentially only violated after it is too late. The current
structure from Version 1 of the standard (i.e., the Clearance
Consideration of Comments on Successive Ballot of FAC-003-2
68
Voter
Entity
Segment
Vote
Comment
1 and 2 requirements) better ensures reliability because
they seek to ensure that registered entities discover
problematic vegetation conditions prior to encroachments
leading to flashover or vegetation contacts. For example,
the current Clearance 1 is the “clearance distances to be
achieved at the time of transmission vegetation
management work.” And the current Clearance 2 is the
“specific radial clearances to be maintained under all rated
electrical operating conditions.” See FAC-003-1, R1.2.1 and
R1.2.2 (emphasis added).
Third, the draft standard appears to inappropriately and
unnecessarily reduce the risk factor assigned to some
failures to manage vegetation. It draws a distinction
between those transmission lines that are elements of IROLs
or Major Western Electricity Coordinating Council (“WECC”)
transfer paths and those that are not. This distinction is
apparently based on the assumption that vegetation
management violations on transmission lines that are not
elements of IROLS or Major WECC transfer paths are less
important. ReliabilityFirst disagrees with this assumption.
Simply put, both are serious issues and the distinction is
inappropriate and unnecessary. The Final Report on the
August 14, 2003 Blackout in the United States and Canada:
Causes and Recommendations, highlights the importance of
all vegetation management work by identifying inadequate
vegetation management as one of the causes of the 2003
Blackout. See Blackout Report, at p. 20.
Finally, ReliabilityFirst disagrees with the proposed Violation
Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”)
Consideration of Comments on Successive Ballot of FAC-003-2
69
Voter
Entity
Segment
Vote
Comment
because they are premised on the same inappropriate and
unnecessary distinction that vegetation management
violations on transmission lines that are not elements of
IROLS or Major WECC transfer paths are less important.
For the foregoing reasons, ReliabilityFirst votes “No” on the
proposed FAC-003-2.
Response: As with a Transmission Owner's determination of its Clearance 1 distances under version 1 of the Standard,
Requirement 3 of the revised Standard begins with the MVCD distances (just as Clearance 1 began with IEEE-516 distances) and
then requires additional consideration for conductor movement, vegetation growth variables, and the utility's maintenance
approach. These are essentially the same considerations required by version 1 of the existing Standard when developing
Clearance 1 distances. Therefore, nothing has been lost in the revised Standard.
The MVCD was established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission
line within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD distances.
The defense-in-depth strategy for reliability standards development recognizes that each requirement in a NERC reliability
standard has a role in preventing system failures, and that these roles are complementary and reinforcing. Reliability standards
should not be viewed as a body of unrelated requirements, but rather should be viewed as part of a portfolio of requirements
designed to achieve an overall defense-in-depth strategy and comport with the quality objectives of a reliability standard. The
draft, when taken in whole, does present a "preventative” maintenance standard.
The Standard has been designed utilizing a "Defense in Depth" strategy which provides for multiple layers of defense against a
MVCD encroachment or an outage. These other layers of defense are identified in requirements R3 through R7. R3 through R7
are the same preventative maintenance requirements as contained in Version 1 of the Standards. Additionally, Measure 3 for
R3 now tests the reasonableness and practicality of a TO’s vegetation management approach long before field work is
implemented; other requirements such as R7 require preventative maintenance work to be completed before encroachments
occur.
The SDT asserts that different VRF’s for IROL and non-IROL lines strengthens the reliability of the standard. Vegetation
Consideration of Comments on Successive Ballot of FAC-003-2
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Voter
Entity
Segment
Vote
Comment
managers that do not know which lines have IROLs or are designated as WECC Transfer Paths may be inappropriately limiting
resources allocated to vegetation management for a line with an IROL or a line designated as a WECC Transfer Path. A
vegetation manager must ensure that the lines with IROLs and lines designated as WECC transfer paths are absolutely clear. By
correctly identifying the risk associated with lines with IROLs line and/or lines designated as WECC Transfer Paths, the standard
helps to assure that appropriate resources are applied.
Consideration of Comments on Successive Ballot of FAC-003-2
71
Non-binding Poll of VRFs and VSLs for FAC-003-2 (February
18-28, 2011) Consideration of Comments Report
Project 2007-07 Vegetation Management — September 30, 2011
Summary Consideration:
Some entities expressed concern regarding the use of the MVCD. The SDT explained that the MVCD was established as a
beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line within its rating and all rated
electrical operating conditions, and that R3 requires that a Transmission Owner to consider the MVCD distances, as well as
variables of conductor movement and the variables associated with vegetation growth, when designing the Transmission Owner’s
overall vegetation management approach. The net result of this “building block” approach is that when entities implement R7,
their efforts will result in vegetation management at clearance distances greater than the MVCD.
Other entities questioned if the intent of the standard is to “manage vegetation” or to “prevent outages. The STD responded that
In Order 693, FERC was very specific that “…FAC-003-1 is designed to minimize transmission outages from vegetation located on
or near transmission rights-of-way by maintaining safe clearances between transmission lines and vegetation” (emphasis
added).
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment
serious consideration in this process. If you feel there has been an error or omission, you can contact the Vice President and
Director of Standards, Herb Schrayshuen, at 404-446-2563 or via email at [email protected]. In addition, there is a
NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedure: http://www.nerc.com/files/RSDP_V6_1_12Mar07.pdf.
Voter
Gregory S
Miller
Entity
Baltimore Gas
& Electric
Company
Segment
1
Vote
Comment
Affirmative
VRFs and VSLs seem reasonable.
Negative
(See comments for 2007-07.)
Response: The SDT thanks you for your comments.
Joseph S.
Stonecipher
Beaches
Energy
Services
1
Response: The SDT responded in the Successive Ballot Consideration of Comments document.
Donald S.
Watkins
Bonneville
Power
Administration
1
Affirmative
In R1 and R2 and their associated VSLs, the SDT added the
phrase “in order of increasing severity” and added the
sentence, “The types of encroachments are listed in order
of increasing degrees of severity in non-compliant
performance as it relates to a failure of a TO’s vegetation
maintenance program.” to the Rationale boxes for R1/R2.
Do you agree? If answer is no, please explain.
BPA prefers the stratified levels of violation severity
presented in the table for R1 and R2. Foot note # 2 on page
8 needs to be clarified with respect to arboricultural
activities or horticultural or agricultural activities.
Foot note # 4 on page 12 needs to be clarified with respect
to arboricultural activities or horticultural or agricultural
activities.
In response to comments received that requirement R3 is
unclear with respect to intent, the SDT added
“maintenance strategies.” Do you agree this clarifies the
intent? If answer is no, please offer alternative language.
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
2
Voter
Entity
Segment
Vote
Comment
The TO procedures / policies and specifications shall
demonstrate the TO’s ability to manage the system at all
rated conditions to maintain reliability. BPA believes that
the intent is clear, but the fundamental approach of using
the MVCD (table 2) to manage a vegetation program is still
problematic. These values are flashover distances and are
way too close. This is acknowledged in a footnote to table 2
but no identification of allowable buffers/distances
between energized phase conductors at rated
temperatures and vegetation is discussed (this is left up the
transmission owners). Clarity is needed on this topic.
Setting a finite distance limit based on recognized
standards, good science and risk avoidance should be done
for the industry. BPA has previously made this comment
during the drafting of the standard. It was not addressed
then, nor has it been addressed now.
Response: The SDT thanks you for your comments. The footnotes were changed to conform with your suggestions.
With respect to comments about the MVCD, R3 does not suggest the MVCD be used as a distance to manage vegetation. The
MVCD was established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line
within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD.
In a performance based standard, requirements are focused on “what” needs to be accomplished to achieve desired results
and avoids prescriptive requirements of “how” to achieve that result. TO’s are in the best position to determine the
appropriate management approach suited for their system, rather than a “one size fits all” or “fill in the blank” requirement
that could suppress best practices for vegetation management.
Randall
McCamish
City of Vero
Beach
1
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
Vero Beach's concern is that entities may not be able prove
compliance with the standard. R1 and R2 say that: "Each
3
Voter
Entity
Segment
Vote
Comment
Transmission Owner shall manage vegetation to prevent
encroachments ...". If the requirements were interpreted
such that "manage" is the operative word, then, we are OK
because we can provide evidence of managing a program,
such as a vegetation management plan and evidence of
executing that plan (which does not align with the
Measures). However, that 1) would cause the standard to
not be performance based, and 2) it would be duplicative of
the other requirements of the standard. If the
requirements were interpreted with "prevent
encroachment" as the operative phrase (which would be an
incorrect interpretation from the construct of the sentence)
there is no way to provide sufficient evidence that
encroachment was prevented during the audit-period. The
suggested Measures are not sufficient evidence to prove
compliance with that interpretation of the requirement. For
instance, most encroachments do not result in outages;
hence, lack of outages cannot prove that there were no
encroachments, and real time observations are insufficient
because it is a spot-check that does not cover the audit
period. There are other weaknesses in the standard, such
as R4 being un-measurable therefore unenforceable.
However, in the guilty until proven innocent paradigm we
live in, FMPA's primary concern is that industry could be
put into a no-win situation of not being able to prove
compliance with the standard if R1 and R2 are interpreted
as "prevent encroachment", and if R1 and R2 are
interpreted as "manage" then it is not a performance based
standard as advertised.
Vero Beach suggests one of two approaches: 1.
Performance based focused on preventing vegetation
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
4
Voter
Entity
Segment
Vote
Comment
related outages. For instance: "Each Transmission Owner
shall prevent vegetation related outages (except as noted
in Footnote 2) of any of its applicable line(s) ..." Evidence of
outages is practical to gather and provide, evidence of
encroachment is not. 2. Modify the standard to be similar
to the currently mandatory non-results based standard and
focus on the word "manage". This would essentially mean
eliminating R1 and R2 since the rest of the standard focuses
on having a plan and managing to that plan..
Response: The SDT thanks you for your comments. In Order 693, FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Christopher
L de
Graffenried
Consolidated
Edison Co. of
New York
1
Affirmative
The VSLs in R6 and R7 should be consistent with each
other: R6 says '...TO failed to inspect 5% or less.....' and R7
says '...TO failed to complete up to 5%....' They both should
use the same verbiage in each VSL whether it is 'x% or less'
or 'up to and including x%.'
Response: The SDT thanks you for your comments. The SDT has changed the verbiage in the VSLs in R6 and R7 such that it
addresses you suggestion.
Michael
Gammon
Kansas City
Power & Light
Co.
1
Negative
The VSL for Requirement 7 should be clear and specifically
state this specifically addresses only "all applicable lines".
Response: The SDT thanks you for your comments. The team has added the phrase, “applicable lines” as proposed to all the
VSLs for R7.
Stan T.
Keys Energy
1
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
Concern is that entities may not be able prove compliance
with the standard. R1 and R2 say that: "Each Transmission
5
Voter
Rzad
Entity
Segment
Services
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Vote
Comment
Owner shall manage vegetation to prevent encroachments
...". If the requirements were interpreted such that
"manage" is the operative word, then, we are OK because
we can provide evidence of managing a program, such as a
vegetation management plan and evidence of executing
that plan (which does not align with the Measures).
However, that 1) would cause the standard to not be
performance based, and 2) it would be duplicative of the
other requirements of the standard. If the requirements
were interpreted with "prevent encroachment" as the
operative phrase (which would be an incorrect
interpretation from the construct of the sentence) there is
no way to provide sufficient evidence that encroachment
was prevented during the audit-period. The suggested
Measures are not sufficient evidence to prove compliance
with that interpretation of the requirement. For instance,
most encroachments do not result in outages; hence, lack
of outages cannot prove that there were no
encroachments, and real time observations are insufficient
because it is a spot-check that does not cover the audit
period. There are other weaknesses in the standard, such
as R4 being un-measurable therefore unenforceable.
However, in the guilty until proven innocent paradigm we
live in, FMPA's primary concern is that industry could be
put into a no-win situation of not being able to prove
compliance with the standard if R1 and R2 are interpreted
as "prevent encroachment", and if R1 and R2 are
interpreted as "manage" then it is not a performance based
standard as advertised. one of two approaches are
suggested: Performance based focused on preventing
vegetation related outages. For instance: "Each
Transmission Owner shall prevent vegetation related
6
Voter
Entity
Segment
Vote
Comment
outages (except as noted in Footnote 2) of any of its
applicable line(s) ..." Evidence of outages is practical to
gather and provide, evidence of encroachment is not.
Modify the standard to be similar to the currently
mandatory non-results based standard and focus on the
word "manage". This would essentially mean eliminating R1
and R2 since the rest of the standard focuses on having a
plan and managing to that plan..
Response: The SDT thanks you for your comments. In Order 693 FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Walt Gill
Lake Worth
Utilities
1
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
concern is that entities may not be able prove compliance
with the standard. R1 and R2 say that: "Each Transmission
Owner shall manage vegetation to prevent encroachments
...". If the requirements were interpreted such that
"manage" is the operative word, then, we are OK because
we can provide evidence of managing a program, such as a
vegetation management plan and evidence of executing
that plan (which does not align with the Measures).
However, that 1) would cause the standard to not be
performance based, and 2) it would be duplicative of the
other requirements of the standard. If the requirements
were interpreted with "prevent encroachment" as the
operative phrase (which would be an incorrect
interpretation from the construct of the sentence) there is
no way to provide sufficient evidence that encroachment
was prevented during the audit-period. The suggested
Measures are not sufficient evidence to prove compliance
7
Voter
Entity
Segment
Vote
Comment
with that interpretation of the requirement. For instance,
most encroachments do not result in outages; hence, lack
of outages cannot prove that there were no
encroachments, and real time observations are insufficient
because it is a spot-check that does not cover the audit
period. There are other weaknesses in the standard, such
as R4 being un-measurable therefore unenforceable.
However, in the guilty until proven innocent paradigm we
live in, FMPA's primary concern is that industry could be
put into a no-win situation of not being able to prove
compliance with the standard if R1 and R2 are interpreted
as "prevent encroachment", and if R1 and R2 are
interpreted as "manage" then it is not a performance based
standard as advertised. suggest one of two approaches: 1.
Performance based focused on preventing vegetation
related outages. For instance: "Each Transmission Owner
shall prevent vegetation related outages (except as noted
in Footnote 2) of any of its applicable line(s) ..." Evidence of
outages is practical to gather and provide, evidence of
encroachment is not. 2. Modify the standard to be similar
to the currently mandatory non-results based standard and
focus on the word "manage". This would essentially mean
eliminating R1 and R2 since the rest of the standard focuses
on having a plan and managing to that plan..
Response: The SDT thanks you for your comments. In Order 693 FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
8
Voter
Entity
Marvin E
VanBebber
Oklahoma Gas
and Electric
Co.
Segment
1
Vote
Negative
Comment
R3 VSL leaves a lot open to interpetation in the analysis
area. This is one where the auditor could be heavy handed
if he desired.
Response: The SDT thanks you for your comments. The Requirement 3 VSL does in fact give TO significant latitude with respect
to maintaining appropriate clearances. As noted in the Rationale, “The documentation provides a basis for evaluating the
competency of the Transmission Owner’s vegetation program. There may be many acceptable approaches to maintain
clearances.” In a performance based standard, requirements (and associated VSLs) are focused on “what” needs to be
accomplished to achieve desired results and avoids prescriptive requirements of “how” to achieve that result. TO’s are in the
best position to determine the appropriate management approach suited for their system rather than a “one-size-fits-all”
requirement that could suppress best practices for vegetation management. With this in mind, if the TO is audited, and it has a
well crafted vegetation management program and has properly documented procedures and results, it should be in a good
position.
Keith V
Carman
Tri-State G & T
Association,
Inc.
1
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “ installation of”.
Response: The SDT thanks you for your comments. The footnotes have been changed as proposed.
Mark B
Thompson
Alberta
Electric
System
Operator
2
Abstain
VRFs and VSLs are set by Provincial authorities in Alberta.
Response: The SDT thanks you for your comments.
David A.
Lapinski
Consumers
Energy
3
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
Comments on FAC-003-2 February 25, 2011 Consumers
Energy submits the following comments on FAC-003-2: In
general we are please with FAC-003-2 and the many
clarifications that the STD has made in this version of the
standard. However, we do have one major disagreement
with the STD and cannot support this standard as drafted.
9
Voter
Entity
Segment
Vote
Comment
We disagree with the use of the Minimum Vegetation
Clearance Distance (MVCD) developed by the drafting team
for Requirements R1 and R2. These distances are not the
design distances used for designing and constructing
transmission facilities as stated in the document for
minimum distances between conductors and grounded
objects. The proposed Table 2 provides a distance of 3.12
feet as the acceptable distance for an alternate current
345kV line at sea level. This distance is considerably less
than the distance used for line design to separate the
grounded tower structure from the energized conductor. If
the distance in Table 2 is acceptable to prevent energized
portions of a transmission line from grounding to a tree
why then is this distance not the design criteria used for
tower design to prevent flashover from conductor to
tower? The STD needs to explain why a ground tree should
have a different standard that a grounded steel tower or
wood pole structure. The STD erroneously viewed the
possibility of transient over voltage as only occurring during
re-energizing and not from natural events such as a
lightning strike that can occur and does occur to energized
operating lines. Secondly, the proposed distances in Table 2
are considerably less than the distances specified in OSHA
requirements for air gap clearance required by tree
workers to safely remove trees or limbs from conductors
energized at the voltages specified. A transmission
owner/operator could let a tree grow to within 3.5 feet of a
345 kV line and not be in violation of this proposed
standard. To remove the tree, the line would have to be deenergized, tagged, tested de-energized, and grounded.
Working clearance would have to be established by the
operating entity and then the tree crew could remove the
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
10
Voter
Entity
Segment
Vote
Comment
tree. The net result is the loss of the capacity of the line
because an outage was forced on the line in order to
remove the tree that did not trigger a violation of FAC-0032. This situation, in our opinion, is a violation of the intent
of the standard, which is to ensure the continued operation
of the line. Therefore, the minimum distance any tree
should be able to approach a conductor is more than the
minimum requirement for air gap distance between the
tree and conductor as required by OSHA worker standards.
The STD did not like referring to another standard to
provide the distance requirements for R1 and R2. This can
be alleviated by putting in a table with the IEEE 516
distances but not reference it as the IEEE 516 standard. The
distances provided in the current draft do not adequately
provide or ensure the continued safe operation of the
transmission facilities in the United States and the
reasoning for the distances provided is unfounded and not
based on current design practices.
Response: The SDT thanks you for your comments. You are correct that these distances do not represent complete design
specifications for towers, nor define and describe safe worker approach distances. These practices are correctly specified in the
other standards you referenced. The SDT feels the standard is clear in that regard. The footnote associated with the Table 2
distances clearly states that these are only distances to prevent flashover under appropriate conditions. The SDT would also
like to point out that the transient overvoltage factors used to derive these distances are the maximums normally seen with a
transmission line in steady state service. Thus, a tower design would have to account for the larger overvoltage factors that are
possible while taking lines out of service.
As has been stated before, these distances were derived using a known set of line design equations and only represent
distances that will prevent spark-over from the transmission line to a grounded object. These are not distances to be managed
to – they have been established as a beginning of a series of “building blocks” for a program to ensure reliability of a
Transmission line within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner’ consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
11
Voter
Entity
Segment
Vote
Comment
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD.
These distances are smaller than safety standard distances that have many other factors involved in the determination, such as
inadvertent human movement and larger safety factors. In regard to the over-voltages caused by lightning, even the maximum
overvoltage factors contained in the IEEE-516 tables do not account for these.
Russell A
Noble
Cowlitz
County PUD
3
Negative
Referring back to Cowlitz’ negative vote made on the 7/919/2010 ballot, Cowlitz tried to convey the problem that
the statement in R4 “without intentional time delay” will
require subjective judgment on the part of the auditor. In
other words, maintaining equal auditing standard
throughout the interconnection will be impossible with this
verbiage in a requirement. Cowlitz agrees with the SDT that
establishing an equitable time frame is very difficult (it may
be impossible!); however leaving it to the judgment of the
auditor to determine whether an intentional delay was
made is most disagreeable. Cowlitz respectfully points out
that the SDT did not adequately address the subjective
nature the auditor is forced into with this requirement. If
establishing “[t]he time required by the to report an issue is
subject to many variables...” and “[f]or this reason it is
difficult to establish a time period which would fairly apply
to all TO’s,” how does leaving this to the auditor to decide
going to make it any better?
Response: The SDT thanks you for your comments. The SDT believes that it was not prudent to suggest a quantitative time
element for notification in R4. The technical reference offers examples of acceptable unintentional delays for your review. The
SDT notes that this language is already embodied in at least one other FERC-approved, in-force Standard.
Charles
Locke
Kansas City
Power & Light
Co.
3
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
The VSL for Requirement 7 should be clear and specifically
state this specifically addresses only "all applicable lines".
12
Voter
Entity
Segment
Vote
Comment
Response: The SDT thanks you for your comments. The team has added the phrase, “applicable lines” as proposed to all the
VSLs for R7.
Mace
Hunter
Lakeland
Electric
3
Affirmative
R1. Each Transmission Owner shall manage vegetation to
prevent encroachments of the types shown below, --------------- and all Rated Electrical Operating Conditions.2 1. An
encroachment into the MVCD as shown in FAC-003-Table 2,
observed in Real-time, absent a Sustained Outage, that is
not corrected within 5 working days of discovery, Make the
same change to R2 Type 1 encroachment and reflect the
changes in Table 1. Rational: This condition would enable a
entity to discover an encroachment and clear it without
having to self report a possible violation as long as the
conditions was corrected within 5 working days. The
change should encourage extra inspections for problem
areas more often than annually as required in R6. There
should be no negative consequences for diligent inspection
of lines as long as the problem is clear with a defined time
such as 5 or 10 working days.
Response: The SDT thanks you for your comment. As a general rule, a revised standards should not be less stringent than the
existing standard it replaces. In the existing standard, a violation occurs when the encroachment occurs. A ‘find and fix’ of five
days would be viewed as a lowering the level of performance required by the current standard.
Rick Syring
Cowlitz
County PUD
4
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
Referring back to Cowlitz’ negative vote made on the 7/919/2010 ballot, Cowlitz tried to convey the problem that
the statement in R4 “without intentional time delay” will
require subjective judgment on the part of the auditor. In
other words, maintaining equal auditing standard
throughout the interconnection will be impossible with this
verbiage in a requirement. Cowlitz agrees with the SDT that
establishing an equitable time frame is very difficult (it may
be impossible!); however leaving it to the judgment of the
13
Voter
Entity
Segment
Vote
Comment
auditor to determine whether an intentional delay was
made is most disagreeable. Cowlitz respectfully points out
that the SDT did not adequately address the subjective
nature the auditor is forced into with this requirement. If
“[t]he time required by the entity to report an issue is
subject to many variables...” and “[f]or this reason it is
difficult to establish a time period which would fairly apply
to all TO’s,” how does leaving this to the auditor to decide
going to make it any better? You will be forcing the audited
entity to "prove the negative."
Response: The SDT thanks you for your comments. The SDT believes that it was not prudent to suggest a quantitative time
element for notification in R4. The technical reference offers examples of acceptable unintentional delays for your review. The
SDT notes that this language is already embodied in at least one other FERC-approved, in-force Standard.
Frank
Gaffney
Florida
Municipal
Power Agency
4
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
R1 and R2 requirement reads: "Each Transmission Owner
shall manage to prevent encroachment ....". The results of
manage would be invoices of tree trimming actually
performed, documentation of a vegetation management
program that would be managed to, etc. However, the
Measures proposed are all actual outages which are neither
evidence of management nor evidence of encroachment
since there can be encroachment without an outage, and in
fact, many if not most encroachments do not result in
outages. Hence, the Measures are inconsistent with the
requirements. Further, there is ambiguity of the action
required in requirements R1 and R2 - e.g., do entities need
evidence that they: 1) "manage", or 2) "prevent
encroachment"; or 3) as implied by the Measures, prevent
vegetation related outages?. In other words, what needs to
be proven through evidence? Certainly the third, prevent
vegetation related outages, is not in the Requirement; yet,
that us what is proposed for the Measures, highlighting the
14
Voter
Entity
Segment
Vote
Comment
inconsistency between Requirements and Measures. But,
how would the ambiguity between "manage" and "prevent
encroachment" be resolved? One auditor could interpret
that the requirement is to "manage" and accept a
vegetation management program and plan and proof that
the plan was executed as appropriate evidence. Another
auditor could interpret that "prevent" is the key word and
look for evidence proving that there was never a vegetation
encroachment. How would evidence be produced to
provide the auditor that vegetation never encroached?
Would video cameras and other surveillance measures
need to operate 24 hours a day? Would we cause an entity
to survey the lines periodically? One can easily see that
"prevent encroachment" is inappropriate here since it is
infeasible to create evidence of compliance. FMPA suggests
one of two approaches: Eliminate the word manage, but do
not focus on encroachment and instead focus on outages.
For instance: "Each Transmission Owner shall prevent
vegetation related outages (except as noted in Footnote 2)
of any of its applicable line(s) ..." Evidence of outages is
practical to gather and provide, evidence of encroachment
is not. Focus on the word "manage", similar to the existing
FAC-003 standard, and move R3 to a new R1 to develop a
management plan, and then the existing R1 and R2 become
R2 an R3 and require execution of that plan in the words of
R7, which would in turn enables elimination of R7.
Response: The SDT thanks you for your comments. In Order 693 FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
15
Voter
Entity
Segment
Vote
Comment
Affirmative
For the Requirement R1 and R2 VSLs, we suggest that the
proposed Moderate (fall-ins) and High (blowing together)
VSL be interchanged. We believe that fall-ins are more
severe encroachments than blowing together and the
categories listed in the compliance section support this
point. Category 1 (grow-ins) is most severe, followed by
Category 2 & 3 (fall-ins) and Category 4 (blowing together.
If the team elects to not make the suggested VSL changes
then a change in the category listing within the compliance
section is warranted. Either way they should be consistent.
inspections in which clearances are evaluated.
Douglas
Hohlbaugh
Ohio Edison
Company
4
Response: The SDT believes that there is consensus that “blowing-together” events are more indicative of a program failure
than are “fall-in” events. Further, the risk to the transmission system from blowing-together events is greater than for fall-ins;
partly because blowing-together events are more likely to repeat themselves, whereas fall-ins generally end on the spot. The
SDT agrees with you that the ordering of the categories seems to convey a different message; however, re-sequencing the
categories in order of severity would have led to a clash with the existing categories in Version 1 and thus would have provoked
widespread confusion.
Francis J.
Halpin
Bonneville
Power
Administration
5
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Affirmative
In R1 and R2 and their associated VSLs, the SDT added the
phrase “in order of increasing severity” and added the
sentence, “The types of encroachments are listed in order
of increasing degrees of severity in non-compliant
performance as it relates to a failure of a TO’s vegetation
maintenance program.” to the Rationale boxes for R1/R2.
Do you agree? If answer is no, please explain.
BPA prefers the stratified levels of violation severity
presented in the table for R1 and R2. Foot note # 2 on page
8 needs to be clarified with respect to arboricultural
activities or horticultural or agricultural activities.
16
Voter
Entity
Segment
Vote
Comment
Foot note # 4 on page 12 needs to be clarified with respect
to arboricultural activities or horticultural or agricultural
activities.
In response to comments received that requirement R3 is
unclear with respect to intent, the SDT added
“maintenance strategies.” Do you agree this clarifies the
intent? If answer is no, please offer alternative language.
The TO procedures / policies and specifications shall
demonstrate the TO’s ability to manage the system at all
rated conditions to maintain reliability. BPA believes that
the intent is clear, but the fundamental approach of using
the MVCD (table 2) to manage a vegetation program is still
problematic. These values are flashover distances and are
way too close. This is acknowledged in a footnote to table 2
but no identification of allowable buffers/distances
between energized phase conductors at rated
temperatures and vegetation is discussed (this is left up the
transmission owners). Clarity is needed on this topic.
Setting a finite distance limit based on recognized
standards, good science and risk avoidance should be done
for the industry. BPA has previously made this comment
during the drafting of the standard. It was not addressed
then, nor has it been addressed now.
Response: The SDT thanks you for your comments. The footnotes were changed to conform with your suggestions.
With respect to comments about the MVCD, R3 does not suggest the MVCD be used as a distance to manage vegetation. The
MVCD was established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line
within its rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner consider the MVCD distances, as well as variables of conductor movement and
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
17
Voter
Entity
Segment
Vote
Comment
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD distances.
In a performance based standard, requirements are focused on “what” needs to be accomplished to achieve desired results
and avoids prescriptive requirements of “how” to achieve that result. TO’s are in the best position to determine the
appropriate management approach suited for their system rather than a “one size fits all” requirements that could suppress
best practices for vegetation management.
James B
Lewis
Consumers
Energy
5
Negative
See comments on the Standard.
Response: The SDT thanks you for your comments that were made during the formal comment period for the Standard; the
SDT’s responses to those comments are available there.
Bob Essex
Cowlitz
County PUD
5
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
Referring back to Cowlitz’ negative vote made on the 7/919/2010 ballot, Cowlitz tried to convey the problem that
the statement in R4 “without intentional time delay” will
require subjective judgment on the part of the auditor. In
other words, maintaining equal auditing standard
throughout the interconnection will be impossible with this
verbiage in a requirement. Cowlitz agrees with the SDT that
establishing an equitable time frame is very difficult (it may
be impossible!); however leaving it to the judgment of the
auditor to determine whether an intentional delay was
made is most disagreeable. Cowlitz respectfully points out
that the SDT did not adequately address the subjective
nature the auditor is forced into with this requirement. If
establishing “[t]he time required by the to report an issue is
subject to many variables...” and “[f]or this reason it is
difficult to establish a time period which would fairly apply
to all TO’s,” how does leaving this to the auditor to decide
going to make it any better?
18
Voter
Entity
Segment
Vote
Comment
Response: The SDT thanks you for your comments. The SDT believes that it was not prudent to suggest a quantitative time
element for notification in R4. The technical reference offers examples of acceptable unintentional delays for your review. The
SDT notes that this language is already embodied in at least one other FERC-approved, in-force Standard.
David
Schumann
Florida
Municipal
Power Agency
5
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
R1 and R2 requirement reads: "Each Transmission Owner
shall manage to prevent encroachment ....". The results of
manage would be invoices of tree trimming actually
performed, documentation of a vegetation management
program that would be managed to, etc. However, the
Measures proposed are all actual outages which are neither
evidence of management nor evidence of encroachment
since there can be encroachment without an outage, and in
fact, many if not most encroachments do not result in
outages. Hence, the Measures are inconsistent with the
requirements. Further, there is ambiguity of the action
required in requirements R1 and R2 - e.g., do entities need
evidence that they: 1) "manage", or 2) "prevent
encroachment"; or 3) as implied by the Measures, prevent
vegetation related outages?. In other words, what needs to
be proven through evidence? Certainly the third, prevent
vegetation related outages, is not in the Requirement; yet,
that us what is proposed for the Measures, highlighting the
inconsistency between Requirements and Measures. But,
how would the ambiguity between "manage" and "prevent
encroachment" be resolved? One auditor could interpret
that the requirement is to "manage" and accept a
vegetation management program and plan and proof that
the plan was executed as appropriate evidence. Another
auditor could interpret that "prevent" is the key word and
look for evidence proving that there was never a vegetation
encroachment. How would evidence be produced to
provide the auditor that vegetation never encroached?
19
Voter
Entity
Segment
Vote
Comment
Would video cameras and other surveillance measures
need to operate 24 hours a day? Would we cause an entity
to survey the lines periodically? One can easily see that
"prevent encroachment" is inappropriate here since it is
infeasible to create evidence of compliance. FMPA suggests
one of two approaches: Eliminate the word manage, but do
not focus on encroachment and instead focus on outages.
For instance: "Each Transmission Owner shall prevent
vegetation related outages (except as noted in Footnote 2)
of any of its applicable line(s) ..." Evidence of outages is
practical to gather and provide, evidence of encroachment
is not. Focus on the word "manage", similar to the existing
FAC-003 standard, and move R3 to a new R1 to develop a
management plan, and then the existing R1 and R2 become
R2 an R3 and require execution of that plan in the words of
R7, which would in turn enables elimination of R7.
Response: The SDT thanks you for your comments. In Order 693 FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Brenda S.
Anderson
Bonneville
Power
Administration
6
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Affirmative
BPA Comments with Yes Vote: In R1 and R2 and their
associated VSLs, the SDT added the phrase “in order of
increasing severity” and added the sentence, “The types of
encroachments are listed in order of increasing degrees of
severity in non-compliant performance as it relates to a
failure of a TO’s vegetation maintenance program.” to the
Rationale boxes for R1/R2. Do you agree? If answer is no,
please explain.
BPA prefers the stratified levels of violation severity
20
Voter
Entity
Segment
Vote
Comment
presented in the table for R1 and R2.
Foot note # 2 on page 8 needs to be clarified with respect
to arboricultural activities or horticultural or agricultural
activities. Foot note # 4 on page 12 needs to be clarified
with respect to arboricultural activities or horticultural or
agricultural activities.
In response to comments received that requirement R3 is
unclear with respect to intent, the SDT added
“maintenance strategies.” Do you agree this clarifies the
intent? If answer is no, please offer alternative language.
The TO procedures / policies and specifications shall
demonstrate the TO’s ability to manage the system at all
rated conditions to maintain reliability. BPA believes that
the intent is clear, but the fundamental approach of using
the MVCD (table 2) to manage a vegetation program is still
problematic. These values are flashover distances and are
way too close. This is acknowledged in a footnote to table 2
but no identification of allowable buffers/distances
between energized phase conductors at rated
temperatures and vegetation is discussed (this is left up the
transmission owners). Clarity is needed on this topic.
Setting a finite distance limit based on recognized
standards, good science and risk avoidance should be done
for the industry. BPA has previously made this comment
during the drafting of the standard. It was not addressed
then, nor has it been addressed now.
Response: The SDT thanks you for your comments. The footnotes were changed to conform with your suggestions. With
respect to comments about the MVCD, R3 does not suggest the MVCD be used as a distance to manage vegetation. The MVCD
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
21
Voter
Entity
Segment
Vote
Comment
was established as a beginning of a series of “building blocks” for a program to ensure reliability of a Transmission line within its
rating and all rated electrical operating conditions.
R3 requires that a Transmission Owner’ consider the MVCD distances, as well as variables of conductor movement and
vegetation growth, when designing the Transmission Owner’s overall vegetation management approach. The net result of this
“building block” approach is that when entities implement R7, their efforts will result in vegetation management at clearance
distances greater than the MVCD distances.
In a performance based standard, requirements are focused on “what” needs to be accomplished to achieve desired results
and avoids prescriptive requirements of “how” to achieve that result. TO’s are in the best position to determine the
appropriate management approach suited for their system rather than a “one size fits all” requirement that could suppress
best practices for vegetation management.
Nickesha P
Carrol
Consolidated
Edison Co. of
New York
6
Affirmative
The VSLs in R6 and R7 should be consistent with each
other: R6 says '...TO failed to inspect 5% or less.....' and R7
says '...TO failed to complete up to 5%....' They both should
use the same verbiage in each VSL whether it is 'x% or less'
or 'up to and including x%.'
Response: The SDT thanks you for your comments. The SDT has changed the verbiage in the VSLs in R6 and R7 such that it
addresses you suggestion.
Mark S
Travaglianti
FirstEnergy
Solutions
6
Affirmative
FirstEnergy supports standard FAC-003-2 and would
appreciate consideration of our comments submitted
through the formal comment period.
Response: The SDT thanks you for your comments and has reviewed and responded to your comments made during the formal
comment period.
Thomas E
Washburn
Florida
Municipal
Power Pool
6
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
Negative
The concern is that entities may not be able prove
compliance with the standard. R1 and R2 say that: "Each
Transmission Owner shall manage vegetation to prevent
encroachments ...". If the requirements were interpreted
such that "manage" is the operative word, then, we are OK
because we can provide evidence of managing a program,
such as a vegetation management plan and evidence of
22
Voter
Entity
Segment
Vote
Comment
executing that plan (which does not align with the
Measures). However, that 1) would cause the standard to
not be performance based, and 2) it would be duplicative of
the other requirements of the standard. If the
requirements were interpreted with "prevent
encroachment" as the operative phrase (which would be an
incorrect interpretation from the construct of the sentence)
there is no way to provide sufficient evidence that
encroachment was prevented during the audit-period. The
suggested Measures are not sufficient evidence to prove
compliance with that interpretation of the requirement. For
instance, most encroachments do not result in outages;
hence, lack of outages cannot prove that there were no
encroachments, and real time observations are insufficient
because it is a spot-check that does not cover the audit
period. There are other weaknesses in the standard, such
as R4 being un-measurable therefore unenforceable.
However, in the guilty until proven innocent paradigm we
live in, FMPA's primary concern is that industry could be
put into a no-win situation of not being able to prove
compliance with the standard if R1 and R2 are interpreted
as "prevent encroachment", and if R1 and R2 are
interpreted as "manage" then it is not a performance based
standard as advertised. Performance based focused on
preventing vegetation related outages. For instance: "Each
Transmission Owner shall prevent vegetation related
outages (except as noted in Footnote 2) of any of its
applicable line(s) ..." Evidence of outages is practical to
gather and provide, evidence of encroachment is not.
Modify the standard to be similar to the currently
mandatory non-results based standard and focus on the
word "manage". This would essentially mean eliminating R1
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
23
Voter
Entity
Segment
Vote
Comment
and R2 since the rest of the standard focuses on having a
plan and managing to that plan..
Response: The SDT thanks you for your comments. In Order 693 FERC was very specific that “…FAC-003-1 is designed to
minimize transmission outages from vegetation located on or near transmission rights-of-way by maintaining safe clearances
between transmission lines and vegetation” (emphasis added). The drafting team followed that concept and used R1 and R2
to move the clearance from a documentation requirement to a performance requirement. Item 1 in the requirements defines
how an encroachment without an outage would be documented. Each Transmission Owner is also required to conduct
inspections in which clearances are evaluated.
Thomas
Saitta
Kansas City
Power & Light
Co.
6
Negative
The VSL for Requirement 7 should be clear and specifically
state this specifically addresses only "all applicable lines".
Response: The SDT thanks you for your comments. The team has added the phrase, “applicable lines” as proposed to all the
VSLs for R7.
James
Eckelkamp
Progress
Energy
6
Affirmative
There needs to be a change in the footnote 2 and footnote
4 to remove the exemption for “arboricultural activities or
horticultural or agricultural activities” and replace it with
the term “installation of."
Response: The SDT thanks you for your comments. The changes to the footnotes have been made as proposed.
Guy V. Zito
Northeast
Power
Coordinating
Council, Inc.
10
Affirmative
The use of the term “encroachment”, and the lack of clarity
in defining clearances is an issue that should be addressed
by the Drafting Team.
Response: The SDT thanks you for your comments. With regard to the use of “encroachment” and the clarity in defining
clearances as it relates to the VRFs and VSLs, the SDT has taken what was a “gray” area in Version 1 and added more clarity
with regard to compliance. In Version 1, it is not actually clear whether experiencing an encroachment or experiencing outage
is a violation of the standard. The SDT recognized this concern and has addressed this via the proposed VSLs for R1 and R2.
These proposed VSLs are designed such to correlate to the severity level of failure of the Transmission Owner’s vegetation
management program.
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
24
Voter
Entity
Segment
Vote
Comment
If you refer to the VSLs for R1 and R2, only the “Lower” VSLs apply to an encroachment, and that has been defined as “an
encroachment into the MVCD observed in Real-time, absent a Sustained Outage.” The “MVCD” clearance distance is clearly
defined in Table 2 of the Standard. After the Lower VSL level for these requirements, the Moderate to Severe VSLs are
correlated more directly to the severity of failure of the Transmission Owner’s vegetation management program associated
with a Sustained Outage. The SDT makes this recommendation of VSLs based on this being an improvement for compliance
clarity over version 1 of the standard.
Anthony E
Jablonski
ReliabilityFirst
Corporation
10
Negative
ReliabilityFirst votes negative and has the following
comments regarding the VRFs and VSLs:
1. VRF for R1 and R2 a. The Final Report on the August
14th, 2003 Blackout in the United States and Canada:
Causes and Recommendations Blackout Report, highlights
the importance of all vegetation management work by
identifying inadequate vegetation management as one of
the causes of the 2003 Blackout. Based on the Blackout
Report there should be no distinction between
encroachments of applicable line(s) identified as an
element of an Interconnection Reliability Operating Limit
(IROL) or Major Western Electricity Coordinating Council
(WECC) transfer path(s) and encroachments of applicable
line(s) not identified as an element of an Interconnection
Reliability Operating Limit (IROL) or Major Western
Electricity Coordinating Council (WECC) transfer path(s).
Therefore, ReliabilityFirst recommends that VRFs should be
the same for R1 and R2.
2. VSL for R3 a. Since this requirement has sub-parts
associated with it, the associated sub-part number should
be referenced in the VSL itself.
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
25
Voter
Entity
Segment
Vote
Comment
3. VSL for R4 a. The words in the VLS do not match the
language in the requirement. The words “vegetation
threat” is not mentioned in Requirement R4. Based on the
FERC Guideline #3 “Violation Severity Level Assignment
Should Be Consistent with the Corresponding Requirement”
4. VSL for R6 a. The following qualifier should be added to
the end of each of the four VSLs, “...at least once per
calendar year and with no more than 18 months between
inspections on the same ROW” to be consistent with the
corresponding requirement and in accordance with the
FERC Guideline #3.
5. VSL for R7 a. There is no associated VSL dealing with the
second part of the requirement which references that “...
the Modifications to the work plan... must be
documented.” Where does an entity fall if they have
complete 100% of its annual vegetation work plan, but
failed to document any modifications to the work plan?
This aspect of the requirement should be addressed in the
corresponding VSLs.
Response: The SDT thanks you for your comments.
1) In Order 693 FERC was very specific that “…FAC-003-1 is designed to minimize transmission outages from vegetation located
on or near transmission rights-of-way by maintaining safe clearances between transmission lines and vegetation” (emphasis
added). Following that concept, the SDT used R1 and R2 to move the clearance from a documentation requirement to a
performance requirement. .
R1 and R2 are dealing with the differentiation between lines that fall into an IROL or WECC Transfer Path definition and those
lines that do not. The SDT asserts that different VRF’s for IROL and non-IROL lines strengthens the reliability of the standard.
Vegetation managers that do not know which lines are IROL or WECC Transfer Paths may be inappropriately limiting resources
allocated to vegetation management for an IROL line or a WECC Transfer Path. A vegetation manager must ensure that the
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
26
Voter
Entity
Segment
Vote
Comment
IROL lines and WECC transfer paths are absolutely clear. By correctly identifying the risk associated with an IROL line and/or a
WECC Transfer Path, the standard helps to assure that appropriate resources are applied.
2) The sub-parts referred to are part of the RBS building block approach to document how a TO prevents encroachment of
vegetation into the MVCD. The sub parts are not separate elements but make up the processes, strategies, procedures or
specifications to prevent encroachment in to the MVCD.
3) The SDT believes the correlation between R4 and the VSL is appropriate.
4) The SDT believes the correlation between R6 and the VSL is appropriate.
5) The wording in the VSL for R7 has been modified to address modifications to the annual work plan.
February 18-28, 2011 Non-binding Poll of VRFs and VSLs for FAC-003-2
27
Consideration of Comments on Draft 5 of
FAC-003-2
Project 2007-07 Vegetation Management — September 30, 2011
Background
The Transmission Vegetation Management Drafting Team thanks all commenters who submitted
comments on the 5th Draft of FAC-003-2 Transmission Vegetation Management standards. These
standards were posted for a 30-day public comment period from January 27, 2011 through February
28, 2011. The stakeholders were asked to provide feedback on the standards through a special
Electronic Comment Form. There were 41 sets of comments, including comments from more than
106 different people from approximately 63 companies representing 9 of the 10 Industry Segments
as shown in the table on the following pages.
Summary of Changes
In order to be consistent with the latest version of NERC’s Results Based Standards template, the
heading “Objective” was replaced with “Purpose,” and the numbering, headings, and sections were
reformatted as necessary.
One repeated concern was whether or not “danger trees” rights outside the Right-of-Way (ROW)
should be an extension of the ROW. The SDT has limited the definition of Right-of-Way to a corridor
of land with a defined width to operate a transmission line, which does not include danger tree
rights.
Another repeated concern was reference to the term “blowout standard” and commenters were
asking for more clarification and/or a specific definition of that term. To this line of comments the
SDT responded, “the definition includes a series of options that give the Transmission Owner latitude
in establishing ROW width. It does not require selecting a single method for its system. The term
blowout standard is not capitalized and is not a defined term, and is intended to represent whatever
conductor “blow out” (as opposed to vegetation “blow in”) design criteria were used when the line
was constructed. This phrase in the definition allows a Transmission Owner to use its internal
engineering standards or the general engineering standards that were in effect when the line was
constructed to determine the ROW width.”
A request was made to include the definition of MVCD within the definition section of the standard.
The SDT agreed with the commenter’s request and used the appropriate portion of the existing
language in the rationale text box associated with R1 for the MVCD definition. The SDT understands
that this term will be added to the NERC glossary coincident with this standard becoming effective.
This is not a substantive change to the standard, it is merely procedural.
The SDT made minor changes to the footnotes in response to several requests.
There was some concern expressed regarding the relationships between the VSLs and language in
the requirements. The SDT revised the language in the Rationale box to explain the program
performance relationships between types of encroachments, faults and outages, and various types of
failed maintenance, and how the various types of failed maintenance have historically been
associated with known vegetation related events.
One commenter requested that “of applicable lines” be added to the requirements and VSL verbiage
to clearly denote applicability within the requirements and VSL verbiage. The SDT made those
changes as requested to the requirements, measures and VSLs.
Two commenters requested an example be added to the Guidelines and Technical Basis similar to
the examples in R6 to clarify that the % calculations should be based on the Annual Plan as modified;
the SDT added the example as requested.
http://www.nerc.com/filez/standards/Vegetation-Management_Project_2007-7.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to
give every comment serious consideration in this process! If you feel there has been an error or
omission, you can contact the Vice President and Director of Standards, Herb Schrayshuen, at
404-446-2563 or via email at [email protected]. In addition, there is a NERC Reliability
Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on Draft 5 of FAC-003-2
2
Index to Questions, Comments, and Responses
1.
The SDT proposes a revised NERC Glossary definition for Right-of-Way (ROW). This revised
definition will be used in lieu of the Active Transmission Line ROW. Do you agree? If
answer is no, please explain. ................................................................................................ 10
2.
In R1 and R2 and their associated VSLs, the SDT added the phrase “in order of increasing
severity” and added the sentence “The types of encroachments are listed in order of
increasing degrees of severity in non-compliant performance as it relates to a failure of a
TO’s vegetation maintenance program.” to the Rationale boxes for R1/R2. Do you agree? If
answer is no, please explain. ................................................................................................ 28
3.
In response to comments received regarding the term “investigation” in M1/M2, the SDT
substituted “confirmation…by the Transmission Owner..” in its place, among other minor
edits to these measures. Do you agree? If answer is no, please explain. ............................ 38
4.
In response to comments received that requirement R3 is unclear with respect to intent,
the SDT added “maintenance strategies”. Do you agree this clarifies the intent? If answer is
no, please offer alternative language. .................................................................................. 46
5.
The SDT added clarifying language in M7 to explain how the annual work plan percentage
complete calculation is to be performed. Is this adequate? If no, please provide improved
examples. .............................................................................................................................. 53
Additional Comments from NERC:................................................................................................ 67
Consideration of Comments on Draft 5 of FAC-003-2
3
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
SERC Vegetation Management subcommittee
Joe Spencer
Additional Organization
Fatima Ahmed
SEPA
SERC
2.
Gerry Beckerie
Ameren
SERC
3.
Todd Bennett
AECI
SERC
4.
Brent Davis
Entergy
SERC
5.
Richard Dearman
TVA
SERC
6.
Jack Gardner
Progress Energy
SERC
7.
Jeff Hackman (chair) Ameren
SERC
8.
Ralph Hale
Entergy
SERC
9.
Jerry Lindler
SCANA
SERC
10. Larry Rodriguez
Entegra Power
SERC
11. Joe Spencer
SERC Reliability
SERC
12. John Troha
SERC Reliability
SERC
13. Marc Tunstall
Fayetteville Public Works Com SERC
14. Terry Wilson
Power South
Group
Sasa Maljukan
3
4
5
6
7
8
9
10
X
Region Segment Selection
1.
2.
2
SERC
Hydro One Networks
Consideration of Comments on Draft 5 of FAC-003-2
X
4
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. David Kiguel
Hydro One Networks Inc NPCC
2. Jonathan Marriott
Hydro One Networks Inc.
3.
Group
Additional Member
Guy Zito
Additional Organization
1
1
Northeast Power Coordinating Council
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC
10
2.
Gregory Campoli
New York Independent System Operator
NPCC
2
3.
Kurtis Chong
Independent Electricity System Operator
NPCC
2
4.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
5.
Bohdan M. Dackow
US Power Generating Company (USPG)
NPCC
NA
6.
Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC
1
7.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
8.
Brian Evans-Mongeon Utility Services
NPCC
8
9.
Mike Garton
Dominion Resources Services, Inc.
NPCC
5
10. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC
5
11. Kathleen Goodman
ISO - New England
NPCC
2
12. David Kiguel
Hydro One Networks Inc.
NPCC
1
13. Michael R. Lombardi
Northeast Utilities
NPCC
1
14. Randy MacDonald
New Brunswick Power Transmission
NPCC
1
15. Bruce Metruck
New York Power Authority
NPCC
6
16. Chantel Haswell
FPL Group, Inc.
NPCC
5
17. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
10
18. Robert Pellegrini
The United Illuminating Company
NPCC
1
19. Saurabh Saksena
National Grid
NPCC
1
20. Michael Schiavone
National Grid
NPCC
1
21. Wayne Sipperly
New York Power Authority
NPCC
5
22. Donald Weaver
New Brunswick System Operator
NPCC
2
23. Ben Wu
Orange and Rockland Utilities
NPCC
1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC
3
4.
Group
Deborah Schaneman
Additional Member Additional Organization
X
Platte River Power Authority Substation
Maintenance Group
Region
Consideration of Comments on Draft 5 of FAC-003-2
X
X
X
X
Segment
5
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
Selection
1.
Scott Rowley
Platte River Power Authority WECC
1, 3, 5, 6
2.
Gary Whittenberg
Platte River Power Authority WECC
1, 3, 5, 6
3.
Aaron Johnson
Platte River Power Authority WECC
1, 3, 5, 6
5.
Group
Denise Koehn
Additional Member
Bonneville Power Administration
Additional Organization
BPA, Transmission Field Services
WECC 1
2. Steven Narolski
BPA, Transmission Field Services
WECC 1
3. Frank Weintraub
BPA, Transmission Lign Design
WECC 1
4. Jennifer Bailey
BPA, Transmission, Construction Mgmt and Inspect WECC 1
5. Don Swanson
BPA, Transmission TLM Technical Services
WECC 1
6. Steve Bottemiller
BPA, Transmission, Real Property Support Svcs
WECC 1
7. Vince Ierulli
BPA, Transmission Lign Design
WECC 1
8. Mike Staats
BPA, Transmission Engineering
WECC 1
9. Jenifur Rancourt
BPA, FERC Compliance
WECC 1, 3, 5, 6
6.
Group
Doug Keegan
NERC Staff
7.
Group
David Thorne
Pepco Holdings Inc and Affiliates
Dana Small
RFC
1
2.
Lisa E Pfeifer
RFC
1
3.
Pat J Byrne
RFC
8.
X
X
X
X
X
X
X
X
Segment
Selection
1.
Group
X
Region Segment Selection
1. Charles Sheppard
Additional Member Additional Organization Region
X
1
Sam Ciccone
FirstEnergy
X
Additional Member Additional Organization Region Segment Selection
1. Rebecca Spach
FE
RFC
1
2. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
3. Dave Folk
FE
RFC
1, 3, 4, 5, 6
Consideration of Comments on Draft 5 of FAC-003-2
6
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4. Mike Ferncez
FE
RFC
1
5. Shawn Standish
FE
RFC
1
6. Katrina Schnobrich FE
RFC
Group
9.
Additional Member
Mike Garton
Additional Organization
Dominion Electric Market Policy
2
3
X
X
4
5
6
X
X
Dominion Resources Services, Inc. NPCC 5
2. Louis Slade
Dominion Resources Services, Inc. SERC
5
3. Connie Lowe
Dominion Resources Services, Inc. RFC
6
4. Michael Crowley
Dominion Virginia Power
1, 3
SERC
Individual
JT Wood
Southern Company Transmission
X
X
Individual
Janet Smith, Regulatory
Affairs Supervisor
Arizona Public Service Company
X
X
X
X
12.
Individual
Cynthia Oder
Salt River Project
X
X
X
X
13.
Individual
Luke Diruzza
Tampa Electric Company
X
X
X
X
14.
Individual
Silvia Parada Mitchell
NextEra Energy
X
X
X
X
15.
Individual
Jennifer Wright
SDG&E
X
X
X
16.
Individual
JAMES SMITH
ASSET MANAGEMENET
X
17.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie (NCR07112)
X
18.
Individual
Michael Gammon
Kansas City Power & Light
X
X
X
19.
Individual
Joe Petaski
Manitoba Hydro
X
11.
8
9
10
Region Segment Selection
1. Michael Gildea
10.
7
Consideration of Comments on Draft 5 of FAC-003-2
X
7
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
Individual
Weston Davis
Central Maine Power Company IberdrolaUSA
X
21.
Individual
Gordon Rawlings
BC Hydro
X
22.
Individual
Andrew Pusztai
American Transmission Company, LLC
X
23.
Individual
Thad Ness
American Electric Power
X
24.
Individual
William Rees
Baltimore Gas and Electric Co.
X
25.
Individual
Jason Regg
TVA
X
Individual
Michael Schiavone
Niagara Mohawk Power Corporation (dba
National Grid)
27.
Individual
Michael Pakeltis
CenterPoint Energy
X
28.
Individual
Greg Rowland
Duke Energy
X
29.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
30.
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
X
31.
Individual
Kirit Shah
Ameren
X
32.
Individual
Amy Kupferberg
Individual
NA
Individual
George Czerniewski
Consolidated Edison Company of New York,
Inc. - Transmission Line Maintenance
X
20.
26.
33.
Consideration of Comments on Draft 5 of FAC-003-2
2
X
3
4
5
6
X
X
X
X
X
X
X
X
X
X
X
X
X
X
7
8
9
10
X
8
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
34.
Individual
andres lopez
USACE
35.
Individual
CJ Ingersoll
CECD
36.
Individual
Edward J Davis
Entergy Services, Inc
X
X
37.
Individual
David Burke
Orange and Rockland Utilities, Inc.
X
X
38.
Individual
Saurabh Saksena
National Grid
X
X
39.
Individual
Steve Rueckert
Western Electricity Coordinating Council
40.
Individual
Jody Nelson
Georgia Transmission Corp.
X
41.
Individual
T. Wiley
Northern Indiana Public Service Company
X
Consideration of Comments on Draft 5 of FAC-003-2
4
5
6
X
7
8
9
10
X
X
X
X
X
X
9
1.
The SDT proposes a revised NERC Glossary definition for Right-of-Way (ROW). This revised definition will be used in lieu of the
Active Transmission Line ROW. Do you agree? If answer is no, please explain.
Summary Consideration: There are 40 comments; 29 of those comments were in agreement with the definition, and 11 were in
disagreement.
One repeated concern in the disagreements was whether or not “danger trees” rights outside the Right-of-Way (ROW) should be an
extension of the ROW. The SDT responded “The SDT has limited the definition of Right-of-Way to a corridor of land with a defined
width to operate a transmission line. This does not include danger tree rights.”
Another repeated concern in the disagreements was reference to the term “blowout standard” and commenters were asking for
more clarification and/or a definition of that term. To this line of comment the SDT responded “The definition includes a series of
options that gives the Transmission Owner latitude in establishing ROW width. It does not require selecting a single method for its
system. The term blowout standard is not capitalized and is not a defined term, and is intended to represent whatever conductor
“blow out” (as opposed to vegetation “blow in”) design criteria were used when the line was constructed. This phrase in the
definition allows a Transmission Owner to use its internal engineering standards or the general engineering standards that were in
effect when the line was constructed to determine the ROW width.”
A request was made to include the definition of MVCD within the definition section of the standard. The SDT agreed with the
commenter’s request and used the appropriate portion of the existing language in the rationale text box associated with R1 for the
MVCD definition. The SDT understands that this term will be added to the NERC glossary coincident with this standard becoming
effective. This is not a substantive change to the standard, it is merely procedural.
A request was made to remove the existing and future definition of ROW from the glossary. The SDT understands that this is not
consistent with the NERC intent for each repeated acronym used in multiple requirements to be available in the glossary for ready
reference.
A request was made to change the definition of ROW to include special permissions given by some property owners. To this the SDT
responded “The SDT has limited the definition of Right-of-Way to a corridor of land with a defined width to operate a transmission
line. The SDT does not propose to change the definition because of the numerous and varied special property owner permissions
that may exist, and which are not always legally binding.”
Consideration of Comments on Draft 5 of FAC-003-2
10
A concern within one disagreement was related to possible misuse of the “pre-2007 vegetation maintenance records.” The SDT
explained that this term was placed in the definition as a method to cover situations where the other alternatives are not viable. The
SDT will address this issue in the Technical Reference Document.
Organization
SERC Vegetation Management
sub-committee
Yes or No
Question 1 Comment
No
We agree with the proposed definition as a replacement for active transmission ROW, however, in
a review of NERC standards, the term ROW is not used except in FAC-003. It is therefore
recommended that the term be removed from the NERC glossary. r
Response: The SDT thanks you for your comments. The SDT considered your request but cannot implement it because it is not consistent with the
NERC Standards Development Process for defining the use of a term solely within a standard itself. All defined terms must be included in the
glossary.
Hydro One Networks
No
The revised definition of ROW is unclear in regards to the application of standards and/or historic
records as a means of determining ROW width; is it necessary for a TO to select one method to
apply in all cases, or can each span be treated in the manner deemed most appropriate by the TO?
Additionally “blowout Standard” has not been defined in the document or in the technical paper,
and therefore it is not clear exactly how this method would be applied, and subsequently defended
under scrutiny.
Response: The SDT thanks you for your comments. The definition includes a series of options that give the Transmission Owner latitude in
establishing ROW width. It does not require selecting a single method for its system. The term blowout standard is not capitalized and is not a
defined term, and is intended to represent whatever conductor “blow out” (as opposed to vegetation “blow in”) design criteria were used when
the line was constructed. This phrase in the definition allows a Transmission Owner to use its internal engineering standards or the general
engineering standards that were in effect when the line was constructed to determine the ROW width.
Northeast Power Coordinating
Council
No
There was no definition of ROW listed in FAC-003-1. The revised definition of ROW in FAC-003-2 is
unclear regarding the application of standards and/or historic records as a means of determining
Consideration of Comments on Draft 5 of FAC-003-2
11
Organization
Yes or No
Question 1 Comment
ROW width. Is it necessary for a TO to select one method to apply in all cases, or can each span be
treated in the manner deemed most appropriate by the TO? “Blowout standard” has not been
defined in the document, technical paper, or NERC Glossary and it is not clear what this method is,
and exactly how it would be applied. It could not be defended under scrutiny. It is still unclear
whether Danger Tree rights are included in this definition.In the NERC Glossary of Terms, Right-ofWay (ROW) is defined as “A corridor of land on which electric lines may be located. The
Transmission Owner may own the land in fee, own an easement, or have certain franchise,
prescription, or license rights to construct and maintain lines.” Propose keeping this definition.Is
encroachment into the MVCD, or (MVCD plus additional distance as defined by the TO)? MVCD, as
specified within the body of FAC-003-2 "is a calculated minimum distance stated in feet (meters) to
prevent flashover between conductors and vegetation, for various altitudes and operating
voltages." MVCD should be “formally” defined in this document, and the NERC Glossary. Can a
list/database be established in 2011 that lists the widths for the pre-2007 vegetation management
records?
Response: The SDT thanks you for your comments. The existing ROW definition in the glossary was created by and for the FAC-003-1 and was
moved there when that standard was adopted. The definition includes a series of options that give the Transmission Owner latitude in establishing
ROW width. It does not require selecting a single method for its system. The term blowout standard is not capitalized and is not a defined term,
and is intended to represent whatever conductor “blow out” (as opposed to vegetation “blow in”) design criteria were used when the line was
constructed. This phrase in the definition allows a Transmission Owner to use its internal engineering standards or the general engineering
standards that were in effect when the line was constructed to determine the ROW width. The SDT has limited the definition of Right-of-Way to a
corridor of land with a defined width to operate a transmission line. This does not include danger tree rights.
The definition of the MVCD is now added to this Standard. While use of the pre-2007 records is a compliance issue and is not in the purview of the
SDT, it is the intent of the language in the definition that you could use this information.
Platte River Power Authority
Substation Maintenance
Group
No
We agree that the ROW width in no case exceeds the TO’s legal rights but may be less. We do not
agree that the revised NERC Glossary definition for Right-of-Way addresses paragraph 734 of FERC
Order 693 “that rights-of-way be defined to encompass the required clearance areas instead of the
Consideration of Comments on Draft 5 of FAC-003-2
12
Organization
Yes or No
Question 1 Comment
corresponding legal rights, and that the standards should not require clearing the entire right-ofway when the required clearance for an existing line does not take up the entire right-of-way”. The
engineering or construction standards for establishing the width of the corridor outlined in the
definition are in most cases not useful. We will continue to rely on our easements and legal rights
with this definition. We believe the Active Transmission Line ROW definition in the previous version
more clearly addressed paragraph 734 of FERC Order 693.
Response: The SDT thanks you for your comments. The standard covers lines that have been built over many years where records could be lost.
The ROW definition provides three alternatives to determine the width of the corridor to be maintained.
NERC Staff
No
NERC supports a revised definition and prefers the definition in Draft 5 over the Active
Transmission Line ROW definition used in Draft 4. NERC believes the use of the term “pre-2007
vegetation maintenance records” in the proposed definition is ambiguous and will likely be
interpreted differently throughout the industry. Therefore, NERC supports this change subject to
removing the aforementioned term.
Response: The SDT thanks you for your comments. The phrase “…pre-2007 vegetation maintenance records…” was placed in the definition as a
method to cover situations where the other alternatives are not viable. The SDT has addressed this issue in detail in the Technical Reference
Document.
FirstEnergy
No
Although for the most part we agree with the changes to the definition of ROW, we suggest the
following changes.
1. The last sentence of the definition states "The ROW width in no case exceeds the Transmission
Owner's legal rights but may be less based on the aforementioned criteria." We do not agree with
the phrase "in no case exceeds the Transmission Owner's legal rights" because there could be
instances where special permission has been granted by landowners to the TO. We suggest revising
this statement to "The ROW width may be less than the Transmission Owner’s granted rights based
on the aforementioned criteria."
Consideration of Comments on Draft 5 of FAC-003-2
13
Organization
Yes or No
Question 1 Comment
2. Regarding the phrase "blowout standard" used in the definition, we are assuming this is in
reference to the company specific calculations for sag and sway on not on any one specific industry
standard. We suggest clarification such as "Transmission Owner's specific blowout or sag and sway
analysis in effect when the line was built".
Response: The SDT thanks you for your comments. The SDT has limited the definition of Right-of-Way to a corridor of land with a defined width to
operate a transmission line. The SDT does not propose to change the definition because of the numerous and varied special property owner
permissions that may exist, and which are not always legally binding.
The term blowout standard is not capitalized and is not a defined term, and is intended to represent whatever conductor “blow out” (as opposed
to vegetation “blow in”) design criteria were used when the line was constructed. This phrase in the definition allows a Transmission Owner to use
its internal engineering standards or the general engineering standards that were in effect when the line was constructed to determine the ROW
width.
Central Maine Power
Company - IberdrolaUSA
No
The definition does not define transmission owner responsibility for areas covered by “danger tree”
rights. This area is outside the maintained width but for economic and social reasons the
transmission owner can not remove all danger trees. Utilities have procedures in place to remove
the hazard trees but it is not practical to remove all danger trees that have the potential to violate
the MVCD should they fail. This area of the definition requires clarification.
Response: The SDT thanks you for your comments. The SDT has limited the definition of Right-of-Way to a corridor of land with a defined width to
operate a transmission line. This does not include danger tree rights.
TVA
No
I suggest that "arboricultural activities or horticultural or agricultural activities be removed and
changed to installation, removal or digging of vegetation.
Response: The SDT thanks you for your comments. The changes have been made in the footnotes.
Niagara Mohawk Power
Corporation (dba National
No
It is still unclear whether Danger Tree rights are included in this definition. Additional question:
Can we establish a list/database in 2011 stating the widths for the pre-2007 vegetation
Consideration of Comments on Draft 5 of FAC-003-2
14
Organization
Yes or No
Grid)
Question 1 Comment
management records? There is no definition of ROW listed in FAC-003-1, however in the NERC
Glossary of Terms, Right-of-Way (ROW) is defined as “A corridor of land on which electric lines may
be located. The Transmission Owner may own the land in fee, own an easement, or have certain
franchise, prescription, or license rights to construct and maintain lines.” We propose keeping this
definition.
Response: The SDT thanks you for your comments. The SDT has limited the definition of Right-of-Way to a corridor of land with a defined width to
operate a transmission line. This does not include danger tree rights. While use of the pre-2007 records is a compliance issue and is not in the
purview of the SDT, it is the intent of the language in the definition that you could use this information.
CenterPoint Energy
No
CenterPoint Energy agrees with the removal of “Active Transmission Line ROW” as a defined term.
The change in the NERC Glossary definition for Right-of-Way (ROW) alone, however, does not
address all of the remaining interpretation issues within the Standard that still exist.
The following issues still require resolution:
1. The “force majeure” was moved from the Applicability section to a footnote, and is no longer an
encompassing exception for each Requirement. Therefore, the “force majeure” footnote needs to
be applied not only to R1, R2, R6, and R7 but also R4 and R5. For R4, notification to the control
center would likely be restricted during a natural disaster. For R5, correction action by the control
center may not be possible during a natural disaster.
2. The exception for applicability beyond the “Rating and all Rated Electrical Operating Conditions”
should be included not only in R1, R2, and R3, but also R5 and R7. For R5 and R7, the
encroachment into the MVCD should consider whether the line is operating within its design limits.
3. The use of the term “Fault” in M1 and M2 should be revised to “Sustained Outage”. A “Fault”
can be associated with a Momentary Outage or a Sustained Outage. The scope of R1 and R2 is
specific to Sustained Outages only. The Periodic Data Submittal is specific to Sustained Outages
only as well. If a later confirmation of a “Fault” by the Transmission Owner indicates that a
vegetation encroachment into the MVCD was due to a fall-in from inside the ROW, yet caused only
Consideration of Comments on Draft 5 of FAC-003-2
15
Organization
Yes or No
Question 1 Comment
a Momentary Outage, the Transmission Owner would be in violation of R1 because M1 considers it
to be the equivalent of a Real-time observation. The current scope of the Standard is not intended
to include Momentary Outages. If it was, the Periodic Data Submittal would capture this type of
outage, which it does not.
4. In the Introduction Section 5 - Background, fall-ins are characterized as “statistically
intermittent” and “these types of events are highly unlikely to cause large-scale grid failures”.
CenterPoint Energy agrees and therefore recommends that fall-ins be excluded from the
Requirements R1, R2, and Periodic Data Submittal of outages. This would negate the need for
determining the limits of the ROW, thus simplifying the Standard to a great margin while not
sacrificing the emphasis of the Standard. The Draft 5 Background Information states the criteria for
developing a results-based reliability standard such that “each requirement should identify a clear
and measurable expected outcome.” When the determination of the limits of the ROW goes
beyond the interpretation of the legal limits of the ROW, it adds a level of complexity that may be
unclear and not deterministically measurable.
5. For R6, CenterPoint Energy believes the detailed rationale and studies used for the
determination of the required one year inspection cycle should be included in the Guidelines and
Technical Basis. The explanation provided in the Rationale that it is “based upon average growth
rates across North America and on common utility practice” are unfounded and arbitrary without a
specific reference to a North American study.
6. R7 contains the phrase, “provided they do not put the transmission system at risk of a vegetation
encroachment”. CenterPoint Energy recommends this phrase be replaced with the more specific
terminology used in the Rationale for R7 and R3: “provided they do not allow encroachment of
vegetation into the MVCD.”
7. CenterPoint Energy believes the Periodic Data Submittal should be clarified as to the specific
conditions under which Sustained Outages are reported. There is a reference to footnote 2
regarding the exclusion for the “force majeure”; however, the exclusion for lines operating outside
their design limits as mentioned in R1, R2, and R3 is missing. CenterPoint Energy believes the
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
wording should be changed to include all applicable exclusions for added clarity and recommends
the following wording: “The Transmission Owner will submit a quarterly report to its Regional
Entity, or Regional Entity’s designee, identifying all Sustained Outages of applicable transmission
lines operating within their Facility Rating and all Rated Electrical Operating Conditions as
determined by the Transmission Owner to have been caused by vegetation, except as excluded in
footnote 2, which includes as a minimum, the following:”
8. The Guidelines and Technical Basis and the Technical Reference with the Gallet Equation should
be combined into one document as a supplement to the Standard to avoid duplication in wording
and misinterpretation of context.
9. The Guideline and Technical Basis under Requirement R6 refers to the “percentage of the
required ROW inspections completed” and should be revised to match the wording of R6 and the
VSL for R6 as the “percentage of applicable transmission line inspections completed.”
10. CenterPoint Energy agrees that the Rationale test boxes should be deleted from the Standard
and applicable explanatory text be included within the Guidelines and Technical Basis.
11. The Guidelines and Technical Basis should contain specific examples for determining if a fall-in
is considered inside or outside the ROW.
12. CenterPoint Energy recommends modifying the Technical Reference section regarding
“Selecting a Maintenance Approach” to delete the sentences beginning with, “If constraints cannot
be overcome and if design clearances are sufficient...” and continuing through to, “identified early
for rectification.” This example may lead the public to inappropriately ask the utilities for
exceptions to allow vegetation beneath the transmission lines, and it also does not address the
dynamics of future modifications to the transmission lines (e.g. higher operating temperatures or
new conductors) that may necessitate reduced clearances to ground, thus requiring removal of
now mature vegetation. The example should not be included in a Standard intended to reduce
vegetation risks to the transmission system. It is also in conflict with later statements in the
Technical Reference regarding Set Objectives which emphasize maintaining access and clear lines of
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
sight.
13. In general, CenterPoint Energy strongly believes the proposed FAC-003-2 has gone far beyond
what was contemplated by the Commission in FERC Order 693. The Commission's determination
dealt with the following areas: (1) applicability; (2) inspection cycles; and (3) minimum clearances
on National Forest Service lands. For instance, in Paragraph 729, the Commission states, “As
proposed in the NOPR, the Commission approves Reliability Standard FAC-003-1 with no proposed
modification on the issue of clearances. The Commission reaffirms its interpretation that FAC-003-1
requires sufficient clearances to prevent outages due to vegetation management practices under
all applicable conditions....” Rewriting the minimum clearances introduces a new set of confusing
definitions, and further burdens the Transmission Owners with new documentation requirements
while providing little, if any, benefit when compared to the Clearance 2 concept in the existing
Standard.A preferred approach would be to incorporate the following few items into the existing
Standard FAC-003-1: (1) the RC versus the RRO; (2) the designation of a specific inspection
frequency; (3) the Gallet equation; and (4) the applicability to National Forest Service lands.
Response: The SDT thanks you for your comments: For clarity the SDT separated various items in your comments and repeated them below with
the numbered responses:
CenterPoint Energy agrees with the removal of “Active Transmission Line ROW” as a defined term. The change in the NERC Glossary definition for
Right-of-Way (ROW) alone, however, does not address all of the remaining interpretation issues within the Standard that still exist. The following
issues still require resolution:
1. The “force majeure” was moved from the Applicability section to a footnote, and is no longer an encompassing exception for each Requirement.
Therefore, the “force majeure” footnote needs to be applied not only to R1, R2, R6, and R7 but also R4 and R5. For R4, notification to the control
center would likely be restricted during a natural disaster. For R5, correction action by the control center may not be possible during a natural
disaster.
Response: Thank you for your comment. The SDT considers the term “without intentional delay” to be adequate coverage for force majeure issues
in R4. R5 requires that if you cannot perform work regardless of the reason you must come up with a plan to ensure that you prevent
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
encroachments, therefore a force majeure exemption is not applicable.
2. The exception for applicability beyond the “Rating and all Rated Electrical Operating Conditions” should be included not only in R1, R2, and R3, but
also R5 and R7. For R5 and R7, the encroachment into the MVCD should consider whether the line is operating within its design limits.
Response: The SDT thanks you for your comments. The SDT made the suggested changes to remove references to arboricultural, horticultural or
agricultural activities from the footnote 2, but did not adopt the suggestion for the new footnote 6 which replaces the footnote 4 to which you
refer” because that footnote 4 is concerned with completing the annual work plan, The SDT does not envision that actions by property owners such
as installation, or removal or digging of vegetation as a valid impediment to completion of the annual work plan. However this term is relevant in R1
and R2 and as such is within foot note 2 because such actions do occur from time to time without the transmission Owner’s knowledge and do then
result in conditions that could lead to encroachments and outages before the Transmission Owner has the opportunity to rectify the condition.
3. The use of the term “Fault” in M1 and M2 should be revised to “Sustained Outage”. A “Fault” can be associated with a Momentary Outage or a
Sustained Outage. The scope of R1 and R2 is specific to Sustained Outages only. The Periodic Data Submittal is specific to Sustained Outages only as
well. If a later confirmation of a “Fault” by the Transmission Owner indicates that a vegetation encroachment into the MVCD was due to a fall-in
from inside the ROW, yet caused only a Momentary Outage, the Transmission Owner would be in violation of R1 because M1 considers it to be the
equivalent of a Real-time observation. The current scope of the Standard is not intended to include Momentary Outages. If it was, the Periodic Data
Submittal would capture this type of outage, which it does not.
Response: Thank you for your comment. The reporting of Sustained Outages is simply to fulfill routine data submission. The SDT does not intend to
create a system that requires a root cause analysis of all Faults which are not Sustained Outages. The SDT did intend for those Faults as referenced in
M1 and M2 to be considered the equivalent of an encroachment observed in real time. The SDT also notes that the term Fault is an existing defined
term and momentary interruption is not.
4. In the Introduction Section 5 - Background, fall-ins are characterized as “statistically intermittent” and “these types of events are highly unlikely
to cause large-scale grid failures”. CenterPoint Energy agrees and therefore recommends that fall-ins be excluded from the Requirements R1, R2,
and Periodic Data Submittal of outages. This would negate the need for determining the limits of the ROW, thus simplifying the Standard to a great
margin while not sacrificing the emphasis of the Standard. The Draft 5 Background Information states the criteria for developing a results-based
reliability standard such that “each requirement should identify a clear and measurable expected outcome.” When the determination of the limits
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
of the ROW goes beyond the interpretation of the legal limits of the ROW, it adds a level of complexity that may be unclear and not deterministically
measurable.
Response: Thank you for your comment. Fall-ins from inside the ROW are indicators of a poor performing vegetation management program. The
definition of Right-of-Way identifies methods to define the width of the corridor establishing whether vegetation was located within the ROW and
subject to the Transmission Owner’s legal rights.
5. For R6, CenterPoint Energy believes the detailed rationale and studies used for the determination of the required one year inspection cycle should
be included in the Guidelines and Technical Basis. The explanation provided in the Rationale that it is “based upon average growth rates across
North America and on common utility practice” are unfounded and arbitrary without a specific reference to a North American study.
Response: Thank you for your comment. The SDT established an inspection cycle at least once per calendar year and with no more than 18 months
between inspections on the same ROW. This cycle was based on industry comments submitted to Draft 1 of this standard ending on 11-25-2008
6. R7 contains the phrase, “provided they do not put the transmission system at risk of a vegetation encroachment”. CenterPoint Energy
recommends this phrase be replaced with the more specific terminology used in the Rationale for R7 and R3: “provided they do not allow
encroachment of vegetation into the MVCD.”
Response: Thank you for your comment. The SDT agrees and has made the requested change to the draft standard.
7. CenterPoint Energy believes the Periodic Data Submittal should be clarified as to the specific conditions under which Sustained Outages are
reported. There is a reference to footnote 2 regarding the exclusion for the “force majeure”; however, the exclusion for lines operating outside their
design limits as mentioned in R1, R2, and R3 is missing. CenterPoint Energy believes the wording should be changed to include all applicable
exclusions for added clarity and recommends the following wording: “The Transmission Owner will submit a quarterly report to its Regional Entity,
or Regional Entity’s designee, identifying all Sustained Outages of applicable transmission lines operating within their Facility Rating and all Rated
Electrical Operating Conditions as determined by the Transmission Owner to have been caused by vegetation, except as excluded in footnote 2,
which includes as a minimum, the following:”
Response: Thank you for your comment. The SDT added your recommended language on “within its Rating and all Rated Electrical Operating
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
Conditions”.
8. The Guidelines and Technical Basis and the Technical Reference with the Gallet Equation should be combined into one document as a
supplement to the Standard to avoid duplication in wording and misinterpretation of context.
Response: Thank you for your comment. The Guideline and Technical section is part of the NERC Results Based Standard format. The Technical
Reference is a supplemental document that explains the VMSDT thought process in developing the requirements and applies to this version of the
standard.
9. The Guideline and Technical Basis under Requirement R6 refers to the “percentage of the required ROW inspections completed” and should be
revised to match the wording of R6 and the VSL for R6 as the “percentage of applicable transmission line inspections completed.”
Response: Thank you for your comment. VSL’s for R6 has been changed to align with the NERC Standard Development guidelines to “a Transmission
Owner failed to inspect”.
10. CenterPoint Energy agrees that the Rationale test boxes should be deleted from the Standard and applicable explanatory text be included within
the Guidelines and Technical Basis.
Response: Thank you for your comment.
11. The Guidelines and Technical Basis should contain specific examples for determining if a fall-in is considered inside or outside the ROW.
Response: Thank you for your comment. The SDT established the definition of a ROW and a fall-in resulting from vegetation would be determined
through investigation of the sustained outage.
12. CenterPoint Energy recommends modifying the Technical Reference section regarding “Selecting a Maintenance Approach” to delete the
sentences beginning with, “If constraints cannot be overcome and if design clearances are sufficient...” and continuing through to, “identified early
for rectification.” This example may lead the public to inappropriately ask the utilities for exceptions to allow vegetation beneath the transmission
lines, and it also does not address the dynamics of future modifications to the transmission lines (e.g. higher operating temperatures or new
conductors) that may necessitate reduced clearances to ground, thus requiring removal of now mature vegetation. The example should not be
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
included in a Standard intended to reduce vegetation risks to the transmission system. It is also in conflict with later statements in the Technical
Reference regarding Set Objectives which emphasize maintaining access and clear lines of sight.
Response: Thank you for your comment. This verbiage is part of an example describing a combination of strategies which may be utilized by a
Transmission Owner.
13. In general, CenterPoint Energy strongly believes the proposed FAC-003-2 has gone far beyond what was contemplated by the Commission in
FERC Order 693. The Commission's determination dealt with the following areas: (1) applicability; (2) inspection cycles; and (3) minimum clearances
on National Forest Service lands. For instance, in Paragraph 729, the Commission states, “As proposed in the NOPR, the Commission approves
Reliability Standard FAC-003-1 with no proposed modification on the issue of clearances. The Commission reaffirms its interpretation that FAC-003-1
requires sufficient clearances to prevent outages due to vegetation management practices under all applicable conditions....” Rewriting the
minimum clearances introduces a new set of confusing definitions, and further burdens the Transmission Owners with new documentation
requirements while providing little, if any, benefit when compared to the Clearance 2 concept in the existing Standard.A preferred approach would
be to incorporate the following few items into the existing Standard FAC-003-1: (1) the RC versus the RRO; (2) the designation of a specific inspection
frequency; (3) the Gallet equation; and (4) the applicability to National Forest Service lands.
Response: Thank you for your comment. The SDT believes the FAC 003-2 is an improvement over Version 1 and followed the SAR establishing that
the SDT should revise the standard.
Duke Energy
Yes
South Carolina Electric and
Gas
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Individual
Yes or No
Question 1 Comment
My Comments do not relate to the question asked, however, I saw no other place to add my
comment.
I would like to thank NERC for allowing the public to participate in the process of improving the
reliability standard FAC-003-1. I became interested in Vegetation Management requirements for
Transmission Lines, after Con Edison clear cut the ROW behind my home. I appreciate the
importance of safe and reliable electrical service, and recognize how an effective TVMP
contributes to this goal.
In this whole process, what has dispirited me the most, is the inaccurate information being
conveyed about why the clear cutting was necessary and, the causes of the August 14th, 2003
blackout. The narrative goes something like..”a tree falling onto transmission lines caused the
black out of 2003.” I find it harmful because it misdirects the focus from the grid’s short fallings,
and impedes upgrading the system to improve reliability.
I found this same philosophy in the initial pages of CN Utility’s document, UTILITY VEGETATION
MANAGEMENT FINAL REPORT MARCH 2004. It suggests that had the trees been adequately
maintained, the blackout would have most “likely” not happened. Now I am aware of the
qualification of the word “likely,” but the document is heavily weighted on the contribution of tree
contact to the blackout. We know that de-regulation and the physical nature of A.C. current had
more to do with the causes of the blackout, than tree contact. The timeline shows a range of
cascading system failures that created the catastrophic event. The trouble began at 1:58 p.m.
when First Energy generating plant in Eastlake, Ohio, shuts down. At 3:06 p.m. a First Energy 345kV transmission line fails. As a result, at 3:17 p.m voltage dips temporarily on the Ohio portion of
the grid. Controllers take no action, but power shifted onto another power line, overloading it and,
causing it to sag into a tree and go offline at 3:32 p.m. Mid West ISO and First Energy controllers
fail to inform system controllers in nearby states. At 3:41 and 3:46 p.m., two breakers connecting
First Energyʼs grid with American Electric Power are tripped. 4:05 p.m., a sustained power surge
on some Ohio lines signals more trouble building. At 4:09:02 p.m., voltage sags deeply, as Ohio
draws 2 GW of power from Michigan. 4:10:34 p.m., many transmission lines trip out, beginning in
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
Michigan and then in Ohio, blocking the eastward flow of power. Generators go down, creating a
huge power deficit, in seconds, power surges out of the East, tripping East coast generators, and
the rest is history.
The U.S.-Canada Power System Outage Task Force: Final Report on Implementation of
Recommendations, September 2006, states that “Inadequate reactive supply was a factor in most
of the events.” and “the assumed contribution of dynamic reactive output of system generators
was greater than the generators actually produced, resulting in more significant voltage problems.”
The backup generators were not adequate to handle the amperage load or voltage needed. A lack
of coordination of System Protection Programs(relays tripping), inadequate communication
between Utilities/TOs, and lack of "training of operating personnel in dealing with severe system
disturbances" are all the causes for the blackout.
With respect to vegetation management, the findings from The U.S.-Canada Power System Outage
Task Force: Final Report on Implementation of Recommendations, September 2006, clearly did not
intend for transmission owners to develop a one-size-fits-all standard.
The Energy Policy Act of 2005, initiated NERC to draft and adopt the standard FAC-003-1. When I
read through the standard, it all seems very reasonable. I can understand the stiff penalties for
noncompliance because it seems, like an easy fix, compared to the necessary, major changes in
infrastructure. The principles further outlined in ANSI A300 VII, and “Best Practices” IVM, seem
very reasonable too. There is mention of the environment, property owners, even proper pruning
techniques. The wire zone clearance of 10 feet and, allowing low growing compatible vegetation in
the boarder zone, seems to retain more vegetation, than remove.
However, in practice, the TOs are simply clear cutting the ROW, with no regard for the enviroment,
the trees that they are cutting, or the abutting properties. It took Con Edison 2 1/2 half days to
clear 450 tress form behind our home. We are now forced to see and hear 93,000 cars a day from
the Sprain Parkway. Following the clearing, our real estate broker dropped the asking price by
30%. The house remains empty and unsold. Apparently, no one is interested in spending 32,000K
a year in property taxes to look at transmission towers/lines and live on a highway. This has been
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
devastating to our family, and thousands of others in Westchester County. They removed a buffer
of trees that were 150 feet away from wires and towers, on a downward slope. These trees would
have never made contact with conductors.
Con Edison’s defense is that they did it because it was in their right to. Moreover, they use the
NERC fine structure to defend their behavior.I went through the Notice of Penalties that NERC has
issued from 6/2/08-2/01/11. Out of 646 Notice of Penalties, 1700 violations were sited, 36 out of
1700 penalties were issued for violations to the FAC- 003-1 standard. Some NOPs had multiple
violations-18 R1 violations were cited and 29 penalties were issued for R2 violations. Out of the 29
R2 penalties, 20 involved tree contact. Some outages were caused by sagging wires, some were
caused by arcing electricity looking for a ground fault, but none were caused by a tree falling onto
the transmissions wires. The numbers should put into perspective how immaterial the problem of
tree contact really is.
Think about it... 20 out of 1700 involved tree contact, and none of then resulted in a sustained
outage. That means 1680 violations were issued due to other system failures. To use these
penalties as an excuse is a complete over exaggeration. What is missing from the standard and the
fine structure, are penalties for over cutting and violations to other stipulations, such as proper
communication, training, and aftercare of the affected areas. The problems that have arisen from
current TVMP activities being executed nationally on our ROWs, is not a public perception
problem. Rather, TOs are not complying with standards that are meant protect the environment
and they are not respecting the property rights of the neighboring homeowners.
I appreciate the opportunity to share my views, and would take any opportunity to further
participate in protecting the rights of property owners, and the environment, while working to
secure safe and reliable electrical service. Most respectfully, Amy M Kupferberg - Utility Whisperer
Response: The SDT thanks you for your comments. You raise a host of issues regarding the operations of electric transmission systems as well as
recounting the blackout of 2003. We agree there seems to be wide public opinion of what actually was the cause of the blackout. Relative to your
recommendations for our team, we note that appropriate NERC standards contain requirements regarding training and communications among
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
other things. For example, requirement R4 of this standard contains language which requires communication when certain vegetation conditions
are discovered. As you know training and communications were just two of the many issues addressed in the blackout report.
In response to your comment “What is missing from the standard and the fine structure, are penalties for over cutting and violations to other
stipulations, such as proper communication, training, and aftercare of the affected areas,” this Standard is meant to define what needs to be
accomplished to achieve reliability; it is up to the Transmission Owner to perform the vegetation maintenance in a manner to accomplish that goal
consistent with applicable environmental concerns and local regulations.
Consolidated Edison Company
of New York, Inc. Transmission Line
Maintenance
Yes
USACE
Yes
CECD
Yes
Entergy Services, Inc
Yes
The revised Glossary definition of ROW helps to clarify the intent of what is expected and/or
considered ROW stipulations. This is a beneficial addition/clarification.
Response: The SDT thanks you for your comments.
Orange and Rockland Utilities,
Inc.
Yes
National Grid
No
The revised ROW definition emphasizes the ROW width needed to operate the transmission line(s).
It is National Grid’s interpretation that the width established when the line was constructed is the
width to be maintained. This width is documented in engineering drawings, per-2007 vegetation
records or blow-out standards. This definition does not imply that danger tree rights beyond the
constructed and maintained width are incorporated in the definition; therefore fallins - from
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 1 Comment
outside the ROW but within within an area with danger tree rights would not be considered fallinins from within the ROW. National Grid would like the SDT to comment on this interpretation in its
response to these comments.
Response: The SDT thanks you for your comments. Your interpretation is consistent with the intent of the definition that the SDT provided.
However the definition includes a series of options that give the Transmission Owner latitude in establishing ROW width. It does not require
selecting a single method for its system. This phrase in the definition allows a TO to use its internal engineering standards or the general
engineering standards that were in effect when the line was constructed to determine the ROW width. The SDT has limited the definition of Rightof-Way to a corridor of land with a defined width to operate a transmission line. This does not include danger tree rights.
Western Electricity
Coordinating Council
Yes
Georgia Transmission Corp.
Yes
Northern Indiana Public
Service Company
Yes
Consideration of Comments on Draft 5 of FAC-003-2
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2.
In R1 and R2 and their associated VSLs, the SDT added the phrase “in order of increasing severity” and added the sentence
“The types of encroachments are listed in order of increasing degrees of severity in non-compliant performance as it relates to
a failure of a TO’s vegetation maintenance program.” to the Rationale boxes for R1/R2. Do you agree? If answer is no, please
explain.
Summary Consideration: 32 of the 38 responses agreed with the changes. The SDT made changes to the footnotes in response to
4 requests. Three of the “yes” response comments included positive references to the improved clarity, alignment with results based
standards, reinstatement of Category 3 outages and the importance of investigations which will be necessary to categorize violations
across the various VSLs.
The disagreements included concerns over the relationships between the VSLs and language in requirements. The SDT revised the
language in the Rationale box to explain the program performance relationships between types of encroachments, faults and
outages, and various types of failed maintenance, and how the various types of failed maintenance have historically been associated
with known vegetation related events.
In response to a request to exchange the order of severity levels of the failure to maintain vegetation to prevent encroachments
from blowing together versus fall-ins, the SDT explained that the blowing together is considered a higher severity level of failed
maintenance since the sway of the conductor is in most cases more determinable and less variable than the more complex geometry
associated and numerous variables associated with fall-ins.
In response to a comment that there was no need for R1 and R2, the SDT explained that removal of R1 and R2 could be viewed as
lessening the reliability of the standard.
One comment recommended that the standard include language to allow any encroachment found and removed, absent a Fault or
Sustained Outage, to not be considered a violation. The SDT noted that the MVCD is a component that must be considered in the
“building block” approach inherent in the standard, and as such, any encroachment inside the MVCD indicates a significant failure in
overall vegetation program approach.
One comment requested a return to the Clearance 1 in the existing standard to support work that is resisted by property owners
and other parties that do not want vegetation to be adequately maintained. The SDT referenced the problem associated with a fillin-the-blank requirement, and explained how this standard does not preclude a utility from removing or pruning vegetation well
beyond the MVCD, but primarily focuses on determining when a violation occurs. The SDT asserts that vegetation maintenance must
Consideration of Comments on Draft 5 of FAC-003-2
28
address the many variables that exist such as growth rates, vegetation maintenance cycles, conductor sag and sway, etc. that could
result in an encroachment of the MVCD which would be a direct violation of the standard. The vegetation program must factor in
delays and/or mitigation measures associated with stakeholder concerns, but must clearly communicate the need for maintenance
to ensure strict compliance with this zero-tolerance standard.
Organization
Yes or No
SERC Vegetation Management
sub-committee
Yes
Hydro One Networks
Yes
Northeast Power Coordinating
Council
Yes
Platte River Power Authority
Substation Maintenance
Group
Yes
Bonneville Power
Administration
Yes
Question 2 Comment
BPA prefers the stratified levels of violation severity presented in the table for R1 and R2.Foot note
#2 on page 8 needs to be clarified with respect to arboricultural activities or horticultural or
agricultural activities. What specifically does this phrase refer to?Foot note #4 on page 12 needs to
be clarified with respect to arboricultural activities or horticultural or agricultural activities. What
specifically does this phrase refer to?
Response: The SDT thanks you for your comments.
The SDT has changed footnote 2 to read as follows:
This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to this reliability standard,
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 2 Comment
including natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by
the Transmission Owner or an applicable regulatory body, ice storms, and floods; human or animal activity such as logging, animal severing tree,
vehicle contact with tree, or installation, removal, or digging of vegetation. Nothing in this footnote should be construed to limit the Transmission
Owner’s right to exercise its full legal rights on the ROW.
The SDT has changed footnote 4 (now footnote 6 in the revised standard) to read as follows:
Circumstances that are beyond the control of a Transmission Owner include but are not limited to natural disasters such as earthquakes, fires,
tornados, hurricanes, landslides, ice storms, floods, or major storms as defined either by the TO or an applicable regulatory body.
NERC Staff
No
The sentence was added to the rationale but the phrase “in order of increasing severity” is not in
the requirement or their associated VSLs. NERC staff does not support the language in the rationale
box which differentiates the VSL based on skill level of maintenance personnel rather than the
impact to reliability of the encroachment. The VSL should be based on whether or not the owner
managed the vegetation to prevent encroachment and therefore be binary. See additional
comments submitted separately regarding combining R1 and R2.
Response: The SDT thanks you for your comments. VSLs should not be assigned based on the impact to reliability, as is proposed by the
commenter. NERC’s VSL Guidelines state the following regarding VSLs: “This is not the same as saying that the requirement is really important and
any noncompliance would have an adverse reliability impact – the impact to reliability should be addressed through the VRF, not the VSL.”
However, the SDT has made changes to reword the rationale in R1 and R2 to further explain how program performance must successfully account
for the relationships between types of encroachments, faults and outages, various types of failed maintenance, and how the various types of failed
maintenance have historically been associated with known vegetation related events.
Pepco Holdings Inc and
Affiliates
Yes
FirstEnergy
No
For the Requirement R1 and R2 VSLs, we suggest that the proposed Moderate (fall-ins) and High
(blowing together) VSL be interchanged. We believe that fall-ins are more severe encroachments
than blowing together and the categories listed in the compliance section support this point.
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 2 Comment
Category 1 (grow-ins) is most severe, followed by Category 2 & 3 (fall-ins) and Category 4 (blowing
together).
Response: The SDT thanks you for your comments. The choice of the VSL for the fall-ins versus the blowing together was made by the SDT using
logic in the language in the rationale text box for R1: “The types of failure to manage vegetation are listed in order of increasing degrees of severity
in non-compliant performance as it relates to a failure of a TO’s vegetation maintenance program, since the encroachments listed require different
and increasing levels of skills and knowledge and thus constitute a logical progression of how well, or poorly, a TO manages vegetation relative to
this Requirement.”
Dominion Electric Market
Policy
Yes
Southern Company
Transmission
Yes
Arizona Public Service
Company
No
This is a reliability standard and the TO should know what its clearance needs are at all rated
conditions, especially considering today’s technology. If the TO manages to this standard there is
no need for R1 and R2.
Response: The SDT thanks you for your comments. Elimination of R1 and R2 would be considered as a lessening of the standard.
Salt River Project
Yes
Tampa Electric Company
Yes
Adds clarity to the VSL from an audit perspective, this is an improved description to the Standard.
Response: The SDT thanks you for your comments.
NextEra Energy
Yes
Although NextEra Energy Inc. (NextEra), including Florida Power & Light Company, agrees with the
changes referenced for R1 and R2, NextEra is concerned that the exemptions identified in footnote
Consideration of Comments on Draft 5 of FAC-003-2
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Organization
Yes or No
Question 2 Comment
2 for “...arboricultural activities or horticultural or agricultural activities...,” and similar language in
footnote 4, are too broad. For example, this language appears to include an exemption for a
landowner, who, during arboricultural activities or horticultural or agricultural activities, causes a
vegetation contact with a transmission line (e.g., cutting or lifting a tree into a transmission line).
This places the Transmission Owner in the difficult position of a landowner arguing it is exempt
from a controllable risk. Thus, the “...arboricultural activities or horticultural or agricultural
activities...” references should be removed from footnote 2, and the similar language in footnote 4
Response: The SDT thanks you for your comments. The SDT made the suggested changes.
SDG&E
Yes
ASSET MANAGEMENET
Yes
Hydro-Quebec TransEnergie
(NCR07112)
Yes
Kansas City Power & Light
No
These proposed Requirements, Measures and Violation Severity Levels as written do not give credit
to the Transmission Owners for effectively monitoring their systems and taking appropriate actions
in regard to vegetation clearing. Why does it make sense to punish and penalize a Transmission
Owner for discovering an encroachment when they take the appropriate actions to remedy the
condition before any facility outage occurs that results in compromising the reliability of the Bulk
Electric System? These Requirements, Measures and VSL’s should recognize the good practices of
effective response to a vegetation condition and penalize ineffective response. Recommend the
SDT consider including appropriate language to recognize effective remedial actions by
Transmission Owners and by doing so, recognize effective efforts instead of punishing them. In
addition, proving encroachments have not occurred will pose audit challenges in determining that
encroachments have not occurred for the Auditors as well as Registered Entities. If no
encroachments occur, then there is nothing to report or record. This is a weak platform to stand
Consideration of Comments on Draft 5 of FAC-003-2
32
Organization
Yes or No
Question 2 Comment
compliance on. Facility interruption events caused by vegetation contacts is definitively
measurable and recordable. Recommend the SDT reconsider the concept of compliance with FAC003 on the basis of sustained outages and remove the references regarding encroachments only.
Recommend the SDT remove the LOWER VSL language from Requirements R1 and R2 and revise
the Requirements and Measures to reflect the same.
Response: The SDT thanks you for your comments. The MVCD was established as a beginning of a series of “building blocks” for a good program.
R3 requires that a TO add to MVCD distances with further considerations for the variables of conductor movement and the variables associated
with vegetation growth when designing the TO’s overall vegetation management approach(s). The net result of this “building block” approach is
the management of vegetation at clearance distances much greater than the MVCD distances. Other related requirements of this “Defense in
Depth” Standard serve to address any number of scenarios which may arise or hinder the TO’s ability to always strictly adhere to the management
approach(s) established within R3. Thus the other requirements of this Standard provide the latitude for “appropriate actions to remedy the
condition” without penalty. Further, it is obvious that trees which have encroached inside of the MVCD are clear evidence of a failed vegetation
management program.
Manitoba Hydro
Yes
Central Maine Power
Company - IberdrolaUSA
Yes
BC Hydro
Yes
American Transmission
Company, LLC
Yes
American Electric Power
No
American Electric Power believes that the phrase "arboricultural activities or horticultural or
agricultural activities" was mistakenly introduced into Footnotes 2 and 4, and should be deleted
from both footnotes. If the phrase remains in the Standard, it may empower orchard growers,
landowners and others to plant trees on the right of way and challenge Transmission Owners'
Consideration of Comments on Draft 5 of FAC-003-2
33
Organization
Yes or No
Question 2 Comment
rights to perform maintenance on the presumption that the standard will exempt the TO from
violating the outage or encroachment requirements.
Response: The SDT thanks you for your comments. The SDT made the suggested changes.
Baltimore Gas and Electric Co.
Yes
TVA
Yes
Niagara Mohawk Power
Corporation (dba National
Grid)
Yes
CenterPoint Energy
Yes
Duke Energy
Yes
We agree with the drafting team’s approach, and also agree with reinstating reporting of Category
3 (Fall-ins from outside the ROW) in the Additional Compliance Information section. The SDT
responded to comments submitted with the last ballot that:”Zero tolerance for vegetation caused
outages is a stated goal of FERC and NERC as it relates to this standard. This policy is part of FAC003-1 and in concept did not change with the proposed version. The SDT recognizes this concern
and has developed gradation taking into account line criticality in VRF’s and type of outage not
contained in the current version FAC-003-1. Finally, it is also important to note that each and every
incident or potential violation is investigated and addressed based on the specific circumstances
surrounding the particular event. These investigations should necessarily take into consideration
and recognize the utility's individual efforts in responding to an encroachment situation.” In
addition, we believe that clarifying changes need to be made to footnotes 2 and 4. Clarify footnote
2 by removing the phrase “arboricultural activities or horticultural or agricultural activities” and
replacing it with the phrase “installation of”. Similarly, clarify footnote 4 by removing the phrase
“arboricultural, horticultural or agricultural activities”, and replacing it with the phrase “or human
Consideration of Comments on Draft 5 of FAC-003-2
34
Organization
Yes or No
Question 2 Comment
activities such as installation, or removal or digging of vegetation.”
Response: The SDT thanks you for your comments. The SDT made the suggested changes to remove references to arboricultural, horticultural or
agricultural activities from the footnote 2, but did not adopt the suggestion for the new footnote 6 which replaces the footnote 4 to which you
refer” because that footnote 4 is concerned with completing the annual work plan, The SDT does not envision that actions by property owners
such as installation, or removal or digging of vegetation as a valid impediment to completion of the annual work plan. However this term is
relevant in R1 and R2 and as such is within foot note 2 because such actions do occur from time to time without the transmission Owner’s
knowledge and do then result in conditions that could lead to encroachments and outages before the Transmission Owner has the opportunity to
rectify the condition.
South Carolina Electric and
Gas
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
This is more in alignment with a results-based reliability standard.
Response: The SDT thanks you for your comments.
Individual
Consolidated Edison Company
of New York, Inc. Transmission Line
Maintenance
Yes
USACE
Yes
Consideration of Comments on Draft 5 of FAC-003-2
35
Organization
Yes or No
CECD
Yes
Entergy Services, Inc
Yes
Orange and Rockland Utilities,
Inc.
Yes
National Grid
Yes
Western Electricity
Coordinating Council
Yes
Georgia Transmission Corp.
Yes
Northern Indiana Public
Service Company
No
Question 2 Comment
While there are some enhancements to the organization and content of the standard such as the
addition of the Guidelines and Technical Basis section, clarification of what constitutes evidence of
compliance, and tailoring of VSL severity levels for the requirements based on the risk each poses
to the likelihood of contributing to a cascade, too many elements present in FAC-003-1 and which
are vital to preventing vegetation caused outages and maximizing system reliability, have been
eliminated from FAC-003-2. Specifically, the elimination of concrete, declared and audited
clearance standards between vegetation and conductors (the existing Clearance 1 and Clearance 2
(R1.2)) Requirements) in the revised standard is a major defect that will decrease system reliability.
It has been indispensable for NIPSCO when communicating with stake holders (governments,
interest groups, land owners, the public, etc.) to point to these clearance standards to give
credibility and support to the kind of tree removal and trimming that is necessary to achieve the
stated objective of zero preventable tree caused outages. Without these declared clearance
standards in the NERC standard, utility vegetation managers will constantly be challenged by stake
holders to show them that such work is required rather than an elective choice on the utility's part.
One of the key lessons learned from the 2003 blackout and First Energy's overgrown ROW tree
Consideration of Comments on Draft 5 of FAC-003-2
36
Organization
Yes or No
Question 2 Comment
problem was that individual land owners, local governments, and interest groups will exert
pressure on the utility to only do the minimum amount of vegetation management. Without
external and enforceable Vegetation Clearance Standards and by returning to a pre-2003 regime
where the extent of vegetation clearing is left to the individual discretion and pressures at each
utility, there is no doubt that tree clearance conditions will deteriorate over time and put system
reliability at greater risk of vegetation contact.
Response: The SDT thanks you for your comments. At the request of FERC in Order 693, the SDT was asked to eliminate the fill-in-the-blank
clearance requirements that are currently in FAC-003-1. A proven Engineering calculation was utilized to determine when a transmission line could
spark over to vegetation without direct contact. Based on this calculation, each utility must determine what clearance levels need to be maintained
as part of their TVMP. The current version does not preclude a utility from removing or pruning vegetation well beyond the MVCD, it just
establishes a line in the sand that determines when a violation occurs. Individual TOs must establish a program that addresses the many variables
that exist such as growth rates, vegetation management cycles, conductor sag and sway, etc. that could result in an encroachment of the MVCD
which would be a direct violation of the standard. Establishing a specific clearance value to be attained during vegetation management activities is
too prescriptive and is in direct conflict with the Results-Based Standard initiative that the SDT is currently implementing. Each TO must factor in
delays and/or mitigation measures associated with stakeholder concerns but must clearly communicate the challenges with maintaining strict
compliance with this zero-tolerance standard.
Consideration of Comments on Draft 5 of FAC-003-2
37
3.
In response to comments received regarding the term “investigation” in M1/M2, the SDT substituted “confirmation…by the
Transmission Owner..” in its place, among other minor edits to these measures. Do you agree? If answer is no, please explain.
Summary Consideration: 34 of the 40 comments agreed with the change. One of the affirmative comments noted the need to make
a minor change in the Guidelines and Technical Basis to assure conformance with the standard language; that change was made.
One commenter questioned what would compel an entity to document and report outages. The SDT feels that this issue is
addressed by the NERC Sanctions guidelines.
It was noted that the last two paragraphs in M1 and M2 were not really measures and should be addressed in the requirements. The
requirements now include this language in footnote 3.
Two commenters wished to include language to exempt brief encroachments into the MVCD due to falling trees. The SDT chose not
to make that change due to concerns raised by regulatory observers.
One commenter felt that a violation should occur for any calculated potential for an MVCD encroachment. The SDT noted that the
MVCD is a beginning of a series of “building blocks” for a program to ensure reliability within the line’s rating and all rated electrical
operating conditions. R3 requires that a TO add to MVCD distances with further considerations for the variables of conductor
movement and the variables associated with vegetation growth when designing the TO’s overall vegetation management
approach(s). Additionally there is a “Defense in Depth” in this Standard to address any number of scenarios which may arise or
hinder the TO’s ability to always strictly adhere to the management approach(s) established within R3. Thus the other requirements
of this Standard provide the latitude for appropriate actions to remedy the condition without penalty.
One comment replied that there was no value to the measure due to the lack of reference to a violation for any calculated potential
MVCD encroachment. The SDT pointed again to requirement R3 which requires this to be addressed in the maintenance strategies
in R3.
One commenter suggested to delete the reference to measures in the evidence retention section; the SDT chose to retain the
existing language.
Organization
Yes or No
Consideration of Comments on Draft 5 of FAC-003-2
Question 3 Comment
38
Organization
Yes or No
SERC Vegetation Management
sub-committee
Yes
Hydro One Networks
Yes
Northeast Power Coordinating
Council
Yes
Platte River Power Authority
Substation Maintenance
Group
Yes
Bonneville Power
Administration
Yes
NERC Staff
No
Question 3 Comment
Concur with restating as mentioned above. Other issues remain regarding data reports indicating
no sustained outages or real-time observations. These measures appear to indicate that if the
outages or real-time observations are not documented then an encroachment didn’t occur. What
will compel an entity to document these occurrences? In addition, the last two paragraphs of the
Measure are not really measures. They would be better served as part of the Requirement.
Response: The SDT thanks you for your comments. The issue of how does one prove that an event did not occur is problematic. A TO must
document the inspections it completes. If an inspection does not note an encroachment then none was observed. The NERC Sanction Guidelines
provide adequate sanctions for the dishonest. The SDT agrees that the last two paragraphs are not measures and would belong in the requirement.
The SDT has moved them to the requirement as footnotes.
Pepco Holdings Inc and
Affiliates
Yes
Consideration of Comments on Draft 5 of FAC-003-2
39
Organization
Yes or No
FirstEnergy
Yes
Dominion Electric Market
Policy
Yes
Southern Company
Transmission
No
Question 3 Comment
We would recommend the middle paragraph of M1 and M2 be revised as follows: “If a later
confirmation of a Fault by the TO shows that vegetation encroachment within the MVCD has
occurred from vegetation growing into or blowing into the conductor within the ROW, this shall be
considered the equivalent of a Real-time observation. Brief encroachments caused by a falling tree
going through the MVCD is not considered an encroachment.”
Response: The SDT thanks you for your comments. The SDT is sympathetic to your concern. In fact, the SDT had originally crafted language similar
to that which you suggested. However, due to concerns expressed by regulators and others, the exemption for encroachment violations due to
falling vegetation from inside the right of way was removed.
Arizona Public Service
Company
No
The TO should be managing for reliability. The system is not static, like vegetation it moves and
changes over time and that fluctuation should be taken into account to maintain reliability at all
rated conditions.
Response: The SDT thanks you for your comments. The SDT agrees with your statement, and in that vein, the MVCD was established as a
beginning of a series of “building blocks” for a program to ensure reliability within its rating and all rated electrical operating conditions. R3
requires that a TO add to MVCD distances with further considerations for the variables of conductor movement and the variables associated with
vegetation growth when designing the TO’s overall vegetation management approach(s). The net result of this “building block” approach is the
management of vegetation at clearance distances much greater than the MVCD distances. Other related requirements of this “Defense in Depth”
Standard serve to address any number of scenarios which may arise or hinder the TO’s ability to always strictly adhere to the management
approach(s) established within R3. Thus, the other requirements of this Standard provide the latitude for appropriate actions to remedy the
condition without penalty. Further, trees which have encroached inside the MVCD are evidence of a deficiency in vegetation maintenance.
Consideration of Comments on Draft 5 of FAC-003-2
40
Organization
Yes or No
Salt River Project
Yes
Tampa Electric Company
Yes
Question 3 Comment
Confirmation allows for the potential of a greater number of “action items” than just investigation.
Response: The SDT thanks you for your comments. We agree that confirmation is necessary before an event is determined to be vegetation
related.
NextEra Energy
Yes
SDG&E
Yes
ASSET MANAGEMENET
Yes
Hydro-Quebec TransEnergie
(NCR07112)
Yes
Kansas City Power & Light
Yes
Manitoba Hydro
Yes
Central Maine Power
Company - IberdrolaUSA
Yes
BC Hydro
Yes
American Transmission
Company, LLC
Yes
American Electric Power
No
For increased clarity, AEP offers the following change to the second paragraph of M1, as well as the
Consideration of Comments on Draft 5 of FAC-003-2
41
Organization
Yes or No
Question 3 Comment
second paragraph of M2. The original text “If a later confirmation of a Fault by the Transmission
Owner shows that a vegetation encroachment within the MVCD has occurred from vegetation
within the ROW, this shall be considered the equivalent of a Real-time observation” should be
replaced with ““If a later confirmation of a Fault by the Transmission Owner shows that a
vegetation encroachment within the MVCD has occurred from vegetation growing into or blowing
together with the conductor within the ROW, this shall be considered the equivalent of a Real-time
observation. A brief encroachment caused by falling vegetation passing through the MVCD is not
considered an encroachment in this requirement”.
Response: The SDT thanks you for your comments. The SDT is sympathetic to your concern. In fact, the SDT had originally crafted language similar
to that which you suggested. However, due to concerns expressed by regulators and others, the exemption for encroachment violations due to
falling vegetation from inside the right of way was removed.
Baltimore Gas and Electric Co.
No
M1 & M2 bullet: “Real-time observation of any MVCD encroachments.” implies that real-time
observation of vegetation encroachment ensures reliable operation the Bulk Electric System. The
reliability standard objective states;”To improve the reliability of the electric Transmission system
by preventing those vegetation related outages that could lead to Cascading.”However, real time
observation of current operating conditions provides no assurance that vegetation will not lead to
outages since it doesn’t take into consideration the full conductor range of motion including
maximum sag. BGE recommends removing the language. If an inspector finds vegetation
encroaching into the MVCD during a visual inspection he / she should immediately initiate an
Immediate Threat Notification. Therefore, this measure has no value.
Response: The SDT thanks you for your comments. The SDT agrees with your statement and in that vein, the MVCD was established as a beginning
of a series of “building blocks” for a program to ensure reliability within its rating and all rated electrical operating conditions. R3 requires that a
TO add to MVCD distances with further considerations for the variables of conductor movement and the variables associated with vegetation
growth when designing the TO’s overall vegetation management approach(s). The net result of this “building block” approach is the management
of vegetation at clearance distances much greater than the MVCD distances. Other related requirements of this “Defense in Depth” Standard
serve to address any number of scenarios which may arise or hinder the TO’s ability to always strictly adhere to the management approach(s)
Consideration of Comments on Draft 5 of FAC-003-2
42
Organization
Yes or No
Question 3 Comment
established within R3. Thus the other requirements of this Standard provide the latitude for appropriate actions to remedy the condition without
penalty. Further, trees which have encroached inside the MVCD are evidence of a deficiency in vegetation maintenance.
TVA
Yes
Niagara Mohawk Power
Corporation (dba National
Grid)
Yes
CenterPoint Energy
Yes
Duke Energy
Yes
However, this change was not completely made in paragraph five of the Guideline and Technical
Basis document. There the phrase “an investigation” should be replaced by the phrase “a later
confirmation”
Response: The SDT thanks you for your comments. The SDT made the suggested change.
South Carolina Electric and
Gas
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
Individual
Consolidated Edison Company
of New York, Inc. Transmission Line
Yes
Consideration of Comments on Draft 5 of FAC-003-2
43
Organization
Yes or No
Question 3 Comment
Maintenance
USACE
Yes
CECD
No
Suggested Modification to the Measure - "If an after-the-fact analysis of a Fault by the Transmission
Owner determines that a vegetation encroachment within the MVCD has occurred from vegetation
within the ROW, this shall be considered the equivalent of observing an encroachment in RealTime."
CECD would also like to comment on the Evidence Retention section, as it relates to Measures. The
Evidence Retention section states that the Transmission Owner retains data or evidence to show
compliance with Requirement R1, R2, R3, R5, and R7, Measures M1, M2, M3, M5, M6 and M7 for
three calendar years...." Measures provide examples of evidence that a Transmission Owner can
produce to show compliance with the associated Requirement but are not separate Requirements
to be managed so reference to Measures should be deleted from the Evidence Retention section of
the standard.
Response: The SDT thanks you for your comments. The SDT prefers to keep the existing language, which has been widely accepted by industry,
since it is substantially the same as you suggest. With respect to the Evidence Retention section: The NERC evidence retention guidelines provided
to SDTs recommend including a reference to the associated requirements and measures.
Entergy Services, Inc
Yes
Orange and Rockland Utilities,
Inc.
Yes
National Grid
Yes
Western Electricity
Yes
Consideration of Comments on Draft 5 of FAC-003-2
44
Organization
Yes or No
Question 3 Comment
Coordinating Council
Georgia Transmission Corp.
Yes
Northern Indiana Public
Service Company
Yes
Consideration of Comments on Draft 5 of FAC-003-2
45
4.
In response to comments received that requirement R3 is unclear with respect to intent, the SDT added “maintenance
strategies”. Do you agree this clarifies the intent? If answer is no, please offer alternative language.
Summary Consideration: 36 responses were in agreement, 2 disagreed with no comments and 2 disagreements included
comments.
A concern was raised with regard to using the MVCD as a distance “to manage a vegetation program” and asked the SDT to provide
a buffer distance. The SDT explained that the MVCD was established as a beginning of a series of “building blocks” for a program to
ensure reliability within its rating and all rated electrical operating conditions. R3 requires that a TO add to MVCD distances with
further considerations for the variables of conductor movement and the variables associated with vegetation growth when
designing the TO’s overall vegetation management approach(s). The net result of this “building block” approach is the management
of vegetation at clearance distances much greater than the MVCD distances. Other related requirements of this “Defense in Depth”
Standard serve to address any number of scenarios which may arise or hinder the TO’s ability to always strictly adhere to the
management approach(s) established within R3. Thus the other requirements of this Standard provide the latitude for appropriate
actions to remedy the condition without penalty. Further, trees which have encroached inside the MVCD are evidence of a
deficiency in vegetation maintenance. A performance based standard is not prescriptive in nature but gives guidance to a TO on
“what” to accomplish rather than “how” to accomplish it.
Another agreeable response requested R5 and R7 to include a relationship between the document that is developed for
maintenance strategies and the annual work plan. The SDT explained that the references to the work plan in R5 and R7 are
sufficient. The SDT considers maintenance strategies and work plans to be separate functions. Avoiding the reference to the work
plans in R3 minimizes confusing the two functions.
One disagreement stated that the term “maintenance strategies” was not helpful and recommends the following: “Each
Transmission Owner shall have a documented vegetation management plan that includes maintenance strategies, procedures,
processes, and specifications it uses to prevent the encroachment of vegetation into the MVCD of its applicable lines that include(s)
the following:” The SDT notes that Requirement 3 is a results-based competency requirement and that having a TVMP as required
in version 1 is simply a matter of having documentation, but there was no stipulation or concern for the quality of the TVMP as
called for by version 1. In R3 of the revised Standard, the aspect of quality is introduced. The Transmission Owner must show that it
has maintenance strategies in place that will logically keep vegetation from encroaching into the MVCD.
Consideration of Comments on Draft 5 of FAC-003-2
46
Another disagreement stated that the TVMP shall demonstrate the TO’s ability to manage the system at all rated conditions to
maintain reliability. The SDT agrees that this is the purpose of R3 and referenced the language in the rationale text for R3 clarifies “... documentation provides a basis for evaluating the competency of the Transmission Owner’s vegetation program. There may be
many acceptable approaches to maintain clearances. Any approach must demonstrate that the Transmission Owner avoids
vegetation-to-wire conflicts under all Ratings and all Rated Electrical Operating Conditions. See Figure 1 for an illustration of possible
conductor locations.” A TVMP is one example of an approach to which this refers.
Organization
Yes or No
SERC Vegetation Management
sub-committee
Yes
Hydro One Networks
Yes
Northeast Power Coordinating
Council
Yes
Platte River Power Authority
Substation Maintenance
Group
Yes
Bonneville Power
Administration
Yes
Question 4 Comment
The TO procedures / policies and specifications shall demonstrate the TO’s ability to manage the
system at all rated conditions to maintain reliability.BPA believes that the intent is clear, but the
fundamental approach of using the MVCD (table 2) to manage a vegetation program is still
problematic. These values are flashover distances and are way too close. This is acknowledged in a
footnote to table 2 but no identification of allowable buffers/distances between energized phase
conductors at rated temperatures and vegetation is discussed (this is left up the transmission
owners). Clarity is needed on this topic. Setting a finite distance limit based on recognized
standards, good science and risk avoidance should be done for the industry. BPA previously made
this comment during the drafting of the standard. It was not addressed then, nor has it been
Consideration of Comments on Draft 5 of FAC-003-2
47
Organization
Yes or No
Question 4 Comment
addressed now.
Response: The SDT thanks you for your comments. The SDT agrees with your statement, and in that vein, the MVCD was established as a beginning
of a series of “building blocks” for a program to ensure reliability within its rating and all rated electrical operating conditions. R3 requires that a
TO add to MVCD distances with further considerations for the variables of conductor movement and the variables associated with vegetation
growth when designing the TO’s overall vegetation management approach(s). The net result of this “building block” approach is the management
of vegetation at clearance distances much greater than the MVCD distances. Other related requirements of this “Defense in Depth” Standard
serve to address any number of scenarios which may arise or hinder the TO’s ability to always strictly adhere to the management approach(s)
established within R3. Thus the other requirements of this Standard provide the latitude for appropriate actions to remedy the condition without
penalty. Further, trees which have encroached inside the MVCD are evidence of a deficiency in vegetation maintenance. A performance based
standard is not prescriptive in nature but gives guidance to a TO on “what” to accomplish rather than “how” to accomplish it.
NERC Staff
No
Adding the term “maintenance strategies” is not helpful in the requirement. NERC staff
recommends the following: “Each Transmission Owner shall have a documented vegetation
management plan that includes maintenance strategies, procedures, processes, and specifications
it uses to prevent the encroachment of vegetation into the MVCD of its applicable lines that
include(s) the following:”
Response: The SDT thanks you for your comments. Requirement R3 is a results-based competency requirement. Having a TVMP as required in
version 1 is simply a matter of having documentation. There was no stipulation or concern for the quality of the TVMP as called for by version 1.
In R3 of the revised Standard, the aspect of quality is introduced. The Transmission Owner must show that it has maintenance strategies in place
that will logically keep vegetation from encroaching into the MVCD.
Pepco Holdings Inc and
Affiliates
Yes
FirstEnergy
Yes
Dominion Electric Market
Yes
Consideration of Comments on Draft 5 of FAC-003-2
48
Organization
Yes or No
Question 4 Comment
Policy
Southern Company
Transmission
Yes
Arizona Public Service
Company
No
The TVMP shall demonstrate the TO’s ability to manage the system at all rated conditions to
maintain reliability.
Response: The SDT thanks you for your comments. We agree that this is the purpose of R3. Please note the language in the rationale text for R3
clarifies - “... documentation provides a basis for evaluating the competency of the Transmission Owner’s vegetation program. There may be many
acceptable approaches to maintain clearances. Any approach must demonstrate that the Transmission Owner avoids vegetation-to-wire conflicts
under all Ratings and all Rated Electrical Operating Conditions. See Figure 1 for an illustration of possible conductor locations.” A TVMP is one
example of an approach to which this refers.
Salt River Project
Yes
Tampa Electric Company
Yes
Good addition, adds clarity and improves overall understanding of the requirement.
Response: The SDT thanks you for your comments.
NextEra Energy
Yes
SDG&E
Yes
ASSET MANAGEMENET
Yes
Hydro-Quebec TransEnergie
(NCR07112)
Yes
Consideration of Comments on Draft 5 of FAC-003-2
49
Organization
Yes or No
Kansas City Power & Light
Yes
Manitoba Hydro
Yes
Central Maine Power
Company - IberdrolaUSA
Yes
BC Hydro
Yes
Question 4 Comment
You could also include the term “maintenance standards”.
Response: The SDT thanks you for your comments. Either word could work – however since most commenters agreed with the use of the word,
‘strategies’ the SDT did not adopt the suggestion to use the word, ‘standards’.
American Transmission
Company, LLC
Yes
American Electric Power
Yes
Baltimore Gas and Electric Co.
Yes
TVA
Yes
Niagara Mohawk Power
Corporation (dba National
Grid)
Yes
CenterPoint Energy
Yes
Duke Energy
Yes
Consideration of Comments on Draft 5 of FAC-003-2
50
Organization
Yes or No
South Carolina Electric and
Gas
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
Question 4 Comment
This clearly defines “intent”.
Response: The SDT thanks you for your comments.
Individual
Consolidated Edison Company
of New York, Inc. Transmission Line
Maintenance
Yes
USACE
No
CECD
Yes
Because Requirement 5 and 7 use the phrase annual work plan, and there is not a Requirement to
develop a work plan, this Requirement should include a relationship between the document that is
developed for maintenance strategies and the annual work plan.
Response: The SDT thanks you for your comments. The SDT considers the references to the work plan in R5 and R7 sufficient. The SDT considers
maintenance strategies and work plans to be separate functions. Avoiding the reference to the work plans in R3 minimizes confusing the two
functions.
Entergy Services, Inc
Yes
Consideration of Comments on Draft 5 of FAC-003-2
51
Organization
Yes or No
Orange and Rockland Utilities,
Inc.
Yes
National Grid
Yes
Western Electricity
Coordinating Council
Yes
Georgia Transmission Corp.
Yes
Northern Indiana Public
Service Company
No
Consideration of Comments on Draft 5 of FAC-003-2
Question 4 Comment
52
5.
The SDT added clarifying language in M7 to explain how the annual work plan percentage complete calculation is to be
performed. Is this adequate? If no, please provide improved examples.
Summary Consideration: There were 31 agreements and 8 disagreements. Seven comments noted that the question should have
referenced R7 not M7. The SDT acknowledged that observation and agreed that the reference should have been R7. The SDT added
the term “of applicable lines” to M7 and to the VSL’s for R4, R5 and R6. The SDT also made minor changes to VSLs for R7 to conform
to verbiage in R6.
One commenter agreed with R7 changes and noted “there is no requirement....that a plan is....developed.” The SDT sees no reason
to add such a requirement for documentation, since a fundamental precept of results-based standards is that having a requirement
to complete any particularly activity also presupposes that the elements required to complete the activity are included in the
requirement, even if unstated.
One affirmative comment requested that exceptions for crew performance and availability be noted explicitly: the SDT noted that
while the requested condition could be listed, the list is not meant to be exhaustive, and that any modification to the work plan can
be made provided it does not allow encroachment into the MVCD. The same commenter wished to include language related to
derating the line to indicate that the purpose of such action would be to “ensure continued...reliability.” The SDT saw problems
associated with proving that a reliability contribution by a derating was in fact accomplished and chose to retain the existing
language. The same commenter wished to remove Category 3 outage reporting, but the SDT sees great value in the investigation of
each vegetation related outage and feels that this reporting is justified to ensure that all outages are sufficiently investigated. The
same commenter requested removing the reference to “defense-in-depth” in the Background section; the SDT chose to leave this
reference as is. Lastly that same commenter suggested that “promptly” could be substituted for “without intentional time delay” in
R4, the SDT saw no difference in the two terms and chose to keep the existing verbiage.
A commenter suggested in lieu of the annual inspection requirement that a time interval based on growth rates be used instead. The
SDT chose to retain the existing annual interval based on industry’s consensus support for the one year interval in a previous posting
of the Standard.
A commenter requested that “of applicable lines” be added to the requirements and VSL verbiage to clearly denote applicability
within the requirements and VSL verbiage. The SDT made those changes as requested to the requirements, measures and VSLs.
That same commenter requested that Category 3 outages be reported by type A & B similar to other categories. The SDT saw no
value to this change since Category 3 serves its purpose without that distinction being made. The same commenter requested
Consideration of Comments on Draft 5 of FAC-003-2
53
changes to the ROW definition; the SDT chose to retain the existing language since it has been vetted with significant industry
consensus.
Another comment suggested adding reference to financial reports in the examples for reasons for modifications to the annual plan,
the SDT feels that such a reference to financial conditions was inappropriate. The same commenter noted the need for clarity in the
structure of the VSLs ; the SDT made those changes. The same commenter requested clarity on use of Table 2 when an entity has a
voltage category not in the table - the team added language to clarify that where the TO has transmission lines operated at nominal
levels not listed in Table 2, the TO should use the clearance distances based on the maximum system voltage (i.e. for a nominal
system voltage of 287 kV the appropriate distances would be for a maximum system voltage of 362 kV). Two commenters requested
an example be added to the Guidelines and Technical Basis section for R7, similar to the examples in R6, to clarify that the %
calculations should be based on the Annual Plan as modified; the SDT added the example as requested.
Another commenter questioned the 48-hour reporting in the 12/17/2008 NERC Public Notice - NERC Compliance Process #2008-001.
The SDT discussed the issue with NERC staff and did not receive any direction that it would be necessary to add this as a
Requirement within the Standard
Additional comments were offered by NERC staff as a separate attachment to comments submitted with the comment form, and
those responses are covered following this question.
Organization
Yes or No
SERC Vegetation Management
sub-committee
Yes
Hydro One Networks
Yes
Northeast Power Coordinating
Council
No
Question 5 Comment
There is no percentage language in M7. Is it R7 that is being referred to?
Response: The SDT thanks you for your comment. The SDT meant to refer to R7.
Consideration of Comments on Draft 5 of FAC-003-2
54
Organization
Yes or No
Platte River Power Authority
Substation Maintenance
Group
Yes
Bonneville Power
Administration
Yes
NERC Staff
Yes
Question 5 Comment
Actually, R7 contains the clarifying language. It should be noted that although R7 indicates the TO
shall complete 100% of the VM work plan, there is no requirement in this draft that a plan is
actually developed.
Response: The SDT thanks you for your comments. The SDT meant to refer to R7, not to M7. As to the seeming lack of an actual requirement for a
work plan, the SDT asserts that a fundamental precept of results-based standards is that having a requirement to complete any particularly activity
also presupposes that the elements required to complete the activity are included in the requirement, even if unstated.
Pepco Holdings Inc and
Affiliates
Yes
FirstEnergy
Yes
Although we generally agree with Requirements R7 and its measure M7, we suggest adding
clarifying wording to bullet 4 which states "Crew or contractor availability/ Mutual assistance
agreements". In addition to availability, contractor performance may be another issue that requires
modification to the work plan. We suggest adding another bullet that reads "Crew or contractor
performance". The rationale behind this addition is to address poor safety, productivity and/or
quality issues with a crew or contractor assigned to perform vegetation management.FirstEnergy
provides the following additional comments and suggestions not related to the specific questions
asked in this posting:
1. Requirement R5 - We appreciate this requirement which recognizes that the TO may face
situations in which it is constrained from performing its vegetation management and are permitted
Consideration of Comments on Draft 5 of FAC-003-2
55
Organization
Yes or No
Question 5 Comment
to seek alternative methods. However, there may be instances where the TO has exhausted all
course of action to perform vegetation and must utilize other means to prevent vegetation
encroachment into the MVCD. Therefore, in these instances, "continued vegetation management"
as stated in the requirement is not possible, but other methods such as line deratings and
deenergizing of lines may have to be used. We ask that the phrase "to ensure continued vegetation
management to prevent encroachments" be changed to read “to ensure continued reliability of the
BES”.
2. Compliance Section - Category 3 - We suggest removing this category from the standard. Since
fall-ins from outside the ROW are not considered a violation of this standard per Requirements R1
and R2, the entity should not have to report these fall-ins.
3. Objectives - We do not believe that is necessary for the Objectives statement to include the
"defense-in-depth" concept which is actually an overarching goal of results-based standards in
general and not specific to FAC-003-2. We suggest removing this phrase.
4. Background Section 5 - Similar to our comment above regarding defense-in-depth in the
objectives statement, this is an overarching goal of results based standard and not specific to FAC003-2. Therefore, we suggest removing the explanation of defense-in-depth from the background
section.
5. Vegetation Inspection Definition - We suggest replacing the word "hazard" with "risk".
6. Requirement R4 - We do not agree with the phrase "without any intentional time delay" and
suggest it be removed. This phrase is not measurable. Also, other drafting teams have attempted to
incorporate this statement but industry comments have persuaded them to remove it; for
example, the Reliability Coordination drafting team (Project 2006-06) initially proposed the same
phrase but later removed it in their development of the COM/IRO standards. At the very least
standards development should be consistent throughout the NERC standards drafting teams. We
suggest the following as wording for Requirement R7: "Each Transmission Owner shall ensure the
control center holding switching authority for the applicable transmission line is promptly notified
Consideration of Comments on Draft 5 of FAC-003-2
56
Organization
Yes or No
Question 5 Comment
when the Transmission Owner has confirmed the existence of a vegetation condition that can
potentially cause a Fault."
Response: The SDT thanks you for your comments. The SDT considered your request to add to the acceptable reasons for modifications the bullet,
“Crew or contractor performance,” and observes that since R7 states “Modifications to the work plan in response to changing conditions or to
findings from vegetation inspections may be made (provided they do not allow encroachment of vegetation into the MVCD)...” the bullet could be
added, but the SDT did not intend the list of examples to be exhaustive and decided not to add the new bullet.
In reference to the comment 1) that the phrase "to ensure continued vegetation management to prevent encroachments" be changed to read “to
ensure continued reliability of the BES,” the SDT agrees that the corrective actions of de-ratings and de-energization as you suggest must be
considered when vegetation cannot be maintained to prevent encroachment into the MVCD, and those examples are explicitly listed in M5. If a
de-rating is used, it must be sufficient to prevent the encroachment into the MVCD. The de-rating or de-energization of the line removes the
threat of an energized line and adjacent vegetation having less separation that the MVCD (i.e. less Fault probability), but the realized reliability
value of those actions will depend on the events that occur while the condition persists. For these reasons the SDT retains the R5 language without
changes.
In reference to the comment 2) “Compliance Section - Category 3 -...suggest removing this category from the standard,” an investigation of the
location of the tree with respect to the edge of the ROW for fall-ins must be made to determine whether the event represents a self-report of a
violation or not. A record of those findings when the tree is found to be outside the ROW is valuable for both the Compliance Monitoring and
Enforcement and the TO, should any questions later arise; therefore the SDT chose to retain the Category 3 reporting.
Regarding your comment 3) “Objectives - We do not believe that is necessary for the Objectives statement to include the "defense-in-depth"
concept which is actually an overarching goal of results-based standards in general and not specific to FAC-003-2. We suggest removing this
phrase.” The SDT notes that the Purpose language is a general statement, and could be expanded or contracted without impacting the
requirements. However, since the current language has undergone extensive debate, comment and revision the SDT sees no compelling reason to
request industry to review another change at this time.
Regarding your comment 4) “Background Section 5 -.... suggest removing the explanation of defense-in-depth from the background section” The
SDT notes again that the background section language is a general statement and could be expanded or contracted without impacting the
requirements. However, since the defense-in-depth drove many of the changes in the standard the SDT thinks this section is relevant and should
be retained.
Consideration of Comments on Draft 5 of FAC-003-2
57
Organization
Yes or No
Question 5 Comment
Regarding your comment 5) “suggest ...for Requirement R7(actually R4): "Each Transmission Owner shall ensure the control center holding
switching authority for the applicable transmission line is promptly notified when the Transmission Owner has confirmed the existence of a
vegetation condition that can potentially cause a Fault." The SDT has searched for but not found a time limit more suitable than “without
intentional time delay.” An extensive list of event scenarios between the time that a condition is observed and the time it is reported can be
studied. In the final analysis the intent is for the notification to be made to allow time for the control center to take steps to maintain reliability if
possible before conditions deteriorate further. “Without intentional time delay” is as sufficient and as measurable as “promptly”.
Dominion Electric Market
Policy
No
The red-line revision does not indicated changes to M7; therefore, Dominion is unable to evaluate
the clarifying language identified in this question. If the SDT meant to reference R7, we agree that
the clarification is adequate.
Response: The SDT thanks you for your comments. The SDT means to reference R7.
Southern Company
Transmission
Yes
Arizona Public Service
Company
Yes
Salt River Project
Yes
Tampa Electric Company
Yes
This allows flexibility for the T.O. to determine the type of “unit” used in calculating the percentage
complete.
Response: The SDT thanks you for your comments.
NextEra Energy
Yes
SDG&E
Yes
Consideration of Comments on Draft 5 of FAC-003-2
58
Organization
Yes or No
ASSET MANAGEMENET
Yes
Hydro-Quebec TransEnergie
(NCR07112)
No
Question 5 Comment
The minimum frequency of Vegetation Inspection should be based upon an average growth rates of
smaller regions than all North America. Example, above the latitude of about 50 degrees North, the
vegetation growth rates is limited. We think that Vegetation Inspection frequency should be
relaxed to 3 years for those areas in Canada. As indicator of the minimum frequency requested in
R6, we suggest to use a global vegetation index like the Normalized Difference Vegetation Index
(NDVI). The NDVI has been in use for many years to measure the vigor of vegetation growth among
other things. http://earthobservatory.nasa.gov/Features/MeasuringVegetation/
Response: The SDT thanks you for your comments. In FERC Order 693, para. 721, FERC stated, “The Commission continues to be concerned with
leaving complete discretion to the transmission owners in determining inspection cycles, which limits the effectiveness of the Reliability Standard.”
The SDT established an inspection cycle at least once per calendar year and with no more than 18 months between inspections on the same ROW.
There was a survey of the industry in a previous request for comments to this standard. The response to that survey is the basis for the use of the
1-year period. While there was a range of growth rates across the continent, the SDT had sufficient feedback to recommend the 1-year cycle. The
inspection also would cover inspecting for fall-in threats. Please note that vegetation inspections can also be combined with other line inspections.
Kansas City Power & Light
No
1) R7 states “Each Transmission Owner shall complete 100% of its annual vegetation work plan...”.
We suggest to be consistent with all other sections of the rule that it should read, “Each
Transmission Owner shall complete 100% of its annual vegetation work plan for all applicable
lines...”. Otherwise, leaves room for interpretation to include all lines including those not defined
as applicable. Also require these same revisions to row R7 of the table “Time Horizons, Violation
Risk Factors, and Violation Severity Levels”.
2) In the “Additional Compliance Information” section Categories 1, 2, and 4 are each defined to
have an A & B component to recognize the severity level difference for “applicable transmission
lines” identified versus not identified “as an element of an IROL or Major WECC Transfer Path”.
However, Category 3 does not separate these two scenarios however it appears that the same
Consideration of Comments on Draft 5 of FAC-003-2
59
Organization
Yes or No
Question 5 Comment
distinction should apply.
Additional comments:Vegetation Inspection Definition Recommend the SDT consider removing the
conditional language, “that are likely to pose a hazard to the line(s) prior to the next”. Vegetation
inspections are not dependent on a predisposed condition of vegetation. Suggest the SDT remove
that phrase and consider the following definition:The systematic examination of vegetation
conditions on a maintained transmission line Right-of-Way under the Transmission Owner’s control
under a planned maintenance or inspection which may be combined with a general line inspection.
Response: The SDT thanks you for your comments. 1) The team has made the appropriate modifications, adding the reference to ‘applicable lines’
where necessary. 2) Since the Category 3 outages do not have any violations associated with their occurrences, the SDT did not see the value in
reporting by type A or type B lines. 3) The SDT chooses to keep the current language because it addresses the core need to find conditions that will
need correcting before the next planned maintenance or next planned inspection is performed.
Manitoba Hydro
Yes
Central Maine Power
Company - IberdrolaUSA
Yes
BC Hydro
Yes
You could also include other documentation such as monthly financial and program variance
reports.
Additional Comments
Table 1: R6 definitions could be clearer. Suggested clarification:
VSL Lower - Greater than 95% of annual inspections complete but less than 100% complete.
VSL Moderate - Greater than 90 % of annual inspections complete but less than 95% complete
VSL High - Greater than 85% of annual inspections complete but less than 90% complete
VSL Severe - Less than 85% of annual inspections completed
Consideration of Comments on Draft 5 of FAC-003-2
60
Organization
Yes or No
Question 5 Comment
Table 1 R7 definitions could be clearer. Suggested clarification:
VSL Lower - Greater than 95% of annual work plan complete but less than 100% complete.
VSL Moderate - Greater than 90 % of annual work plan complete but less than 95% complete
VSL High - Greater than 85% of annual work plan complete but less than 90% complete
VSL Severe - Less than 85% of annual work plan completed
Table 2: This table includes a number of common nominal system voltages vs MVCD distances by
altitude. However, some utilities have other non-standard voltages, in our case 287 kV, which
forms a significant part of their system. It may be worthwhile for the standard to state what a
utility should follow when a standard voltage class is not present - i.e. go to the next higher voltage
MVCD if a particular voltage isn’t in the table, or direct the utility to do its own Gallett Equation
calcuations for their unique voltage class. Otherwise, different utilities may create a non-standard
solution that wouldn’t address the risk.
Response: The SDT thanks you for your comments. The SDT did not intend for the list of examples to be exhaustive. To the extent that financial or
variance reports include evidence of the work units completed they may be useful as supportive evidence. inappropriate.
The SDT used the NERC VSL Guidelines to develop the VSLs; therefore the SDT feels that the VSL's for R7 are adequate as listed. The proposed VSLs
would leave some ‘gaps’ – for example the proposed VSLs aren’t clear on what VSLs is assigned when an entity has completed exactly 95% of its
inspections.
Table 2 in the Standard lists both the nominal system voltages and the corresponding maximum system voltages. The clearance distances listed
for each nominal system voltage were calculated using the maximum system voltage values. Therefore, where the TO has transmission lines
operated at nominal levels not listed in Table 2, the TO should use the clearance distances based on the maximum system voltage (i.e. for a
nominal system voltage of 287 kV the appropriate distances would be for a maximum system voltage of 362 kV). The SDT has added language to
the guidelines and technical basis section to clarify this point.
American Transmission
Yes
Consideration of Comments on Draft 5 of FAC-003-2
61
Organization
Yes or No
Question 5 Comment
Company, LLC
American Electric Power
Yes
Baltimore Gas and Electric Co.
Yes
TVA
No
I suggest that footnote 4 be changed by removing the reference to arbicultural, horticultural or
agricultural activities.
Response: The SDT thanks you for your comments. The recommended changes have been made to footnote 4.
Niagara Mohawk Power
Corporation (dba National
Grid)
No
There is currently no percentage language in M7. If they are referring to R7, then YES it is
adequate.
Response: The SDT thanks you for your comments. The question should have referred to R7.
CenterPoint Energy
No
CenterPoint Energy could not find any reference to an example percentage complete calculation
for the annual work plan in the Standard for M7, in the Guideline and Technical Basis for M7, nor in
the Technical Reference for M7. There was such an example for M6 which was helpful. CenterPoint
Energy recommends such an example be included for M7.
Response: The SDT thanks you for your comments. The percentage complete should be based on the annual plan as modified.
The SDT has changed the language in the standard to reflect more clearly that the percentage complete should be based on the plan as modified,
and the following example has been added to the Guideline and Technical Basis:
For example, when a Transmission Owner identifies 1,000 miles of 230 kV transmission lines to be completed in the TO’s annual plan, the
Transmission Owner will be responsible completing those identified miles. If a TO makes a modification to the annual plan that does not put the
transmission system at risk of an encroachment the annual plan may be modified. If 100 miles of the annual plan is deferred until next year the
calculation to determine what percentage the TO completed for the current year would be: 1000 – 100 (deferred miles) = 900 modified annual
Consideration of Comments on Draft 5 of FAC-003-2
62
Organization
Yes or No
Question 5 Comment
plan, or 900 / 900 = 100% completed annual miles. If a TO only completed 875 of the total 1000 miles with no acceptable documentation for
modification of the annual plan the calculation for failure to complete the annual plan would be: 1000 – 875 = 125 miles failed to complete then,
125 miles (not completed) / 1000 total annual plan miles = 12% failed to complete.
Duke Energy
Yes
South Carolina Electric and
Gas
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
This is directed toward R7 rather than M7.
Response: The SDT thanks you for your comments.
Individual
Consolidated Edison Company
of New York, Inc. Transmission Line
Maintenance
Yes
The added language for the annual work plan percentage complete calculation is shown in R7 not
M7 as stated in the question. In the Guideline and Technical Basis Section for Requirement R6,
there is a sample calculation shown for the amount of lines the TO failed to inspect. An example
should also be included for Requirement R7 since there is some confusion regarding how
modifications to the work plan affect the calculation. In the Lower VSL column for R7, it states that
the TO failed to complete up to 5% of its annual vegetation work plan (including modifications if
any). If a TO operates 100 lines and submits a justified modification that affects 10 miles of lines,
the total number of units in the final amended plan is 90 miles. When you read the VSL, it is
somewhat confusing since the information in parenthesis says that the calculation 'includes' the
modifications. Should it state 'excludes modifications if any' or the VSLs can simply be re-written to
state that ..The TO failed to complete up to x% of the final amended plan.' Also, the VSLs in R6 and
Consideration of Comments on Draft 5 of FAC-003-2
63
Organization
Yes or No
Question 5 Comment
R7 should be consistent with each other: R6 says '...TO failed to inspect 5% or less.....' and R7 says
'...TO failed to complete up to 5%....' They both should use the same verbiage in each VSL whether
it is 'x% or less' or 'up to and including x%.'
Response: The SDT thanks you for your comments. The percentage should be based on the plan as modified. The SDT has changed the language in
the standard to reflect this more clearly.
USACE
Yes
CECD
Yes
Entergy Services, Inc
Yes
The actual clarifying language seems to have been added to R7 instead of M7 (as stated above).
The clarifying language provides benefit as added to R7, and should remain in R7.Additionally, we
feel that, in an effort to promote consistency with the other 6 Requirements, the term "on
applicable Transmission lines" should be added at the end of the first sentence of R7, as it is listed
in all other R's. The first sentence of R7 currently reads: "Each Transmission Owner shall complete
100% of its annual vegetation work plan to ensure no vegetation encroachments occur within the
MVCD". We feel the first sentence should read "Each Transmission Owner shall complete 100% of
its annual vegetation work plan to ensure no vegetation encroachments occur within the MVCD on
applicable transmission lines".
Response: The SDT thanks you for your comments. The first sentence does now contain the term “applicable lines”.
Orange and Rockland Utilities,
Inc.
Yes
National Grid
No
There is currently no percentage language in M7. If they are referring to R7, then YES it is
adequate.
Consideration of Comments on Draft 5 of FAC-003-2
64
Organization
Yes or No
Question 5 Comment
Response: The SDT thanks you for your comments. The SDT was referring to R7.
Western Electricity
Coordinating Council
Yes
We support the clarifying languae in M7However, since there is no generic "Any other Comments"
section associated with this on-line comment form, we raise a question here. On December 24,
2008, NERC issued an e-mail to all Transmission Owners in which it referenced its December 17,
2008 Public Notice - NERC Compliance Process #2008-001, Vegetation-related Transmission Outage
Reporting. The notice stated that: "Due to the potential severity of transmission outages caused by
vegetation associated with Standard FAC-003-1, NERC is encouraging each Transmission Owner to
self-report all Category 1 and Category 2 transmission outages related to vegetation to the Regional
Entity within 48 hours utilizing the 48-hour vegetation reporting notice form provided by your
appropriate Regional Entity."We do not see any reference to a 48-hour reporting notice in lthis
version of the standard. Is this still a requirement? The only reference to reporting is in the
Additional Compliance Information section and references quarterly reporting only.
Response: The SDT thanks you for your comments. The SDT is aware of the 48 hour, voluntary self-report request from NERC for outages where
vegetation may be involved. The SDT also agrees with the general philosophy proposed by WECC that all requirements associated with a Standard
are best served in the Standard. Also, the SDT did examine the general concept of an "investigation" type requirement. However, the SDT did not
pursue this because it did not satisfy the basic rule for requirements as embedded in the Standards Process Manual, “What functional entity shall
do what under what conditions to achieve what reliability objective.” After the fact investigation and reporting, while important to the Compliance
and Enforcement (CMEP) aspect of mandatory and enforceable Standards, does not achieve a reliability objective such that the failure to comply
with the Requirement would jeopardize reliability. The SDT also notes that any useful (other than CMEP) information related to an outage that is
subsequently reported under the NERC voluntary request would generally be available for industry use through TADS. Finally, the SDT did discuss
the issue with NERC staff and did not receive direction that it was necessary, or desirable, to include one or more elements of the voluntary
request in this Standard.
Georgia Transmission Corp.
Yes
Northern Indiana Public
Yes
Consideration of Comments on Draft 5 of FAC-003-2
65
Organization
Yes or No
Question 5 Comment
Service Company
Consideration of Comments on Draft 5 of FAC-003-2
66
Additional Comments from NERC:
In addition to the comments NERC submitted to the five questions on the official comment form, NERC staff has numerous other
comments to make with regard to this Draft 5. Before that, NERC staff first wants to acknowledge the significant effort and talent
that the industry brought to attempt to improve upon Reliability Standard FAC-003-1 – Vegetation Management. This Draft 5 of
FAC-003-2 – Vegetation Management entailed significant industry work towards understanding the issue, compromising on
proposals and attempting to reach consensus utilizing the NERC Standards Development Process. While NERC staff believes this
draft represents some improvements to the existing standard, it does not believe the draft in its totality represents an improvement
to the existing standard. FERC Order 693 approved the existing Vegetation Management Standard and it provided a number of
directives for NERC with regard to further developing the Standard in order to improve it. Such directives and NERC comments
regarding how the directives were addressed included:
•
FERC Directive - Develop compliance audit procedures, using relevant industry experts, which would identify appropriate
inspection cycles based on local factors. The Commission is dissuaded from requiring the ERO to create a backstop
inspection cycle at this time.
NERC Comment – Compliance audit procedures are outside the scope of the SDT and this Draft 5. Although not required by
the Commission, the SDT added an annual inspection cycle to the Standard, with a maximum of 18 months between
inspections. NERC believes this requirement represents an improvement to the existing Standard and does not believe it is
overly burdensome on utilities.
Response: The SDT thanks you for your comments.
•
FERC Directive - Remove the general limitation on lines 200kV and above to include lines that have an impact on reliability.
o Do not reduce facilities included
o Develop an acceptable definition for the applicability of this Reliability Standard that covers facilities that impact
reliability while not unreasonably increasing the burden on transmission owners.
o Evaluate the suggestions proposed by LPPC, APPA and Avista that regional entities should determine which facilities
this standard applies to
NERC Comment – NERC believes Draft 5 partially addresses this issue by increasing applicable facilities to IROL lines under
200kV. NERC staff is also concerned about
Consideration of Comments on Draft 5 of FAC-003-2
67
o The possibility that this very addition could limit a regional entity’s desire to include additional lines.
o The exclusion of facilities inside the fenced area of switching stations, stations and substations. These excluded areas
still pose a vegetation related outage risk and the rationale for excluding them is not compelling enough.
o The separation of IROL (any voltage level) and non-IROL (200 kV and above) Transmission Lines into separate
requirements with different VRFs. NERC believes all Transmission Lines subject to this standard should be under the
same requirement and associated VRFs. IROL lines are relatively few and do not warrant their own requirement. By
having lower VRFs for non-IROL lines, this version of the standard is weaker than the existing standard. These two
requirements should be a single requirement with high VRFs
Response: The SDT thanks you for your comments. In the guidelines provided by NERC to the drafting team, the SDT is dissuaded from writing ‘fill
in the blank’ requirements. In version one, the team directed the RO to designate which critical lines below 200kV should fall under the standard
without defining what critical meant. This is a ‘fill-in-the- blank.’ There is no assurance that this applicability would be applied consistency across
North America. The SDT followed FERCs suggestion to take into account “…the suggestions by Progress Energy, SERC and MISO to limit applicability
to lower voltage lines associated with IROL…” The team went further by including WECC transfer paths. The SDT asserts that the inclusion of both
IROL lines and WECC Transfer paths addresses the comments by LPPC, APPA and Avista along with Progress Energy, SERC and MISO. The NERC Staff
needs to consider that the comments all contend that each inclusion of a below 200kV line is an added burden to the rate payers. Not to give some
direction to the Planning Coordinator would allow a planner to include ALL transmission lines, which would be an unreasonable burden to the rate
payer. We added this language for clarity at the request of stakeholder concerns.
Neither the standard nor its original SAR were intended to cover fenced or discrete locations such as substations, which entail entirely different
issues compared to linear corridors. Often substations are owned by either DPs or GOs, therefore, the TO may not have rights inside the fenced
facility. The requirements in this standard would not be sufficient to include stations and switch yards. Should there be a compelling need for a
vegetation standard for fenced facilities, a new SAR should be introduced.
The SDT asserts that different VRF’s for IROL and non-IROL lines strengthens the reliability of the standard. Vegetation managers that do not know
which lines are IROL or WECC Transfer Paths may be inappropriately limiting resources allocated to vegetation management for an IROL line or a
WECC Transfer Path. A vegetation manager must ensure that the IROL lines and WECC transfer paths are absolutely clear. By correctly identifying
the risk associated with an IROL line and/or a WECC Transfer Path, the standard helps to assure that appropriate resources are applied.
VRF guidelines require an analysis of impact to BES. We did that by considering the relative risk levels to the interconnected transmission system of
an interruption of a non-IROL/non-Transfer Path line versus the interruption of IROL/Transfer Path lines. The fact that the PENALTY might be higher
or lower DOES NOT AFFECT the strength or weakness of the Standard, since even the Medium Risk Factor value in the Base Penalty Matrix in the
Consideration of Comments on Draft 5 of FAC-003-2
68
sanctions guidelines is $350,000 per violation per day. In both R1 and R2 of Version 2 there is zero-tolerance for encroachments, and Version 2
increases the scope to include observed encroachments without Faults, and confirmed vegetation Faults without Sustained Outages which were
not clearly included in Version 1. The 1) distinction by separation of VRFs and 2) inclusion of clear language to inspect for, investigate, correct, and
report to all known reliability threats will strengthen the standard.
•
FERC Directive - Develop a Reliability Standard that defines the minimum clearance needed as an improvement to IEEE 516
which FERC does not believe is appropriately used for purposes of reliability and/or safety.
NERC Comment – Draft 5 makes a change from IEEE 516 and utilizes Gallet equations for industry clearances. While NERC
believes these equations are technically accurate, NERC is concerned about the usefulness of the clearances determined
under this methodology as put forth in this draft. NERC is not aware of any utility which would maintain clearances as
specified in this draft as it has no built in safety factor. NERC is further concerned that utilities could be mandated by courts
of law to reduce existing maintained clearances to values much closer to those determined by the methodology in this draft.
Response: The SDT thanks you for your comments. As with a Transmission Owner's determination of its Clearance 1 distances under version 1 of
the Standard, Requirement 3 of the revised Standard begins with the MVCD distances (just as Clearance 1 began with IEEE-516 distances) and then
requires additional consideration for conductor movement, vegetation growth variables, and the utility's maintenance approach. These are
essentially the same considerations required by version 1 of the existing Standard when developing Clearance 1 distances. Therefore, nothing has
been "lost" in the revised Standard. In fact, the proposed Standard is better from an auditing perspective because the overall logic and rationale
used by the TO in complying with the new Requirement 3 is now subject to an overall test of adequacy, competency and reasonableness. Also,
informal polls conducted by the SDT show that many Transmission Owners are unsuccessful in utilizing Clearance 1 as a tool, because it is easily
challenged by landowners as being an arbitrary fill-in-the-blank value set by the Transmission Owner. Further, if the Transmission Owner would cut
only to Clearance 1 instead of to the full extent of its legal rights, courts could rule against the Transmission Owner for failing to exercise its full
legal rights. Thus, in the revised Standard, the Transmission Owner has neither gained nor lost any tool or advantage in dealing with landowners,
but the SDT asserts that the bar has been raised with regard to the adequacy of the Transmission Owner’s overall vegetation management
program.
Consideration of Comments on Draft 5 of FAC-003-2
69
•
FERC Directive - Define rights-of-way to encompass the required clearance areas instead of the corresponding legal rights,
and the standards should not require clearing the entire right-of-way when the required clearance for an existing line does
not take up the entire right-of-way.
NERC Comment – NERC staff believes this directive was met and is addressed in question 1 of the comment form.
Response: The SDT thanks you for your comments.
•
FERC Directive – NERC should address the proposed modifications through its Reliability Standards development process.
NERC Comment – NERC staff believes this directive was met in preparing this draft standard.
Response: The SDT thanks you for your comments.
•
FERC Directive - Collect outage data for transmission outages, analyze it, and use the results of this analysis and information
in the development of the Reliability Standard.
NERC Comment – NERC staff believes more work needs to be done in this area. NERC staff believes the drafting team should
consider modifying the Periodic Data Submittal to include if outages occur on Federal land.
Response: The SDT thanks you for your comments. After discussion with NERC staff, NERC has agreed to address this issue outside the work of the
SDT. The SDT recommends that NERC staff consider adding a field to the TADS data to capture vegetation outages on applicable lines on federal
lands.
Other Draft 5 Issues
•
Removal of a formal transmission vegetation management program, of Clearance 1 and of a documented vegetation
management plan.
Consideration of Comments on Draft 5 of FAC-003-2
70
NERC Comment – NERC does not support the removal of these items. NERC does not believe these changes represent an
improvement to the standard and does not believe this existing requirement is overly burdensome to utilities. NERC does
not understand why industry would not be willing to be held accountable to their vegetation management plans. NERC is
concerned that the removal of these items could make it difficult for utilities to obtain permissions needed to maintain
clearances between inspection cycles which are prudent for reliability and safety due to intervener or landowners exercising
their rights and then pointing to this new standard as a the basis for smaller clearances. . Requirement 3 in this draft needs
to include a documented plan and to clearly identify the specifics to be included in the plan and provide clarity of
expectations. The SDT may not support such specifics as not being consistent with results-based standards development but
NERC staff believes otherwise.
Response: The SDT thanks you for your comments. The existing series of items in Requirement R3 along with R3.2 are collectively with the balance
of the standard equivalent to the term TVMP. These combined items in R3 are the defense in depth approach that require the TO to maintain
vegetation so that it does not enter into the MVCD before the next planned vegetation work, thus accomplishing the equivalent of a C1 without a
fill-in-the-blank issue.
•
Objectives: A qualifier in the standard Objective that it should apply to preventing the risk of vegetation related outages that
could lead to cascading outages.
NERC Comment – This qualifier limits the purpose of the standard, which should be to prevent vegetation related outages,
not cascading outages. The more outages there are, the less the overall system reliability. An outage does not necessarily
have to lead to a cascading outage to be significant and represent a reasonable risk to the BES. References to cascading
outages should be removed.
Consideration of Comments on Draft 5 of FAC-003-2
71
Response: The SDT thanks you for your comments. The SDT has thoughtfully considered every aspect of this version of the Standard to ensure that
the pieces are consistent, aligned, and support each other. The SDT added the phrase “with Cascading” not to limit the Standard, but rather to
recognize that the 200 kV bright-line for applicability (which is not in question) is founded on the very notion that the 200 kV serves as a proxy for
"The Big Three": Cascading, Separation, and Instability. The SDT considered adding all of these conditions to the Purpose statement. However,
given the focus of this Standard is on vegetation, and vegetation was deemed to be related to Cascading (i.e. 2003 Blackout report), rather than the
other two undesirable system conditions, it seemed more logical and consistent to include the likely outcome of an unmanaged vegetation
condition on a Transmission Owner's system. If NERC Staff has evidence that other two are likely related to vegetation, it has not yet been provided
to the SDT.
Unlike other types of outages on lines (such as those caused by failed insulators, broken cross-arms, rotten poles and lightning flashover),
vegetation outages uniquely affect lines when they are heavily loaded and thus susceptible to a cascading event.
•
Background: This section excludes vegetations fall-ins and blow-ins from outside the ROW on the basis that they are not
preventable.
NERC Comment – Many fall-ins and blow-ins from outside the ROW are preventable. Trees outside the ROW must be
managed adequately to prevent outages on the BES. The work to remove and/or prune trees outside the ROW may be more
difficult and costly than such work inside the ROW, but that is not sufficient reason to exclude this work. In addition, utilities
wishing to perform such work might be prevented from doing so by regulatory bodies based upon the lack of a specific
requirement in this standard.
Response: The SDT thanks you for your comments and has reworded the Background by removing the term non-preventable.
•
Requirement 1 & 2: These requirements discuss preventing encroachments into the MVCD of an applicable line that is
operating within its Rating.
NERC Comments –NERC staff would like confirmation that “Rating” is intended to include all published ratings issued by the
facility owner, such as Normal, Emergency, etc.
Consideration of Comments on Draft 5 of FAC-003-2
72
Response: The SDT thanks you for your response. The glossary term “Rating” is adequate to address the issues you raise.
•
Requirement 4: R4 states that “Each Transmission Owner, without any intentional time delay, shall notify…”
NERC Comments: The previous version of the standard included a time limit of 15 minutes once communications became
available. This should be reinstated.
Response: The SDT thanks you for your response. The SDT is not aware any posting with a 15 minute rule included.
•
Requirement 7: R7 sets the requirement for each Transmission Owner to complete 100 percent of its annual vegetation work
plan.
NERC Comments – NERC is concerned that the draft doesn’t have a requirement for a Transmission Owner to have a
documented annual plan making Requirement 7 unenforceable. In addition, Requirement 7 has a number of other qualifiers
that would seem to allow manipulation of the annual plan to ensure compliance.
Response: The SDT thanks you for your comments. The SDT asserts that a fundamental precept of results-based standards is that having a
requirement to complete any particularly activity also presupposes that the elements required to complete the activity are included in the
requirement, even if unstated.
•
Draft 5 document quality
NERC Comments – this draft has some typographical errors which need to be fixed. For example, on page 28, reference to
use of Table 5 versus Table 7 based on knowledge of maximum transient over-voltage factor is reversed. These edits could
probably be handled through a recirculation ballet.
Response: The SDT thanks you for your comments. We agree with the typo you found and we have changed the language in the draft standard.
Consideration of Comments on Draft 5 of FAC-003-2
73
•
Previously raised NERC issues
NERC Comments – NERC staff posted several comments on the Draft 4 version of this standard in July 2010. NERC believes
most of the concerns it raised in those comments are not addressed in Draft 5 and continue to be a concern for NERC.
Response: The SDT thanks you for your comments; however there are not enough specifics for the SDT to respond.
•
General compliance and audit issues
NERC Comments –
o The whole “sustained outage” concept in R1 (for fall ins and blow ins) is unworkable from an enforcement
perspective.
o The difference between a violation and a non-violation in Draft 5 is whether the registered entity was fortunate with
regard to an encroachment. This part should be rewritten to say that any tree contact is a violation. VRFs and VSLs
could then be used to address whether the violation was minor or serious.
o There could be a lot of litigation over whether “circumstances” were really “beyond the control” of the TO. NERC had
previously objected to the implementation of a force majeure clause in the standard. If an entity failed to carry out
its annual plan, that should be treated as a violation, and any excuses for failing to do so or for changing the plan midyear all go to whether the penalty should be $0 or substantial.
o For the evidence retention period, the entity really should retain evidence of compliance until the next compliance
audit. Since some TOs may be on a 6 year audit schedule, the 3 year retention period is not sufficient.
Response: The SDT thanks you for your comments.
•
The SDT does not understand your comment. The violations under the existing standards are largely due to sustained outages.
•
Version 2 has a violation for every known and confirmed encroachment. The Penalty for those encroachments that do no cause Faults is up
to $30,000 per violation per day
•
The SDT thanks you for your comments. The SDT believes this language is appropriate for this standard due to the many factors related to
vegetation that are truly outside the TO’s control. Unlike the vast majority of other NERC standards, implementation of FAC-003 is not under
Consideration of Comments on Draft 5 of FAC-003-2
74
the absolute control of the utilities. These influences range from landowner and agency obstacles to weather events, and as such the SDT
believes the force majeure provisions should be applicable. The recognition of this provision is also supported by 90% of the industry. An
attempt at similar language is contained in version 1 but it is ambiguous and lacks clarity. This language adds clarity and reduces the
opportunity for misapplication. Further, TO’s must have supporting evidence for claims that situations are “beyond their control”.
•
The SDT thanks you for your comments, and will use the NERC approved retention times.
End of Report
Consideration of Comments on Draft 5 of FAC-003-2
75
FAC-003-2 — Transmission Vegetation Management
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. SC approved SAR for initial posting (January 11, 2007).
2. SAR posted for comment (January 15–February 14, 2007).
3. SAR posted for comment (April 10–May 9, 2007).
4. SC authorized moving the SAR forward to standard development (June 27, 2007).
5. First draft of proposed standard posted (October 27, 2008-November 25, 2008)).
6. Second draft of revised standard posted (September 10, 20-October 24, 2009).
7. Third draft of revised standard posted (March 1, 2010-March 31, 2010).
8. Fourth draft of revised standard posted (June 17, 2010-July 17, 2010).
9. Fifth draft of revised standard posted (February 18, 2011-February 28, 2011)
10. Sixth draft of revised standard posted (September xx - 2011)
Proposed Action Plan and Description of Current Draft
This is the fourth posting of the proposed revisions to the standard in accordance with ResultsBased Criteria and the sixth draft overall.
Future Development Plan
Anticipated Actions
Recirculation ballot of standards.
Receive BOT approval
Draft 6: August 14, 2011
Anticipated Date
September 2011
November 2011
1
FAC-003-2 — Transmission Vegetation Management
Effective Dates
This standard becomes effective on the first calendar day of the first calendar quarter one year
after the date of the order approving the standard from applicable regulatory authorities where
such explicit approval is required. Where no regulatory approval is required, the standard
becomes effective on the first calendar day of the first calendar quarter one year after Board of
Trustees adoption.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of
an Interconnection Reliability Operating Limit (IROL) or designated by the Western
Electricity Coordinating Council (WECC) as an element of a Major WECC Transfer
Path, becomes subject to this standard the latter of: 1) 12 months after the date the
Planning Coordinator or WECC initially designates the line as being an element of an
IROL or an element of a Major WECC Transfer Path, or 2) January 1 of the planning
year when the line is forecast to become an element of an IROL or an element of a Major
WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element
of an IROL or a Major WECC Transfer Path which has a specified date for the removal
of such designation will no longer be subject to this standard effective on that specified
date.
3. A line operated at 200 kV or above, currently subject to this standard which is a
designated element of an IROL or a Major WECC Transfer Path and which has a
specified date for the removal of such designation will be subject to Requirement R2 and
no longer be subject to Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an
asset owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date of the line if at the time of acquisition the
line is designated by the Planning Coordinator as an element of an IROL or by WECC as
an element of a Major WECC Transfer Path.
Draft 6: August 14, 2011
2
FAC-003-2 — Transmission Vegetation Management
Version History
Version
Date
1
TBA
Action
1. Added “Standard Development
Roadmap.”
Change Tracking
01/20/06
2. Changed “60” to “Sixty” in section
A, 5.2.
3. Added “Proposed Effective Date:
April 7, 2006” to footer.
4. Added “Draft 3: November 17,
2005” to footer.
1
2
April 4, 2007
Draft 6: August 14, 2011
Regulatory Approval — Effective Date
New
3
FAC-003-2 — Transmission Vegetation Management
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Right-of-Way (ROW)
The current glossary definition of this NERC
The corridor of land under a transmission line(s)
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in Paragraph 734 of FERC Order 693.
corridor is established by engineering or
construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in
effect when the line was built. The ROW width in no case exceeds the Transmission Owner’s
legal rights but may be less based on the aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the Transmission Owner’s control
that are likely to pose a hazard to the line(s) prior to
the next planned maintenance or inspection. This
may be combined with a general line inspection.
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
Draft 6: August 14, 2011
4
FAC-003-2 — Transmission Vegetation Management
When this standard has received ballot approval, the text boxes will be moved to the Guideline
and Technical Basis Section.
A. Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-2
3. Purpose:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1.
Functional Entities:
4.1.1 Transmission Owners
4.2.
Facilities: Defined below (referred to as “applicable lines”), including but not
limited to those that cross lands owned by federal 1, state, provincial, public,
private, or tribal entities:
Rationale: The areas excluded in
4.2.4 were excluded based on comments
4.2.1. Each overhead transmission line
from industry for reasons summarized as
operated at 200kV or higher.
4.2.2. Each overhead transmission line
operated below 200kV identified as an
element of an IROL under NERC
Standard FAC-014 by the Planning
Coordinator.
4.2.3. Each overhead transmission line
operated below 200 kV identified as an
element of a Major WECC Transfer
Path in the Bulk Electric System by
WECC.
follows: 1) There is a very low risk from
vegetation in this area. Based on an
informal survey, no TOs reported such
an event. 2) Substations, switchyards,
and stations have many inspection and
maintenance activities that are necessary
for reliability. Those existing process
manage the threat. As such, the formal
steps in this standard are not well suited
for this environment. 3) NERC has a
project in place to address at a later date
the applicability of this standard to
Generation Owners. 4) Specifically
addressing the areas where the standard
does and does not apply makes the
standard clearer.
4.2.4. Each overhead transmission line
identified above (4.2.1 through 4.2.3)
located outside the fenced area of the
switchyard, station or substation and any portion of the span of the
transmission line that is crossing the substation fence.
1
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
Draft 6: August 14, 2011
5
FAC-003-2 — Transmission Vegetation Management
Enforcement:
The Requirements within a Reliability Standard govern and will be enforced. The Requirements
within a Reliability Standard define what an entity must do to be compliant and binds an entity to
certain obligations of performance under Section 215 of the Federal Power Act. Compliance
will in all cases be measured by determining whether a party met or failed to meet the Reliability
Standard Requirement given the specific facts and circumstances of its use, ownership or
operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining satisfactory
performance nor to limit how an entity may demonstrate compliance if valid alternatives to
demonstrating compliance are available in a specific case. A Reliability Standard may be
enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements
under NERC’s Reliability Standards or to modify the Requirements in any existing NERC
Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”
5. Background:
This standard uses three types of requirements to provide layers of protection to prevent
vegetation related outages that could lead to Cascading:
a)
Performance-based defines a particular reliability objective or outcome to be
achieved. In its simplest form, a results-based requirement has four components:
who, under what conditions (if any), shall perform what action, to achieve what
particular bulk power system performance result or outcome?
b)
Risk-based preventive requirements to reduce the risks of failure to acceptable
tolerance levels. A risk-based reliability requirement should be framed as: who,
under what conditions (if any), shall perform what action, to achieve what
particular result or outcome that reduces a stated risk to the reliability of the bulk
power system?
c)
Competency-based defines a minimum set of capabilities an entity needs to
have to demonstrate it is able to perform its designated reliability functions. A
competency-based reliability requirement should be framed as: who, under what
Draft 6: August 14, 2011
6
FAC-003-2 — Transmission Vegetation Management
conditions (if any), shall have what capability, to achieve what particular result
or outcome to perform an action to achieve a result or outcome or to reduce a
risk to the reliability of the bulk power system?
The defense-in-depth strategy for reliability standards development recognizes that each
requirement in a NERC reliability standard has a role in preventing system failures, and
that these roles are complementary and reinforcing. Reliability standards should not be
viewed as a body of unrelated requirements, but rather should be viewed as part of a
portfolio of requirements designed to achieve an overall defense-in-depth strategy and
comport with the quality objectives of a reliability standard.
This standard uses a defense-in-depth approach to improve the reliability of the electric
Transmission system by:
•
Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash-over clearance (R1 and R2);
•
Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over
conditions including consideration of 1) conductor dynamics and 2) the
interrelationships between vegetation growth rates, control methods and the
inspection frequency (R3);
•
Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash-over at any moment (R4);
•
Requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains such as legal injunctions (R5);
•
Requiring inspections of vegetation conditions to be performed annually (R6);
and
•
Requiring that the annual work needed to prevent flash-over is completed (R7).
For this standard, the requirements have been developed as follows:
•
Performance-based: Requirements 1 and 2
•
Competency-based: Requirement 3
•
Risk-based: Requirements 4, 5, 6 and 7
R3 serves as the first line of defense by ensuring that entities understand the problem they
are trying to manage and have fully developed strategies and plans to manage the
problem. R1, R2, and R7 serve as the second line of defense by requiring that entities
carry out their plans and manage vegetation. R6, which requires inspections, may be
either a part of the first line of defense (as input into the strategies and plans) or as a third
line of defense (as a check of the first and second lines of defense). R4 serves as the final
line of defense, as it addresses cases in which all the other lines of defense have failed.
Draft 6: August 14, 2011
7
FAC-003-2 — Transmission Vegetation Management
Major outages and operational problems have resulted from interference between
overgrown vegetation and transmission lines located on many types of lands and
ownership situations. Adherence to the standard requirements for applicable lines on any
kind of land or easement, whether they are Federal Lands, state or provincial lands,
public or private lands, franchises, easements or lands owned in fee, will reduce and
manage this risk. For the purpose of the standard the term “public lands” includes
municipal lands, village lands, city lands, and a host of other governmental entities.
This standard addresses vegetation management along applicable overhead lines and does
not apply to underground lines, submarine lines or to line sections inside an electric
station boundary.
This standard focuses on transmission lines to prevent those vegetation related outages
that could lead to Cascading. It is not intended to prevent customer outages due to tree
contact with lower voltage distribution system lines. For example, localized customer
service might be disrupted if vegetation were to make contact with a 69kV transmission
line supplying power to a 12kV distribution station. However, this standard is not written
to address such isolated situations which have little impact on the overall electric
transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses an
increased outage risk, especially when numerous transmission lines are operating at or
near their Rating. This can present a significant risk of consecutive line failures when
lines are experiencing large sags thereby leading to Cascading. Once the first line fails
the shift of the current to the other lines and/or the increasing system loads will lead to
the second and subsequent line failures as contact to the vegetation under those lines
occurs. Conversely, most other outage causes (such as trees falling into lines, lightning,
animals, motor vehicles, etc.) are not an interrelated function of the shift of currents or
the increasing system loading. These events are not any more likely to occur during
heavy system loads than any other time. There is no cause-effect relationship which
creates the probability of simultaneous occurrence of other such events. Therefore these
types of events are highly unlikely to cause large-scale grid failures. Thus, this standard
places the highest priority on the management of vegetation to prevent vegetation growins.
Draft 6: August 14, 2011
8
FAC-003-2 — Transmission Vegetation Management
B. Requirements and Measures
R1. Each Transmission Owner shall
manage vegetation to prevent
encroachments into the MVCD of its
applicable line(s) which are either an
element of an IROL, or an element of
a Major WECC Transfer Path;
operating within its Rating and all
Rated Electrical Operating Conditions
of the types shown below 2 [Violation
Risk Factor: High] [Time Horizon:
Real-time]:
Rationale for R1 and R2:
Lines with the highest significance to reliability
are covered in R1; all other lines are covered in
R2.
Ra tio n a le fo r th e typ e s o f fa ilu re to
m a n a g e ve g e ta tio n wh ic h a re lis te d in
o rd e r o f in c re a s in g de g re e s o f s e ve rity in
n o n -c o m p lia n t p e rfo rm a n c e a s it re la te s
to a fa ilu re o f a Tra ns m is s io n Own e r's
ve g e ta tio n m a in te n a n c e p ro g ra m :
1.
An encroachment into the
MVCD as shown in FAC-003Table 2, observed in Real-time,
absent a Sustained Outage 3,
1. This management failure is found by routine
inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in
an otherwise sound program.
2.
An encroachment due to a fall-in
from inside the ROW that caused
a vegetation-related Sustained
Outage 4,
2. This management failure occurs when the
height and location of a side tree within the ROW
is not adequately addressed by the program.
3.
An encroachment due to the
blowing together of applicable
lines and vegetation located
inside the ROW that caused a
vegetation-related Sustained
Outage4,
3. This management failure occurs when side
growth is not adequately addressed and may be
indicative of an unsound program.
4.
An encroachment due to
vegetation growth into the
MVCD that caused a vegetationrelated Sustained Outage4.
4. This management failure is usually indicative
of a program that is not addressing the most
fundamental dynamic of vegetation management,
(i.e. a grow-in under the line). If this type of
failure is pervasive on multiple lines, it provides a
mechanism for a Cascade.
2
This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to
this reliability standard, including natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, wind
shear, fresh gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice
storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree, or
installation, removal, or digging of vegetation. Nothing in this footnote should be construed to limit the
Transmission Owner’s right to exercise its full legal rights on the ROW.
3
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation encroachment within the
MVCD has occurred from vegetation within the ROW, this shall be considered the equivalent of a Real-time
observation.
4
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage
regardless of the actual number of outages within a 24-hour period.
Draft 6: August 14, 2011
9
FAC-003-2 — Transmission Vegetation Management
M1. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained Outages
associated with encroachment types 2 through 4 above, or records confirming no Realtime observations of any MVCD encroachments. (R1)
R2. Each Transmission Owner shall manage vegetation to prevent encroachments into the
MVCD of its applicable line(s) which are not either an element of an IROL, or an
element of a Major WECC Transfer Path; operating within its Rating and all Rated
Electrical Operating Conditions of the types shown below2 [Violation Risk Factor:
Medium] [Time Horizon: Real-time]:
1. An encroachment into the MVCD, observed in Real-time as shown in FAC-003Table 2, absent a Sustained Outage3,
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage4,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage4,
4. An encroachment due to vegetation growth into the MVCD that caused a
vegetation-related Sustained Outage4
M2. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R2. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained Outages
associated with encroachment types 2 through 4 above, or records confirming no Realtime observations of any MVCD encroachments. (R2)
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10
FAC-003-2 — Transmission Vegetation Management
R3. Each Transmission Owner shall have
documented maintenance strategies or
procedures or processes or specifications
it uses to prevent the encroachment of
vegetation into the MVCD of its
applicable lines that accounts for the
following:
3.1 Movement of applicable line
conductors under their Rating and
all Rated Electrical Operating
Conditions;
Rationale
The documentation provides a basis for
evaluating the competency of the
Transmission Owner’s vegetation program.
There may be many acceptable approaches
to maintain clearances. Any approach must
demonstrate that the Transmission Owner
avoids vegetation-to-wire conflicts under all
Ratings and all Rated Electrical Operating
Conditions. See Figure 1 for an illustration
of possible conductor locations.
3.2 Inter-relationships between
vegetation growth rates, vegetation control methods, and
inspection frequency.
[Violation Risk Factor: Lower] [Time Horizon: Long Term
Planning]:
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the Transmission Owner can prevent encroachment into the MVCD
considering the factors identified in the requirement. (R3)
R4. Each Transmission Owner, without any
Rationale
intentional time delay, shall notify the
This is to ensure expeditious communication
control center holding switching
between the Transmission Owner and the
authority for the associated applicable
control center when a critical situation is
line when the Transmission Owner has
confirmed.
confirmed the existence of a vegetation
condition that is likely to cause a Fault at
any moment [Violation Risk Factor: Medium] [Time Horizon: Real-time].
M4. Each Transmission Owner that has a confirmed vegetation condition likely to cause a
Fault at any moment will have evidence that it notified the control center holding
switching authority for the associated transmission line without any intentional time
delay. Examples of evidence may include control center logs, voice recordings,
switching orders, clearance orders and subsequent work orders. (R4)
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11
FAC-003-2 — Transmission Vegetation Management
R5. When a Transmission Owner is
constrained from performing vegetation
work on an applicable line operating
within its Rating and all Rated Electrical
Operating Conditions, and the constraint
may lead to a vegetation encroachment
into the MVCD prior to the
implementation of the next annual work
plan, then the Transmission Owner shall
take corrective action to ensure continued
vegetation management to prevent
encroachments [Violation Risk Factor:
Medium] [Time Horizon: Operations
Planning].
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
Transmission Owner from performing
planned vegetation maintenance work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the Transmission Owner to put interim
measures in place, rather than do nothing.
The corrective action process is not
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
M5. Each Transmission Owner has evidence of the corrective action taken for each
constraint where an applicable transmission line was put at potential risk. Examples of
acceptable forms of evidence may include initially-planned work orders, documentation
of constraints from landowners, court orders, inspection records of increased
monitoring, documentation of the de-rating of lines, revised work orders, invoices, or
evidence that the line was de-energized. (R5)
R6. Each Transmission Owner shall perform a
Vegetation Inspection of 100% of its
applicable transmission lines (measured in
units of choice - circuit, pole line, line
miles or kilometers, etc.) at least once per
calendar year and with no more than 18
calendar months between inspections on
the same ROW 5 [Violation Risk Factor:
Medium] [Time Horizon: Operations
Planning].
Rationale
Inspections are used by Transmission
Owners to assess the condition of the entire
ROW. The information from the assessment
can be used to determine risk, determine
future work and evaluate recentlycompleted work. This requirement sets a
minimum Vegetation Inspection frequency
of once per calendar year but with no more
than 18 months between inspections on the
same ROW. Based upon average growth
rates across North America and on common
utility practice, this minimum frequency is
reasonable. Transmission Owners should
consider local and environmental factors
that could warrant more frequent
inspections.
5
When the Transmission Owner is prevented from performing a Vegetation Inspection within the timeframe in R6
due to a natural disaster, the TO is granted a time extension that is equivalent to the duration of the time the TO was
prevented from performing the Vegetation Inspection.
Draft 6: August 14, 2011
12
FAC-003-2 — Transmission Vegetation Management
M6. Each Transmission Owner has evidence that it conducted Vegetation Inspections of the
transmission line ROW for all applicable lines at least once per calendar year but with
no more than 18 calendar months between inspections on the same ROW. Examples of
acceptable forms of evidence may include completed and dated work orders, dated
invoices, or dated inspection records. (R6)
R7. Each Transmission Owner shall complete
100% of its annual vegetation work plan of
Rationale
applicable lines to ensure no vegetation
This requirement sets the expectation
encroachments occur within the MVCD.
that the work identified in the annual
Modifications to the work plan in response
work plan will be completed as planned.
to changing conditions or to findings from
It allows modifications to the planned
vegetation inspections may be made
work for changing conditions, taking into
(provided they do not allow encroachment
consideration anticipated growth of
of vegetation into the MVCD) and must be
vegetation and all other environmental
documented. The percent completed
factors, provided that those modifications
calculation is based on the number of units
do not put the transmission system at risk
actually completed divided by the number
of a vegetation encroachment.
of units in the final amended plan
(measured in units of choice - circuit, pole
line, line miles or kilometers, etc.) Examples of reasons for modification to annual plan
may include [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]:
•
Change in expected growth rate/ environmental factors
•
Circumstances that are beyond the control of a Transmission Owner 6
•
Rescheduling work between growing seasons
•
Crew or contractor availability/ Mutual assistance agreements
•
Identified unanticipated high priority work
•
Weather conditions/Accessibility
•
Permitting delays
•
Land ownership changes/Change in land use by the landowner
•
Emerging technologies
M7. Each Transmission Owner has evidence that it completed its annual vegetation work
plan for its applicable lines. Examples of acceptable forms of evidence may include a
copy of the completed annual work plan (as finally modified), dated work orders, dated
invoices, or dated inspection records. (R7)
6
Circumstances that are beyond the control of a Transmission Owner include but are not limited to natural disasters
such as earthquakes, fires, tornados, hurricanes, landslides, ice storms, floods, or major storms as defined either by
the TO or an applicable regulatory body.
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13
FAC-003-2 — Transmission Vegetation Management
C. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
1.2 Regional Entity Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The Transmission Owner retains data or evidence to show compliance with
Requirements R1, R2, R3, R5, R6 and R7, Measures M1, M2, M3, M5, M6 and
M7 for three calendar years unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
The Transmission Owner retains data or evidence to show compliance with
Requirement R4, Measure M4 for most recent 12 months of operator logs or most
recent 3 months of voice recordings or transcripts of voice recordings, unless
directed by its Compliance Enforcement Authority to retain specific evidence for
a longer period of time as part of an investigation.
If a Transmission Owner is found non-compliant, it shall keep information related
to the non-compliance until found compliant or for the time period specified
above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3 Compliance Monitoring and Enforcement Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaint
Periodic Data Submittal
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14
FAC-003-2 — Transmission Vegetation Management
1.4 Additional Compliance Information
Periodic Data Submittal: The Transmission Owner will submit a quarterly report
to its Regional Entity, or the Regional Entity’s designee, identifying all Sustained
Outages of applicable lines operated within their Rating and all Rated Electrical
Operating Conditions as determined by the Transmission Owner to have been
caused by vegetation, except as excluded in footnote 2, and including as a
minimum the following:
o The name of the circuit(s), the date, time and duration of the outage;
the voltage of the circuit; a description of the cause of the outage; the
category associated with the Sustained Outage; other pertinent
comments; and any countermeasures taken by the Transmission
Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, that are identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by
vegetation and applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, blowing together from within
the ROW.
o Category 4B — Blowing together: Sustained Outages caused by
vegetation and applicable lines, but are not identified as an element of
an IROL or Major WECC Transfer Path, blowing together from within
the ROW.
The Regional Entity will report the outage information provided by Transmission
Owners, as per the above, quarterly to NERC, as well as any actions taken by the
Regional Entity as a result of any of the reported Sustained Outages.
Draft 6: August 14, 2011
15
FAC-003-2 — Transmission Vegetation Management
Table of Compliance Elements
R#
R1
R2
R3
Time
Horizon
Real-time
Real-time
Long-Term
Planning
VRF
High
Medium
Lower
Draft 6: August 14, 2011
Violation Severity Level
Lower
Moderate
High
Severe
The Transmission Owner
failed to manage
vegetation in a manner
such that the Transmission
Owner had an
encroachment into the
MVCD observed in Realtime, absent a Sustained
Outage.
The Transmission Owner
failed to manage vegetation in
a manner such that the
Transmission Owner had an
encroachment into the MVCD
due to a fall-in from inside the
ROW that caused a
vegetation-related Sustained
Outage.
The Transmission Owner failed
to manage vegetation in a
manner such that the
Transmission Owner had an
encroachment into the MVCD
due to blowing together of
applicable lines and vegetation
located inside the ROW that
caused a vegetation-related
Sustained Outage.
The Transmission Owner failed
to manage vegetation in a
manner such that the
Transmission Owner had an
encroachment into the MVCD
due to a grow-in that caused a
vegetation-related Sustained
Outage.
The Transmission Owner
failed to manage
vegetation in a manner
such that the Transmission
Owner had an
encroachment into the
MVCD observed in Realtime, absent a Sustained
Outage.
The Transmission Owner
failed to manage vegetation in
a manner such that the
Transmission Owner had an
encroachment into the MVCD
due to a fall-in from inside the
ROW that caused a
vegetation-related Sustained
Outage.
The Transmission Owner failed
to manage vegetation in a
manner such that the
Transmission Owner had an
encroachment into the MVCD
due to blowing together of
applicable lines and vegetation
located inside the ROW that
caused a vegetation-related
Sustained Outage.
The Transmission Owner failed
to manage vegetation in a
manner such that the
Transmission Owner had an
encroachment into the MVCD
due to a grow-in that caused a
vegetation-related Sustained
Outage.
The Transmission Owner has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
inter-relationships between
vegetation growth rates,
vegetation control methods,
and inspection frequency, for
the Transmission Owner’s
The Transmission Owner has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
movement of transmission line
conductors under their Rating
and all Rated Electrical
Operating Conditions, for the
Transmission Owner’s
The Transmission Owner does
not have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent
the encroachment of vegetation
into the MVCD, for the
Transmission Owner’s
applicable lines.
16
FAC-003-2 — Transmission Vegetation Management
applicable lines. (Requirement
R3, Part 3.2)
R4
R5
R6
R7
Real-time
Operations
Planning
Operations
Planning
Operations
Planning
applicable lines. Requirement
R3, Part 3.1)
The Transmission Owner
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
applicable line, but there was
intentional delay in that
notification.
Medium
The Transmission Owner
experienced a confirmed
vegetation threat and did not
notify the control center
holding switching authority for
that applicable line.
The Transmission Owner did
not take corrective action when
it was constrained from
performing planned vegetation
work where an applicable line
was put at potential risk.
Medium
Medium
The Transmission Owner
failed to inspect 5% or less
of its applicable lines
(measured in units of
choice - circuit, pole line,
line miles or kilometers,
etc.)
The Transmission Owner
failed to inspect more than 5%
up to and including 10% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The Transmission Owner failed
to inspect more than 10% up to
and including 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The Transmission Owner failed
to inspect more than 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
Medium
The Transmission Owner
failed to complete 5% or
less of its annual
vegetation work plan for
its applicable lines (as
finally modified).
The Transmission Owner
failed to complete more than
5% and up to and including
10% of its annual vegetation
work plan for its applicable
lines (as finally modified).
The Transmission Owner failed
to complete more than 10% and
up to and including 15% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The Transmission Owner failed
to complete more than 15% of
its annual vegetation work plan
for its applicable lines (as
finally modified).
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17
FAC-003-2 — Transmission Vegetation Management
D. Re g io n a l Diffe re n c e s
None.
E. In te rp re ta tio n s
None.
F. As s o c ia te d Do c u m e nts
Guideline and Technical Basis (attached).
Draft 6: August 14, 2011
18
FAC-003-2 — Transmission Vegetation Management
Guideline and Technical Basis
Effective dates:
The first two sentences of the Effective Dates section is standard language used in most NERC standards to cover the general effective
date and is sufficient to cover the vast majority of situations. Five special cases are needed to cover effective dates for individual lines
which undergo transitions after the general effective date. These special cases cover the effective dates for those lines which are
initially becoming subject to the standard, those lines which are changing their applicability within the standard, and those lines which
are changing in a manner that removes their applicability to the standard.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to become elements of an IROL or Major
WECC Transfer Path in a future Planning Year (PY). For example, studies by the Planning Coordinator in 2011 may identify a line to
have that designation beginning in PY 2021, ten years after the planning study is performed. It is not intended for the Standard to be
immediately applicable to, or in effect for, that line until that future PY begins. The effective date provision for such lines ensures that
the line will become subject to the standard on January 1 of the PY specified with an allowance of at least 12 months for the
Transmission Owner to make the necessary preparations to achieve compliance on that line. The table below has some explanatory
examples of the application.
Date that Planning
Study is
completed
05/15/2011
05/15/2011
05/15/2011
05/15/2011
PY the line
will become
an IROL
element
2012
2013
2014
2021
Date 1
05/15/2012
05/15/2012
05/15/2012
05/15/2012
Date 2
01/01/2012
01/01/2013
01/01/2014
01/01/2021
Effective Date
The latter of Date 1
or Date 2
05/15/2012
01/01/2013
01/01/2014
01/01/2021
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or Major WECC Transfer Path may be
removed from that designation due to system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network.
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FAC-003-2 — Transmission Vegetation Management
Case 3 is needed because a line operating at 200 kV or above that once was designated as an element of an IROL or Major WECC
Transfer Path may be removed from that designation due to system improvements, changes in generation, changes in loads or changes
in studies and analysis of the network. Such changes result in the need to apply R1 to that line until that date is reached and then to
apply R2 to that line thereafter.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be acquired by a Transmission Owner from a
third party such as a Distribution Provider or other end-user who was using the line solely for local distribution purposes, but the
Transmission Owner, upon acquisition, is incorporating the line into the interconnected electrical energy transmission network which
will thereafter make the line subject to the standard.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by a Transmission Owner from a third party
such as a Distribution Provider or other end-user who was using the line solely for local distribution purposes, but the Transmission
owner, upon acquisition, is incorporating the line into the interconnected electrical energy transmission network. In this special case
the line upon acquisition was designated as an element of an Interconnection Reliability Operating Limit (IROL) or an element of a
Major WECC Transfer Path.
Defined Terms:
Explanation for revising the definition of ROW:
The current NERC glossary definition of Right of Way has been modified to address the matter set forth in Paragraph 734 of FERC
Order 693. The Order pointed out that Transmission Owners may in some cases own more property or rights than are needed to reliably
operate transmission lines. This modified definition represents a slight but significant departure from the strict legal definition of “right
of way” in that this definition is based on engineering and construction considerations that establish the width of a corridor from a
technical basis. The pre-2007 maintenance records are included in the revised definition to allow the use of such vegetation widths if
there were no engineering or construction standards that referenced the width of right of way to be maintained for vegetation on a
particular line but the evidence exists in maintenance records for a width that was in fact maintained prior to this standard becoming
mandatory. Such widths may be the only information available for lines that had limited or no vegetation easement rights and were
typically maintained primarily to ensure public safety. This standard does not require additional easement rights to be purchased to
satisfy a minimum right of way width that did not exist prior to this standard becoming mandatory.
Draft 6: August 14, 2011
20
FAC-003-2 — Transmission Vegetation Management
Explanation for revising the definition of Vegetation Inspections:
The current glossary definition of this NERC term is being modified to allow both maintenance inspections and vegetation inspections
to be performed concurrently. This allows potential efficiencies, especially for those lines with minimal vegetation and/or slow
vegetation growth rates.
Explanation of the definition of the MVCD:
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a method of calculating a flash over
distance that has been used in the design of high voltage transmission lines. Keeping vegetation away from high voltage conductors by
this distance will prevent voltage flash-over to the vegetation. See the explanatory text below for Requirement R3 and associated Figure
1. Table 2 below provides MVCD values for various voltages and altitudes. Details of the equations and an example calculation are
provided in Appendix 1 of the Technical Reference Document.
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be achieved is the management of vegetation
such that there are no vegetation encroachments within a minimum distance of transmission lines. Content-wise, R1 and R2 are the
same requirements; however, they apply to different Facilities. Both R1 and R2 require each Transmission Owner to manage vegetation
to prevent encroachment within the MVCD of transmission lines. R1 is applicable to lines that are identified as an element of an IROL
or Major WECC Transfer Path. R2 is applicable to all other lines that are not elements of IROLs, and not elements of Major WECC
Transfer Paths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation management for an applicable line that is
an element of an IROL or a Major WECC Transfer Path is a greater risk to the interconnected electric transmission system than
applicable lines that are not elements of IROLs or Major WECC Transfer Paths. Applicable lines that are not elements of IROLs or
Major WECC Transfer Paths do require effective vegetation management, but these lines are comparatively less operationally
significant. As a reflection of this difference in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and
Medium for R2.
Requirements R1 and R2 state that if inadequate vegetation management allows vegetation to encroach within the MVCD distance as
shown in Table 2, it is a violation of the standard. Table 2 distances are the minimum clearances that will prevent spark-over based on
the Gallet equations as described more fully in the Technical Reference document.
These requirements assume that transmission lines and their conductors are operating within their Rating. If a line conductor is
intentionally or inadvertently operated beyond its Rating and Rated Electrical Operating Condition (potentially in violation of other
standards), the occurrence of a clearance encroachment may occur solely due to that condition. For example, emergency actions taken
by a Transmission Operator or Reliability Coordinator to protect an Interconnection may cause excessive sagging and an outage.
Draft 6: August 14, 2011
21
FAC-003-2 — Transmission Vegetation Management
Another example would be ice loading beyond the line’s Rating and Rated Electrical Operating Condition. Such vegetation-related
encroachments and outages are not violations of this standard.
Evidence of failures to adequately manage vegetation include real-time observation of a vegetation encroachment into the MVCD
(absent a Sustained Outage), or a vegetation-related encroachment resulting in a Sustained Outage due to a fall-in from inside the
ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to the blowing together of the lines and vegetation
located inside the ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to a grow-in. Faults which do not
cause a Sustained outage and which are confirmed to have been caused by vegetation encroachment within the MVCD are considered
the equivalent of a Real-time observation for violation severity levels.
With this approach, the VSLs for R1 and R2 are structured such that they directly correlate to the severity of a failure of a
Transmission Owner to manage vegetation and to the corresponding performance level of the Transmission Owner’s vegetation
program’s ability to meet the objective of “preventing the risk of those vegetation related outages that could lead to Cascading.” Thus
violation severity increases with a Transmission Owner’s inability to meet this goal and its potential of leading to a Cascading event.
The additional benefits of such a combination are that it simplifies the standard and clearly defines performance for compliance. A
performance-based requirement of this nature will promote high quality, cost effective vegetation management programs that will
deliver the overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For example initial investigations and
corrective actions may not identify and remove the actual outage cause then another outage occurs after the line is re-energized and
previous high conductor temperatures return. Such events are considered to be a single vegetation-related Sustained Outage under the
standard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for various altitudes and operating
voltages that is used in the design of Transmission Facilities. Keeping vegetation from entering this space will prevent transmission
outages.
If the Transmission Owner has applicable lines operated at nominal voltage levels not listed in Table 2, then the TO should use the
next largest clearance distance based on the next highest nominal voltage in the table to determine an acceptable distance.
Draft 6: August 14, 2011
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FAC-003-2 — Transmission Vegetation Management
Requirement R3: R3 is a competency based requirement concerned with the maintenance strategies, procedures, processes, or
specifications, a Transmission Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the Transmission Owner uses to plan
and perform vegetation work to prevent transmission Sustained Outages and minimize risk to the transmission system. The approach
provides the basis for evaluating the intent, allocation of appropriate resources, and the competency of the Transmission Owner in
managing vegetation. There are many acceptable approaches to manage vegetation and avoid Sustained Outages. However, the
Transmission Owner must be able to show the documentation of its approach and how it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7. However, regardless of the approach a
utility uses to manage vegetation, any approach a Transmission Owner chooses to use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or maximum vegetation height) to
ensure that MVCD clearances are never violated.
2. the work methods that the Transmission Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing in reaction to a number of different loading variables.
Changes in vertical and horizontal conductor positioning are the result of thermal and physical loads applied to the line. Thermal
loading is a function of line current and the combination of numerous variables influencing ambient heat dissipation including wind
velocity/direction, ambient air temperature and precipitation. Physical loading applied to the conductor affects sag and sway by
combining physical factors such as ice and wind loading. The movement of the transmission line conductor and the MVCD is
illustrated in Figure 1 below. In the Technical Reference document more figures and explanations of conductor dynamics are
provided.
Draft 6: August 14, 2011
23
FAC-003-2 — Transmission Vegetation Management
Figure 1
A cross-section view of a single conductor at a given point along the span is shown with six possible conductor
positions due to movement resulting from thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the Transmission Owner for the mitigation of Fault
risk when a vegetation threat is confirmed. R4 involves the notification of potentially threatening vegetation conditions, without any
intentional delay, to the control center holding switching authority for that specific transmission line. Examples of acceptable
unintentional delays may include communication system problems (for example, cellular service or two-way radio disabled), crews
located in remote field locations with no communication access, delays due to severe weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in the form of a Transmission Owner’s
employee who personally identifies such a threat in the field. Confirmation could also be made by sending out an employee to
evaluate a situation reported by a landowner.
Draft 6: August 14, 2011
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FAC-003-2 — Transmission Vegetation Management
Vegetation-related conditions that warrant a response include vegetation that is near or encroaching into the MVCD (a grow-in issue)
or vegetation that could fall into the transmission conductor (a fall-in issue). A knowledgeable verification of the risk would include
an assessment of the possible sag or movement of the conductor while operating between no-load conditions and its rating.
The Transmission Owner has the responsibility to ensure the proper communication between field personnel and the control center to
allow the control center to take the appropriate action until or as the vegetation threat is relieved. Appropriate actions may include a
temporary reduction in the line loading, switching the line out of service, or other preparatory actions in recognition of the increased
risk of outage on that circuit. The notification of the threat should be communicated in terms of minutes or hours as opposed to a
longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at any moment. For example, some
Transmission Owners may have a danger tree identification program that identifies trees for removal with the potential to fall near the
line. These trees would not require notification to the control center unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the Transmission Owner for the mitigation of
Sustained Outage risk when temporarily constrained from performing vegetation maintenance. The intent of this requirement is to
deal with situations that prevent the Transmission Owner from performing planned vegetation management work and, as a result, have
the potential to put the transmission line at risk. Constraints to performing vegetation maintenance work as planned could result from
legal injunctions filed by property owners, the discovery of easement stipulations which limit the Transmission Owner’s rights, or
other circumstances.
This requirement is not intended to address situations where the transmission line is not at potential risk and the work event can be
rescheduled or re-planned using an alternate work methodology. For example, a land owner may prevent the planned use of chemicals
on non-threatening, low growth vegetation but agree to the use of mechanical clearing. In this case the Transmission Owner is not
under any immediate time constraint for achieving the management objective, can easily reschedule work using an alternate approach,
and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint, the Transmission Owner is required
to take an interim corrective action to mitigate the potential risk to the transmission line. A wide range of actions can be taken to
address various situations. General considerations include:
•
Identifying locations where the Transmission Owner is constrained from performing planned vegetation maintenance work
which potentially leaves the transmission line at risk.
Draft 6: August 14, 2011
25
FAC-003-2 — Transmission Vegetation Management
•
•
•
•
Developing the specific action to mitigate any potential risk associated with not performing the vegetation maintenance
work as planned.
Documenting and tracking the specific action taken for the location.
In developing the specific action to mitigate the potential risk to the transmission line the Transmission Owner could
consider location specific measures such as modifying the inspection and/or maintenance intervals. Where a legal
constraint would not allow any vegetation work, the interim corrective action could include limiting the loading on the
transmission line.
The Transmission Owner should document and track the specific corrective action taken at each location. This location
may be indicated as one span, one tree or a combination of spans on one property where the constraint is considered to be
temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing Vegetation Inspections. The provision
that Vegetation Inspections can be performed in conjunction with general line inspections facilitates a Transmission Owner’s ability to
meet this requirement. However, the Transmission Owner may determine that more frequent vegetation specific inspections are
needed to maintain reliability levels, based on factors such as anticipated growth rates of the local vegetation, length of the local
growing season, limited ROW width, and local rainfall. Therefore it is expected that some transmission lines may be designated with
a higher frequency of inspections.
The VSLs for Requirement R6 have levels ranked by the failure to inspect a percentage of the applicable lines to be inspected. To
calculate the appropriate VSL the Transmission Owner may choose units such as: circuit, pole line, line miles or kilometers, etc.
For example, when a Transmission Owner operates 2,000 miles of applicable transmission lines this Transmission Owner will be
responsible for inspecting all the 2,000 miles of lines at least once during the calendar year. If one of the included lines was 100 miles
long, and if it was not inspected during the year, then the amount failed to inspect would be 100/2000 = 0.05 or 5%. The “Low VSL”
for R6 would apply in this example.
Draft 6: August 14, 2011
26
FAC-003-2 — Transmission Vegetation Management
Requirement R7:
R7 is a risk-based requirement. The Transmission Owner is required to complete its an annual work plan for vegetation management
to accomplish the purpose of this standard. Modifications to the work plan in response to changing conditions or to findings from
vegetation inspections may be made and documented provided they do not put the transmission system at risk. The annual work plan
requirement is not intended to necessarily require a “span-by-span”, or even a “line-by-line” detailed description of all work to be
performed. It is only intended to require that the Transmission Owner provide evidence of annual planning and execution of a
vegetation management maintenance approach which successfully prevents encroachment of vegetation into the MVCD.
For example, when a Transmission Owner identifies 1,000 miles of applicable transmission lines to be completed in the Transmission
Owner’s annual plan, the Transmission Owner will be responsible completing those identified miles. If a Transmission Owner makes
a modification to the annual plan that does not put the transmission system at risk of an encroachment the annual plan may be
modified. If 100 miles of the annual plan is deferred until next year the calculation to determine what percentage was completed for
the current year would be: 1000 – 100 (deferred miles) = 900 modified annual plan, or 900 / 900 = 100% completed annual miles. If a
Transmission Owner only completed 875 of the total 1000 miles with no acceptable documentation for modification of the annual plan
the calculation for failure to complete the annual plan would be: 1000 – 875 = 125 miles failed to complete then, 125 miles (not
completed) / 1000 total annual plan miles = 12.5% failed to complete.
The ability to modify the work plan allows the Transmission Owner to change priorities or treatment methodologies during the year as
conditions or situations dictate. For example recent line inspections may identify unanticipated high priority work, weather conditions
(drought) could make herbicide application ineffective during the plan year, or a major storm could require redirecting local resources
away from planned maintenance. This situation may also include complying with mutual assistance agreements by moving resources
off the Transmission Owner’s system to work on another system. Any of these examples could result in acceptable deferrals or
additions to the annual work plan provided that they do not put the transmission system at risk of a vegetation encroachment.
In general, the vegetation management maintenance approach should use the full extent of the Transmission Owner’s easement, fee
simple and other legal rights allowed. A comprehensive approach that exercises the full extent of legal rights on the ROW is superior
to incremental management because in the long term it reduces the overall potential for encroachments, and it ensures that future
planned work and future planned inspection cycles are sufficient.
When developing the annual work plan the Transmission Owner should allow time for procedural requirements to obtain permits to
work on federal, state, provincial, public, tribal lands. In some cases the lead time for obtaining permits may necessitate preparing
work plans more than a year prior to work start dates. Transmission Owners may also need to consider those special landowner
requirements as documented in easement instruments.
Draft 6: August 14, 2011
27
FAC-003-2 — Transmission Vegetation Management
This requirement sets the expectation that the work identified in the annual work plan will be completed as planned. Therefore,
deferrals or relevant changes to the annual plan shall be documented. Depending on the planning and documentation format used by
the Transmission Owner, evidence of successful annual work plan execution could consist of signed-off work orders, signed contracts,
printouts from work management systems, spreadsheets of planned versus completed work, timesheets, work inspection reports, or
paid invoices. Other evidence may include photographs, and walk-through reports.
Draft 6: August 14, 2011
28
FAC-003-2 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 7
For Alternating Current Voltages (feet)
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
(kV) 8
MVCD
(feet)
MVCD
(feet)
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
Over sea
level up
to 500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over
2000 ft
up to
3000 ft
Over
3000 ft
up to
4000 ft
Over
4000 ft
up to
5000 ft
Over
5000 ft
up to
6000 ft
Over
6000 ft
up to
7000 ft
Over
7000 ft
up to
8000 ft
Over
8000 ft
up to
9000 ft
Over
9000 ft
up to
10000 ft
Over
10000 ft
up to
11000 ft
765
800
8.2ft
8.33ft
8.61ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
500
550
5.15ft
5.25ft
5.45ft
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
345
362
3.19ft
3.26ft
3.39ft
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
287
302
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
230
242
3.03ft
3.09ft
3.22ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
161*
169
2.05ft
2.09ft
2.19ft
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
138*
145
1.74ft
1.78ft
1.86ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
115*
121
1.44ft
1.47ft
1.54ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
88*
100
1.18ft
1.21ft
1.26ft
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
69*
72
0.84ft
0.86ft
0.90ft
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)
7
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will be
achieved at time of vegetation maintenance.
8
Where applicable lines are operated at nominal voltages other than those listed, The Transmission Owner should use the maximum system voltage to determine
the appropriate clearance for that line.
Draft 6: August 14, 2011
29
FAC-003-2 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level up
to 152.4
m
Over
152.4 m up
to 304.8 m
Over 304.8
m up to
609.6m
Over
609.6m up
to 914.4m
Over
914.4m up
to
1219.2m
Over
1219.2m
up to
1524m
Over 1524 m
up to 1828.8
m
Over
1828.8m
up to
2133.6m
Over
2133.6m
up to
2438.4m
Over
2438.4m up
to 2743.2m
Over
2743.2m up
to 3048m
Over
3048m up
to
3352.8m
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
69*
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
Draft 6: August 14, 2011
30
FAC-003-2 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
±750
±600
±500
±400
±250
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
Over sea
level up to
500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over
152.4 m
up to
304.8 m
(Over
304.8 m
up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to
1219.2m
(Over
1219.2m
up to
1524m
(Over
1524 m up
to 1828.8
m)
(Over
1828.8m
up to
2133.6m)
(Over
2133.6m
up to
2438.4m)
(Over
2438.4m
up to
2743.2m)
(Over
2743.2m
up to
3048m)
(Over
3048m up
to
3352.8m)
14.12ft
(4.30m)
10.23ft
(3.12m)
8.03ft
(2.45m)
6.07ft
(1.85m)
3.50ft
(1.07m)
14.31ft
(4.36m)
10.39ft
(3.17m)
8.16ft
(2.49m)
6.18ft
(1.88m)
3.57ft
(1.09m)
14.70ft
(4.48m)
10.74ft
(3.26m)
8.44ft
(2.57m)
6.41ft
(1.95m)
3.72ft
(1.13m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
6.63ft
(2.02m)
3.87ft
(1.18m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
6.86ft
(2.09m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
7.09ft
(2.16m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
7.33ft
(2.23m)
4.34ft
(1.32m)
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
7.56ft
(2.30m)
4.5ft
(1.37m)
16.91ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
7.80ft
(2.38m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
8.03ft
(2.45m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
8.27ft
(2.52m)
5.00ft
(1.52m)
17.97ft
(5.48m)
13.54ft
(4.13m)
10.92ft
(3.33m)
8.51ft
(2.59m)
5.17ft
(1.58m)
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a misapplication. The SDT consulted specialists
who advised that the Gallet Equation would be a technically justified method. The explanation of why the Gallet approach is more
appropriate is explained in the paragraphs below.
Draft 6: August 14, 2011
31
FAC-003-2 — Transmission Vegetation Management
The drafting team sought a method of establishing minimum clearance distances that uses realistic weather conditions and realistic
maximum transient over-voltages factors for in-service transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to conductor distances in FAC-003-1:
•
avoid the problem associated with referring to tables in another standard (IEEE-516-2003)
•
transmission lines operate in non-laboratory environments (wet conditions)
•
transient over-voltage factors are lower for in-service transmission lines than for inadvertently re-energized transmission lines
with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in IEEE 516-2003 to determine the
minimum distance between a transmission line conductor and vegetation. The equations and methods provided in IEEE 516 were
developed by an IEEE Task Force in 1968 from test data provided by thirteen independent laboratories. The distances provided in
IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap, or in other words, dry laboratory conditions.
Consequently, the validity of using these distances in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the minimum clearance distances. Table 7
could be used if the Transmission Owner knew the maximum transient over-voltage factor for its system. Otherwise, Table 5 would
have to be used. Table 5 represented minimum air insulation distances under the worst possible case for transient over-voltage factors.
These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV
phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for concern in this
particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is inadvertently re-energized immediately after the
line is de-energized and a trapped charge is still present. The intent of FAC-003 is to keep a transmission line that is in service from
becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst case
transient overvoltage assumptions are not appropriate for this application. Rather, the appropriate over voltage values are those that
occur only while the line is energized.
Draft 6: August 14, 2011
32
FAC-003-2 — Transmission Vegetation Management
Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are
negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 per unit. This value is a conservative estimate of the transient overvoltage that is created at the point of application (e.g. a substation) by switching a capacitor bank without pre-insertion devices (e.g.
closing resistors). At voltage levels where capacitor banks are not very common (e.g. Maximum System Voltage of 362 kV), the
maximum transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines and shunt reactor bank
switching. These transient voltages are usually 1.5 per unit or less.
Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order
to be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient
over-voltage factor of 2.0 per unit for transmission lines operated at 302 kV and below is considered to be a realistic maximum in this
application. Likewise, for ac transmission lines operated at Maximum System Voltages of 362 kV and above a transient over-voltage
factor of 1.4 per unit is considered a realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These equations are used for computing the
required strike distances for proper transmission line insulation coordination. They were developed for both wet and dry applications
and can be used with any value of transient over-voltage factor. The Gallet Equation also can take into account various air gap
geometries. This approach was used to design the first 500 kV and 765 kV lines in North America.
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical spark-over distances
computed using the Gallet wet equations, for each of the nominal voltage classes and identical transient over-voltage factors, the
Gallet equations yield a more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are not vastly different when the same
transient overvoltage factors are used; the “wet” equations will consistently produce slightly larger distances than the IEEE 516
equations when the same transient overvoltage is used. While the IEEE 516 equations were only developed for dry conditions the
Gallet equations have provisions to calculate spark-over distances for both wet and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live vegetation, there are no spark-over formulas
currently derived expressly for vegetation to conductor minimum distances. Therefore the SDT chose a proven method that has been
used in other EHV applications. The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage Factor
that is consistent with the absence of trapped charges on an in-service transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the Gallet equations.
Draft 6: August 14, 2011
33
FAC-003-2 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations vs.
IEEE 516-2003 MAID distances
Table 7
(Table D.5 for feet)
Draft 6: August 14, 2011
( AC )
( AC )
Nom System
Max System
Transient
Over-voltage
Clearance (ft.)
Voltage (kV)
Voltage (kV)
Factor (T)
765
800
2.0
14.36
13.95
500
550
2.4
11.0
10.07
345
362
3.0
8.55
7.47
230
115
242
121
3.0
3.0
5.28
2.46
4.2
2.1
Gallet (wet)
@ Alt. 3000 feet
IEEE 516-2003
MAID (ft)
@ Alt. 3000 feet
34
FAC-003-2 — Transmission Vegetation Management
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. SC approved SAR for initial posting (January 11, 2007).
2. SAR posted for comment (January 15–February 14, 2007).
3. SAR posted for comment (April 10–May 9, 2007).
4. SC authorized moving the SAR forward to standard development (June 27, 2007).
5. First draft of proposed standard posted (October 27, 2008-November 25, 2008)).
6. Second draft of revised standard posted (September 10, 20-October 24, 2009).
7. Third draft of revised standard posted (March 1, 2010-March 31, 2010).
8. ForthFourth draft of revised standard posted (June 17, 2010-July 17, 2010).
9. Fifth draft of revised standard posted (February 18, 2011-February 28, 2011)
10. Sixth draft of revised standard posted (September xx - 2011)
Proposed Action Plan and Description of Current Draft
This is the thirdfourth posting of the proposed revisions to the standard in accordance with
Results-Based Criteria and the fifthsixth draft overall.
Future Development Plan
Anticipated Actions
Recirculation ballot of standards.
Receive BOT approval
Draft 5: January 276: August 14, 2011
Anticipated Date
JanuarySeptember
2011
FebruaryNovember
2011
1
FAC-003-2 — Transmission Vegetation Management
Effe c tive Da te s
FirstThis standard becomes effective on the first calendar day of the first calendar quarter one
year after the date of the order approving the standard from applicable regulatory authorities
where such explicit approval is required. Where no regulatory approval is required, the standard
becomes effective on the first calendar day of the first calendar quarter one year after Board of
Trustees adoption.
Exceptions:Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of
an Interconnection Reliability Operating Limit (IROL) or designated by the Western
Electricity Coordinating Council (WECC) as an element of a Major WECC transfer
pathTransfer Path, becomes subject to this standard the latter of: 1) 12 months after the
date the Planning Coordinator or WECC initially designates the line as being subjectan
element of an IROL or an element of a Major WECC Transfer Path, or 2) January 1 of
the planning year when the line is forecast to this standard.become an element of an
IROL or an element of a Major WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element
of an IROL or a Major WECC Transfer Path which has a specified date for the removal
of such designation will no longer be subject to this standard effective on that specified
date.
3. A line operated at 200 kV or above, currently subject to this standard which is a
designated element of an IROL or a Major WECC Transfer Path and which has a
specified date for the removal of such designation will be subject to Requirement R2 and
no longer be subject to Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher thatwhich is newly acquired by
an asset owner and which was not previously subject to this standard, becomes subject to
this standard 12 months after the acquisition date of the line..
5. An existing transmission line operated below 200kV which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date of the line if at the time of acquisition the
line is designated by the Planning Coordinator as an element of an IROL or by WECC as
an element of a Major WECC Transfer Path.
Draft 5: January 276: August 14, 2011
2
FAC-003-2 — Transmission Vegetation Management
Ve rs io n His to ry
Version
1
Date
TBA
Action
1. Added “Standard Development
Roadmap.”
Change Tracking
01/20/06
2. Changed “60” to “Sixty” in section
A, 5.2.
3. Added “Proposed Effective Date:
April 7, 2006” to footer.
4. Added “Draft 3: November 17,
2005” to footer.
1
2
April 4, 2007
Regulatory Approval — Effective Date
Draft 5: January 276: August 14, 2011
New
3
FAC-003-2 — Transmission Vegetation Management
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary. When this standard has received ballot approval, the text
boxes will be moved to the Guideline and Technical Basis Section.
Right-of-Way (ROW)
The current glossary definition of this NERC
The corridor of land under a transmission line(s)
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in Paragraph 734 of FERC Order 693.
corridor is established by engineering or
construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in
effect when the line was built. The ROW width in no case exceeds the Transmission Owner’s
legal rights but may be less based on the aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the Transmission Owner’s control
that are likely to pose a hazard to the line(s) prior to
the next planned maintenance or inspection. This
may be combined with a general line inspection.
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
Draft 5: December 17, 20106: August 14, 2011
4
FAC-003-2 — Transmission Vegetation Management
When this standard has received ballot approval, the text boxes will be moved to the Guideline
and Technical Basis Section.
A. Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-2
3. ObjectivesPurpose: To maintain a reliable electric transmission system by using a
defense-in-depth strategy to manage vegetation located on transmission
rights of way (ROW) and minimize encroachments from vegetation
located adjacent to the ROW, thus preventing the risk of those vegetationrelated outages that could lead to Cascading.
4. Applicability
4.1.
Functional Entities:
4.1.1 Transmission Owners
4.2.
Facilities: Defined below (referred to as “applicable lines”), including but not
limited to those that cross lands owned by federal 1, state, provincial, public,
private, or tribal entities:
Rationale: The areas excluded in 4.2.4
were excluded based on comments from
4.2.1. OverheadEach overhead transmission
industry for reasons summarized as
linesline operated at 200kV or higher.
follows: 1) There is a very low risk from
vegetation in this area. Based on an
4.2.2. OverheadEach overhead transmission
informal survey, no TOs reported such
linesline operated below 200kV having
an event. 2) Substations, switchyards,
been identified as included in the
and stations have many inspection and
definitionan element of an
maintenance activities that are necessary
Interconnection Reliability Operating
for reliability. Those existing process
Limit (IROL) under NERC Standard
manage the threat. As such, the formal
FAC-014 by the Planning Coordinator.
steps in this standard are not well suited
for this environment. 3) NERC has a
4.2.3. OverheadEach overhead
project in place to address at a later date
Rationale
transmission linesline operated
the applicability of this standard to
-The areas
excludedOwners.
in 4.2.44)
were
excluded based
below 200 kV having been
Generation
Specifically
on
comments
from
industry
for
reasons
addressing the areas where the summarized
standard
identified as included in the
as
follows:
1)
There
is
a
very
low
risk
from
does
and
does
not
apply
makes
the
definitionan element of one of
vegetationstandard
in this area.
Based
on
an
informal
clearer.
thea Major WECC Transfer
survey, no TOs reported such an event. 2)
PathsPath in the Bulk Electric
Substations, switchyards, and stations have many
System by WECC.
inspection and maintenance activities that are
necessary for reliability. Those existing process
4.2.4. This standard applies toEach
manage the threat. As such, the formal steps in this
overhead transmission linesline
standard are not well suited for this environment. 3)
The standard was written for Transmission Owners.
1
EPAct 2005 section 1211c: “Access
Rolling the excluded areas into this standard will
approvals by Federal agencies”..”
bring GO and DP into the standard, even though
NERC has an initiative in place to address this
bigger registry issue. 4) Specifically addressing the
5 makes
Draft 5: December 17, 20106: August 14, 2011
areas where the standard applies or doesn’t
the standard stronger as it relates to clarity.
FAC-003-2 — Transmission Vegetation Management
identified above (4.2.1 through 4.2.3) located outside the fenced area of
the switchyard, station or substation and any portion of the span of the
transmission line that is crossing the substation fence.
Enforcement: The reliability obligations of the applicable entities and facilities are contained
within the technical requirements of this standard. [Straw proposal]
5. Background:
This NERC Vegetation Management Standard (“Standard”) uses a defense-in-depth
approach to improve the reliability of the electric Transmission System by preventing those
vegetation related outages that could lead to Cascading. This Standard is not intended to
address non-preventable outages such as those due to vegetation fall-ins or blow-ins from
outside the Right-of-Way, vandalism, human activities and acts of nature. Operating
experience indicates that trees that have grown out of specification have contributed to
Cascading, especially under heavy electrical loading conditions.
With a defense-in-depth strategy, this Standard utilizesThe Requirements within a Reliability
Standard govern and will be enforced. The Requirements within a Reliability Standard define
what an entity must do to be compliant and binds an entity to certain obligations of performance
under Section 215 of the Federal Power Act. Compliance will in all cases be measured by
determining whether a party met or failed to meet the Reliability Standard Requirement given the
specific facts and circumstances of its use, ownership or operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining satisfactory
performance nor to limit how an entity may demonstrate compliance if valid alternatives to
demonstrating compliance are available in a specific case. A Reliability Standard may be
enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements
under NERC’s Reliability Standards or to modify the Requirements in any existing NERC
Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”
5. Background:
Draft 5: December 17, 20106: August 14, 2011
6
FAC-003-2 — Transmission Vegetation Management
This standard uses three types of requirements to provide layers of protection to prevent
vegetation related outages that could lead to Cascading:
a)
Performance-based — defines a particular reliability objective or outcome to be
achieved. In its simplest form, a results-based requirement has four components:
who, under what conditions (if any), shall perform what action, to achieve what
particular bulk power system performance result or outcome?
b)
Risk-based — preventive requirements to reduce the risks of failure to
acceptable tolerance levels. A risk-based reliability requirement should be framed
as: who, under what conditions (if any), shall perform what action, to achieve
what particular result or outcome that reduces a stated risk to the reliability of
the bulk power system?
c)
Competency-based — defines a minimum capabilityset of capabilities an entity
needs to have to demonstrate it is able to perform its designated reliability
functions. A competency-based reliability requirement should be framed as: who,
under what conditions (if any), shall have what capability, to achieve what
particular result or outcome to perform an action to achieve a result or outcome
or to reduce a risk to the reliability of the bulk power system?
The defense-in-depth strategy for reliability standards development recognizes that each
requirement in a NERC reliability standard has a role in preventing system failures, and
that these roles are complementary and reinforcing. Reliability standards should not be
viewed as a body of unrelated requirements, but rather should be viewed as part of a
portfolio of requirements designed to achieve an overall defense-in-depth strategy and
comport with the quality objectives of a reliability standard. For this Standard, the
requirements have been developed as follows:
•
This standard uses a defense-in-depth approach to improve the reliability of the
electric Transmission system by:
• Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash-over clearance (R1 and R2);
• Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over
conditions including consideration of 1) conductor dynamics and 2) the
interrelationships between vegetation growth rates, control methods and the
inspection frequency (R3);
• Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash-over at any moment (R4);
• Requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains such as legal injunctions (R5);
• Requiring inspections of vegetation conditions to be performed annually (R6);
and
• Requiring that the annual work needed to prevent flash-over is completed (R7).
For this standard, the requirements have been developed as follows:
Draft 5: December 17, 20106: August 14, 2011
7
FAC-003-2 — Transmission Vegetation Management
•
Performance-based: Requirements 1 and 2
•
•
Competency-based: Requirement 3
•
•
Risk-based: Requirements 4, 5, 6 and 7
Thus the various requirements associated with a successful vegetation program could be
viewed as using R1, R2 and R3 as first levels of defense; while R4 could be a subsequent
or final level of defense. R6 depending on the particular vegetation approach may be
either an initial defense barrier or a final defense barrier. R3 serves as the first line of
defense by ensuring that entities understand the problem they are trying to manage and
have fully developed strategies and plans to manage the problem. R1, R2, and R7 serve
as the second line of defense by requiring that entities carry out their plans and manage
vegetation. R6, which requires inspections, may be either a part of the first line of
defense (as input into the strategies and plans) or as a third line of defense (as a check of
the first and second lines of defense). R4 serves as the final line of defense, as it
addresses cases in which all the other lines of defense have failed.
Major outages and operational problems have resulted from interference between
overgrown vegetation and transmission lines located on many types of lands and
ownership situations. Adherence to the Standardstandard requirements for applicable
lines on any kind of land or easement, whether they are Federal Lands, state or provincial
lands, public or private lands, franchises, easements or lands owned in fee, will reduce
and manage this risk. For the purpose of the Standardstandard the term “public lands”
includes municipal lands, village lands, city lands, and a host of other governmental
entities.
This Standardstandard addresses vegetation management along applicable overhead lines
and does not apply to underground lines, submarine lines or to line sections inside an
electric station boundary.
This Standardstandard focuses on transmission lines to prevent those vegetation related
outages that could lead to Cascading. It is not intended to prevent customer outages due
to tree contact with lower voltage distribution system lines. For example, localized
customer service might be disrupted if vegetation were to make contact with a 69kV
transmission line supplying power to a 12kV distribution station. However, this
Standardstandard is not written to address such isolated situations which have little
impact on the overall electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses an
increased outage risk, especially when numerous transmission lines are operating at or
near their Rating. This can present a significant risk of multipleconsecutive line failures
andwhen lines are experiencing large sags thereby leading to Cascading. Once the first
line fails the shift of the current to the other lines and/or the increasing system loads will
lead to the second and subsequent line failures as contact to the vegetation under those
lines occurs. Conversely, most other outage causes (such as trees falling into lines,
lightning, animals, motor vehicles, etc.) are statistically intermittent. are not an
Draft 5: December 17, 20106: August 14, 2011
8
FAC-003-2 — Transmission Vegetation Management
interrelated function of the shift of currents or the increasing system loading. These
events are not any more likely to occur during heavy system loads than any other time.
There is no cause-effect relationship which creates the probability of simultaneous
occurrence of other such events. Therefore these types of events are highly unlikely to
cause large-scale grid failures. Thus, this Standard’s emphasis isstandard places the
highest priority on the management of vegetation to prevent vegetation grow-ins.
Draft 5: December 17, 20106: August 14, 2011
9
FAC-003-2 — Transmission Vegetation Management
B. Requirements and Measures
R1. Each Transmission Owner shall
manage vegetation to prevent
encroachments of the types shown
below, into the Minimum Vegetation
Clearance Distance (MVCD) of any of
its applicable line(s) identified
aswhich are either an element of an
Interconnection Reliability Operating
Limit (IROL) in the planning horizon
by the Planning Coordinator;, or an
element of a Major Western Electricity
Coordinating Council (WECC)
transfer path(s); Transfer Path;
operating within its Rating and all
Rated Electrical Operating
Conditions.2 of the types shown
below 3 [Violation Risk Factor: High]
[Time Horizon: Real-time]:
1.
An encroachment into the
MVCD as shown in FAC-003Table 2, observed in Real-time,
absent a Sustained Outage 4,
2.
An encroachment due to a fall-in
from inside the Right-of-Way
(ROW) that caused a vegetationrelated Sustained Outage 5,
3.
An encroachment due to the
blowing together of applicable
Rationale for R1 and R2:
Lines
with the highest significance to reliability
Rationale
are covered
in R1;
other lines
are covered in
The MVCD
is aallcalculated
minimum
R2. distance stated in feet (meters) to prevent
flash-over between conductors and
vegetation,
andto
Ra tio
n a le fo r for
th evarious
typ e s altitudes
o f fa ilu re
Theicdistances
m a noperating
a g e ve gvoltages.
e ta tio n wh
h a re lisin
te Table
d in 2
a proven
o rd were
e r o fderived
in c re a using
s in g de
g re e s transmission
o f s e ve rity in
types
tola te s
n o ndesign
-c o m pmethod.
lia n t p eThe
rfo rm
a n of
c e failure
a s it re
aremlisted
ordereof
to amanage
fa ilu revegetation
o f a Tra ns
is s io in
n Own
r's
ve gincreasing
e ta tio n mdegrees
a in te n aofn cseverity
e p ro gin
ranonm:
compliant performance as it relates to a
1. This
management
is found
by routine
failure
of a TO’s failure
vegetation
maintenance
inspection
orsince
Faultthe
event
investigation,listed
and is
program
encroachments
normally
symptomatic
ofincreasing
unusual conditions
require
different and
levels of in
an otherwise
program.
skills andsound
knowledge
and thus constitute a
logical progression of how well, or poorly, a
2. This
failure occurs
the
TO management
manages vegetation
relativewhen
to this
height
and location of a side tree within the ROW
Requirement.
is not adequately addressed by the program.
3. This management failure occurs when side
growth is not adequately addressed and may be
indicative of an unsound program.
4. This management failure is usually indicative
of a program that is not addressing the most
fundamental dynamic of vegetation management,
(i.e. a grow-in under the line). If this type of
failure is pervasive on multiple lines, it provides a
2
This requirement does not apply to circumstances that are beyond
the controlfor
of aa Transmission
mechanism
Cascade. Owner subject to
this reliability standard, including natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, wind
shear, fresh gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice
storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree,
arboricultural activities or horticultural or agricultural activities, or removal or digging of vegetation. Nothing in this
footnote should be construed to limit the Transmission Owner’s right to exercise its full legal rights on the ROW.
3
This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to
this reliability standard, including natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, wind
shear, fresh gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice
storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree, or
installation, removal, or digging of vegetation. Nothing in this footnote should be construed to limit the
Transmission Owner’s right to exercise its full legal rights on the ROW.
4
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation encroachment within the
MVCD has occurred from vegetation within the ROW, this shall be considered the equivalent of a Real-time
observation.
5
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage
regardless of the actual number of outages within a 24-hour period.
Draft 5: December 17, 20106: August 14, 2011
10
FAC-003-2 — Transmission Vegetation Management
4.
lines and vegetation located inside the ROW that caused a vegetation-related
Sustained OutageOutage4,
An encroachment due to a grow-invegetation growth into the MVCD that caused
a vegetation-related Sustained Outage. Outage4.
[VRF – High] [Time Horizon – Real-time]
M1. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained Outages
associated with encroachment types 2 through 4 above, or records confirming no Realtime observations of any MVCD encroachments. (R1)
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation
encroachment within the MVCD has occurred from vegetation within the ROW, this
shall be considered the equivalent of a Real-time observation.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. (R1)
Rationale
R2. Each Transmission Owner shall manage
The MVCD is a calculated minimum
vegetation to prevent encroachments of the
distance stated in feet (meters) to prevent
types shown below, into the MVCD of any
flash-over between conductors and
of its applicable line(s) that iswhich are not
vegetation, for various altitudes and
either an element of an IROL;, or an
operating voltages. The distances in Table 2
element of a Major WECC transfer
were derived using a proven transmission
pathTransfer Path; operating within its
design method. The types of failure to
Rating and all Rated Electrical Operating
manage vegetation are listed in order of
Conditions.2 of the types shown below2
increasing degrees of severity in non[Violation Risk Factor: Medium] [Time
compliant performance as it relates to a
Horizon: Real-time]:
failure of a TO’s vegetation maintenance
1. An encroachment into the MVCD as
program since the encroachments listed
shown in FAC-003-Table 2 as shown
require different and increasing levels of
in FAC-003-Table 2, observed in Realskills and knowledge and thus constitute a
time, absent a Sustained
logical progression of how well, or poorly,
OutageOutage3,
a TO manages vegetation relative to this
2. An encroachment due to a fall-in from
Requirement.
inside the ROW that caused a
vegetation-related Sustained
OutageOutage4,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained OutageOutage4,
4. An encroachment due to a grow-invegetation growth into the MVCD that caused a
vegetation-related Sustained Outage.Outage4
Draft 5: December 17, 20106: August 14, 2011
11
FAC-003-2 — Transmission Vegetation Management
[VRF – Medium] [Time Horizon – Real-time]
M2. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R2. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained Outages
associated with encroachment types 2 through 4 above, or records confirming no Realtime observations of any MVCD encroachments. (R2)
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation
encroachment within the MVCD has occurred from vegetation within the ROW, this
shall be considered the equivalent of a Real-time observation.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. (R2)
Draft 5: December 17, 20106: August 14, 2011
12
FAC-003-2 — Transmission Vegetation Management
R3. Each Transmission Owner shall have
Rationale
documented maintenance strategies or
The documentation provides a basis for
procedures or processes or specifications
evaluating the competency of the
it uses to prevent the encroachment of
Transmission Owner’s vegetation program.
vegetation into the MVCD of its
There may be many acceptable approaches
applicable transmission lines that
to maintain clearances. Any approach must
include(s)accounts for the following:
demonstrate that the Transmission Owner
3.1 Accounts for the
avoids vegetation-to-wire conflicts under all
movementMovement of applicable
Ratings and all Rated Electrical Operating
transmission line conductors under
Conditions. See Figure 1 for an illustration
their Facility Rating and all Rated
of possible conductor locations.
Electrical Operating Conditions;
3.2 Accounts for the interInterrelationships between vegetation growth rates, vegetation
control methods, and inspection frequency.
[VRF –[Violation Risk Factor: Lower] [Time Horizon –: Long Term
Planning]]:
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the Transmission Owner can prevent encroachment into the MVCD
considering the factors identified in the requirement. (R3)
R4. Each Transmission Owner, without any
Rationale
intentional time delay, shall notify the
ToThis is to ensure expeditious communication
control center holding switching
between the Transmission Owner and the
authority for the associated applicable
control center when a critical situation is
transmission line when the Transmission
confirmed.
Owner has confirmed the existence of a
vegetation condition that is likely to
cause a Fault at any moment. [Violation Risk Factor: Medium] [Time Horizon: Realtime].
[VRF – Medium] [Time Horizon – Real-time]
M4. Each Transmission Owner that has a confirmed vegetation condition likely to cause a
Fault at any moment will have evidence that it notified the control center holding
switching authority for the associated transmission line without any intentional time
delay. Examples of evidence may include control center logs, voice recordings,
switching orders, clearance orders and subsequent work orders. (R4)
Draft 5: December 17, 20106: August 14, 2011
13
FAC-003-2 — Transmission Vegetation Management
R5. When a Transmission Owner is
constrained from performing vegetation
work on an applicable line operating
within its Rating and all Rated Electrical
Operating Conditions, and the constraint
may lead to a vegetation encroachment
into the MVCD of its applicable
transmission lines prior to the
implementation of the next annual work
plan, then the Transmission Owner shall
take corrective action to ensure continued
vegetation management to prevent
encroachments. [Violation Risk Factor:
Medium] [Time Horizon: Operations
Planning].
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
Transmission Owner from performing
planned vegetation maintenance work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the Transmission Owner to put interim
measures in place, rather than do nothing.
The corrective action process is not
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
[VRF – Medium] [Time Horizon – Operations Planning]
M5. Each Transmission Owner has evidence of the corrective action taken for each
constraint where an applicable transmission line was put at potential risk. Examples of
acceptable forms of evidence may include initially-planned work orders, documentation
of constraints from landowners, court orders, inspection records of increased
monitoring, documentation of the de-rating of lines, revised work orders, invoices,
andor evidence that athe line was de-energized. (R5)
Rationale
Inspections are used by Transmission
Owners to assess the condition of the entire
ROW. The information from the assessment
R6. Each Transmission Owner shall perform a
can be used to determine risk, determine
Vegetation Inspection of 100% of its
future work and evaluate recentlyapplicable transmission lines (measured in
completed work. This requirement sets a
units of choice - circuit, pole line, line
minimum Vegetation Inspection frequency
miles or kilometers, etc.) at least once per
of once per calendar year but with no more
calendar year and with no more than 18
than 18 months between inspections on the
calendar months between inspections on
same ROW. Based upon average growth
the same ROW. 67 [Violation Risk Factor:
rates across North America and on common
utility practice, this minimum frequency is
reasonable. Transmission Owners should
6
considerInspection
local and
environmental
When the Transmission Owner is prevented from performing a Vegetation
within
the timeframefactors
in R6
that could
warrant
more
frequent
due to a natural disaster, the TO is granted a time extension that is equivalent
to the
duration
of the
time the TO was
prevented from performing the Vegetation Inspection.
inspections.
Draft 5: December 17, 20106: August 14, 2011
14
FAC-003-2 — Transmission Vegetation Management
Medium] [Time Horizon: Operations Planning].
[VRF – Medium] [Time Horizon – Operations Planning]
M6. Each Transmission Owner has evidence that it conducted Vegetation Inspections of the
transmission line ROW for all applicable transmission lines at least once per calendar
year but with no more than 18 calendar months between inspections on the same ROW.
Examples of acceptable forms of evidence may include completed and dated work
orders, dated invoices, or dated inspection records. (R6)
Rationale
This requirement sets the expectation that
the work identified in the annual work plan
will
be completed as planned. An annual
Rationale
This requirement
vegetation
work plan
sets allows
the expectation
for work to be
that the work
modified
for changing
identifiedconditions,
in the annual
taking
workconsideration
into
plan will be completed
anticipatedasgrowth
planned.
of
It allows modifications
vegetation
and all other to
environmental
the planned
work forprovided
factors,
changingthat
conditions,
the changes
taking
do not
into
consideration
violate
the encroachment
anticipated growth
within the
of MVCD.
vegetation and all other environmental
factors, provided that those modifications
do not put the transmission system at risk
of a vegetation encroachment.
R7. Each Transmission Owner shall complete
100% of its annual vegetation work plan of
applicable lines to ensure no vegetation
encroachments occur within the MVCD.
Modifications to the work plan in response
to changing conditions or to findings from
vegetation inspections may be made
(provided they do not put the transmission
system at riskallow encroachment of a
vegetation encroachmentinto the MVCD)
and must be documented. The percent
completed calculation is based on the
number of units actually completed divided
by the number of units in the final amended
plan (measured in units of choice - circuit, pole line, line miles or kilometers, etc.)
Examples of reasons for modification to annual plan may include: [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of a Transmission Owner 8
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
7
When the Transmission Owner is prevented from performing a Vegetation Inspection within the timeframe in R6
due to a natural disaster, the TO is granted a time extension that is equivalent to the duration of the time the TO was
prevented from performing the Vegetation Inspection.
8
Circumstances that are beyond the control of a Transmission Owner include but are not limited to natural disasters
such as earthquakes, fires, tornados, hurricanes, landslides, ice storms, floods, or major storms as defined either by
the TO or an applicable regulatory body, ice storms, and floods; arboricultural, horticultural or agricultural activities.
Draft 5: December 17, 20106: August 14, 2011
15
FAC-003-2 — Transmission Vegetation Management
[VRF – Medium] [Time Horizon – Operations Planning]
M7. Each Transmission Owner has evidence that it completed its annual vegetation work
plan. for its applicable lines. Examples of acceptable forms of evidence may include a
copy of the completed annual work plan (including modifications if anyas finally
modified), dated work orders, dated invoices, or dated inspection records. (R7)
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16
FAC-003-2 — Transmission Vegetation Management
C. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
1.2 Regional Entity Evidence Retention
Compliance Monitoring and Enforcement Processes:
•
•
•
•
•
•
•
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
Periodic Data Submittals
Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The Transmission Owner retains data or evidence to show compliance with
Requirements R1, R2, R3, R5, R6 and R7, Measures M1, M2, M3, M5, M6 and
M7 for three calendar years unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
The Transmission Owner retains data or evidence to show compliance with
Requirement R4, Measure M4 for most recent 12 months of operator logs or most
recent 3 months of voice recordings or transcripts of voice recordings, unless
directed by its Compliance Enforcement Authority to retain specific evidence for
a longer period of time as part of an investigation.
If a Transmission Owner is found non-compliant, it shall keep information related
to the non-compliance until found compliant or for the time period specified
above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3 Compliance Monitoring and Enforcement Processes:
Compliance Audit
Self-Certification
Spot Checking
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17
FAC-003-2 — Transmission Vegetation Management
Compliance Violation Investigation
Self-Reporting
Complaint
Periodic Data Submittal
1.31.4
Additional Compliance Information
Periodic Data Submittal: The Transmission Owner will submit a quarterly report
to its Regional Entity, or the Regional Entity’s designee, identifying all Sustained
Outages of applicable transmission lineslines operated within their Rating and all
Rated Electrical Operating Conditions as determined by the Transmission Owner
to have been caused by vegetation, except as excluded in footnote 2, which
includesand including as a minimum, the following:
o The name of the circuit(s), the date, time and duration of the outage;
the voltage of the circuit; a description of the cause of the outage; the
category associated with the Sustained Outage; other pertinent
comments; and any countermeasures taken by the Transmission
Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable transmission lines, that are identified as an
element of an IROL or Major WECC Transfer Path, by vegetation
inside and/or outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable transmission lines, but are not identified as an
element of an IROL or Major WECC Transfer Path, by vegetation
inside and/or outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation
falling into applicable transmission lines that are identified as an
element of an IROL or Major WECC Transfer Path, from within the
ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation
falling into applicable transmission lines, but are not identified as an
element of an IROL or Major WECC Transfer Path, from within the
ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling
into applicable transmission lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by
vegetation and applicable transmission lines that are identified as an
element of an IROL or Major WECC Transfer Path, blowing together
from within the ROW.
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18
FAC-003-2 — Transmission Vegetation Management
o Category 4B — Blowing together: Sustained Outages caused by
vegetation and applicable transmission lines, but are not identified as
an element of an IROL or Major WECC Transfer Path, blowing
together from within the ROW.
The Regional Entity will report the outage information provided by Transmission
Owners, as per the above, quarterly to NERC, as well as any actions taken by the
Regional Entity as a result of any of the reported Sustained Outages.
Draft 5: December 17, 20106: August 14, 2011
19
FAC-003-2 — Transmission Vegetation Management
Tim e Ho rizo n s , Vio la tio n Ris k Fa c to rs , a n d Vio la tio n S e ve rity Le ve ls
Table 1
Table of Compliance Elements
R#
R1
R2
R3
Time
Horizon
Real-time
Real-time
Long-Term
Planning
VRF
High
Medium
Violation Severity Level
Lower
Moderate
High
TheThe Transmission
Owner failed to manage
vegetation in a manner
such that the Transmission
Owner had an
encroachment into the
MVCD observed in Realtime, absent a Sustained
Outage.
TheThe Transmission Owner
failed to manage vegetation in
a manner such that the
Transmission Owner had an
encroachment into the MVCD
due to a fall-in from inside the
ROW that caused a
vegetation-related Sustained
Outage.
TheThe Transmission Owner
failed to manage vegetation in
a manner such that the
Transmission Owner had an
encroachment into the MVCD
due to blowing together of
applicable lines and vegetation
located inside the ROW that
caused a vegetation-related
Sustained Outage.
TheThe Transmission Owner
failed to manage vegetation in
a manner such that the
Transmission Owner had an
encroachment into the MVCD
due to a grow-in that caused a
vegetation-related Sustained
Outage.
TheThe Transmission
Owner failed to manage
vegetation in a manner
such that the Transmission
Owner had an
encroachment into the
MVCD observed in Realtime, absent a Sustained
Outage.
TheThe Transmission Owner
failed to manage vegetation in
a manner such that the
Transmission Owner had an
encroachment into the MVCD
due to a fall-in from inside the
ROW that caused a
vegetation-related Sustained
Outage.
TheThe Transmission Owner
failed to manage vegetation in
a manner such that the
Transmission Owner had an
encroachment into the MVCD
due to blowing together of
applicable lines and vegetation
located inside the ROW that
caused a vegetation-related
Sustained Outage.
TheThe Transmission Owner
failed to manage vegetation in
a manner such that the
Transmission Owner had an
encroachment into the MVCD
due to a grow-in that caused a
vegetation-related Sustained
Outage.
The Transmission Owner has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
The Transmission Owner has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
The Transmission Owner does
not have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent
Lower
Draft 5: December 17, 20106: August 14, 2011
20
Severe
FAC-003-2 — Transmission Vegetation Management
inter-relationships between
vegetation growth rates,
vegetation control methods,
and inspection frequency, for
the Transmission Owner’s
applicable lines. (Requirement
R3, Part 3.2)
R4
R5
Real-time
Operations
Planning
R6
Operations
Planning
R7
Operations
Planning
Medium
movement of transmission line
conductors under their Rating
and all Rated Electrical
Operating Conditions, for the
Transmission Owner’s
applicable lines. Requirement
R3, Part 3.1)
the encroachment of vegetation
into the MVCD, for the
Transmission Owner’s
applicable lines.
The Transmission Owner
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
transmissionapplicable line, but
there was intentional delay in
that notification.
The Transmission Owner
experienced a confirmed
vegetation threat and did not
notify the control center
holding switching authority for
that transmissionapplicable
line.
The Transmission Owner did
not take corrective action when
it was constrained from
performing planned vegetation
work where a transmissionan
applicable line was put at
potential risk.
Medium
Medium
The Transmission Owner
failed to inspect 5% or less
of its applicable
transmission lines
(measured in units of
choice - circuit, pole line,
line miles or kilometers,
etc.)
The Transmission Owner
failed to inspect more than 5%
up to and including 10% of its
applicable transmission lines
(measured in units of choice circuit, pole line, line miles or
kilometers, etc.).
The Transmission Owner failed
to inspect more than 10% up to
and including 15% of its
applicable transmission lines
(measured in units of choice circuit, pole line, line miles or
kilometers, etc.).
The Transmission Owner failed
to inspect more than 15% of its
applicable transmission lines
(measured in units of choice circuit, pole line, line miles or
kilometers, etc.).
Medium
The Transmission Owner
failed to complete up to
5% or less of its annual
vegetation work plan
The Transmission Owner
failed to complete more than
5% and up to and including
10% of its annual vegetation
The Transmission Owner failed
to complete more than 10% and
up to and including 15% of its
annual vegetation work plan
The Transmission Owner failed
to complete more than 15% of
its annual vegetation work plan
(including modifications if
Draft 5: December 17, 20106: August 14, 2011
21
FAC-003-2 — Transmission Vegetation Management
(including modifications if
anyfor its applicable lines
(as finally modified).
Draft 5: December 17, 20106: August 14, 2011
work plan (including
modifications if anyfor its
applicable lines (as finally
modified).
(including modifications if
anyfor its applicable lines (as
finally modified).
22
anyfor its applicable lines (as
finally modified).
FAC-003-2 — Transmission Vegetation Management
Va ria n c e s
D. Re g io n a l Diffe re n c e s
None.
D.E. In te rp re ta tio n s
None.
F. As s o c ia te d Do c u m e nts
Guideline and Technical Basis (attached).
Draft 6: August 14, 2011
23
FAC-003-2 — Transmission Vegetation Management
Guideline and Technical Basis
Effective dates:
The first two sentences of the Effective Dates section is standard language used in most NERC standards to cover the general effective
date and is sufficient to cover the vast majority of situations. Five special cases are needed to cover effective dates for individual lines
which undergo transitions after the general effective date. These special cases cover the effective dates for those lines which are
initially becoming subject to the standard, those lines which are changing their applicability within the standard, and those lines which
are changing in a manner that removes their applicability to the standard.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to become elements of an IROL or Major
WECC Transfer Path in a future Planning Year (PY). For example, studies by the Planning Coordinator in 2011 may identify a line to
have that designation beginning in PY 2021, ten years after the planning study is performed. It is not intended for the Standard to be
immediately applicable to, or in effect for, that line until that future PY begins. The effective date provision for such lines ensures that
the line will become subject to the standard on January 1 of the PY specified with an allowance of at least 12 months for the
Transmission Owner to make the necessary preparations to achieve compliance on that line. The table below has some explanatory
examples of the application.
Date that Planning
Study is
completed
05/15/2011
05/15/2011
05/15/2011
05/15/2011
PY the line
will become
an IROL
element
2012
2013
2014
2021
Date 1
05/15/2012
05/15/2012
05/15/2012
05/15/2012
Date 2
01/01/2012
01/01/2013
01/01/2014
01/01/2021
Effective Date
The latter of Date 1
or Date 2
05/15/2012
01/01/2013
01/01/2014
01/01/2021
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or Major WECC Transfer Path may be
removed from that designation due to system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network.
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24
FAC-003-2 — Transmission Vegetation Management
Case 3 is needed because a line operating at 200 kV or above that once was designated as an element of an IROL or Major WECC
Transfer Path may be removed from that designation due to system improvements, changes in generation, changes in loads or changes
in studies and analysis of the network. Such changes result in the need to apply R1 to that line until that date is reached and then to
apply R2 to that line thereafter.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be acquired by a Transmission Owner from a
third party such as a Distribution Provider or other end-user who was using the line solely for local distribution purposes, but the
Transmission Owner, upon acquisition, is incorporating the line into the interconnected electrical energy transmission network which
will thereafter make the line subject to the standard.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by a Transmission Owner from a third party
such as a Distribution Provider or other end-user who was using the line solely for local distribution purposes, but the Transmission
owner, upon acquisition, is incorporating the line into the interconnected electrical energy transmission network. In this special case
the line upon acquisition was designated as an element of an Interconnection Reliability Operating Limit (IROL) or an element of a
Major WECC Transfer Path.
Defined Terms:
Explanation for revising the definition of ROW:
The current NERC glossary definition of Right of Way has been modified to address the matter set forth in Paragraph 734 of FERC
Order 693. The Order pointed out that Transmission Owners may in some cases own more property or rights than are needed to reliably
operate transmission lines. This modified definition represents a slight but significant departure from the strict legal definition of “right
of way” in that this definition is based on engineering and construction considerations that establish the width of a corridor from a
technical basis. The pre-2007 maintenance records are included in the revised definition to allow the use of such vegetation widths if
there were no engineering or construction standards that referenced the width of right of way to be maintained for vegetation on a
particular line but the evidence exists in maintenance records for a width that was in fact maintained prior to this standard becoming
mandatory. Such widths may be the only information available for lines that had limited or no vegetation easement rights and were
typically maintained primarily to ensure public safety. This standard does not require additional easement rights to be purchased to
satisfy a minimum right of way width that did not exist prior to this standard becoming mandatory.
Draft 6: August 14, 2011
25
FAC-003-2 — Transmission Vegetation Management
Explanation for revising the definition of Vegetation Inspections:
The current glossary definition of this NERC term is being modified to allow both maintenance inspections and vegetation inspections
to be performed concurrently. This allows potential efficiencies, especially for those lines with minimal vegetation and/or slow
vegetation growth rates.
Explanation of the definition of the MVCD:
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a method of calculating a flash over
distance that has been used in the design of high voltage transmission lines. Keeping vegetation away from high voltage conductors by
this distance will prevent voltage flash-over to the vegetation. See the explanatory text below for Requirement R3 and associated Figure
1. Table 2 below provides MVCD values for various voltages and altitudes. Details of the equations and an example calculation are
provided in Appendix 1 of the Technical Reference Document.
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be achieved is the prevention ofmanagement of
vegetation such that there are no vegetation encroachments within a minimum distance of transmission lines. Content-wise, R1 and R2
are the same requirements; however, they apply to different Facilities. Both R1 and R2 require each Transmission Owner to manage
vegetation to prevent encroachment within the Minimum Vegetation Clearance Distance (“MVCD”) of transmission lines. R1 is
applicable to lines “that are identified as an element of an Interconnection Reliability Operating Limit (IROL) or Major Western
Electricity Coordinating Council (WECC) transfer path (operating within Rating and Rated Electrical Operating Conditions) to avoid a
Sustained Outage”. R2 appliesIROL or Major WECC Transfer Path. R2 is applicable to all other applicable lines that are not an
elementelements of an IROL orIROLs, and not elements of Major WECC Transfer PathPaths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation management for an encroachment into the
MVCDapplicable line that is an element of an IROL or a Major WECC Transfer Path transmission line is a greater risk to the
interconnected electric transmission system. than applicable lines that are not elements of IROLs or Major WECC Transfer Paths.
Applicable lines that are not an elementelements of an IROLIROLs or Major WECC Transfer Path are required to be clear ofPaths do
require effective vegetation management, but these lines are comparatively less operationally significant. As a reflection of this
difference in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and Medium for R2.
These requirements (Requirements R1 and R2) state that if inadequate vegetation encroachesmanagement allows vegetation to
encroach within the distances MVCD distance as shown in Table 1 in Appendix 1 of this supplemental Transmission Vegetation
Management Standard FAC-003-2 Technical Reference document, it is ina violation of the standard. Table 2 tabulatesdistances are the
Draft 6: August 14, 2011
26
FAC-003-2 — Transmission Vegetation Management
distances necessary tominimum clearances that will prevent spark-over based on the Gallet equations as described more fully in
Appendix 1 below. the Technical Reference document.
These requirements assume that transmission lines and their conductors are operating within their Rating. If a line conductor is
intentionally or inadvertently operated beyond its Rating and Rated Electrical Operating Condition (potentially in violation of other
standards), the occurrence of a clearance encroachment may occur. solely due to that condition. For example, emergency actions
taken by a Transmission Operator or Reliability Coordinator to protect an Interconnection may cause the transmission line to sag
moreexcessive sagging and come closer to vegetation, potentially causing an outage. Another example would be ice loading beyond
the line’s Rating and Rated Electrical Operating Condition. Such vegetation-related encroachments and outages are not a
violationviolations of these requirementsthis standard.
Evidence of violation of Requirement R1 and R2failures to adequately manage vegetation include real-time observation of a
vegetation encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related encroachment resulting in a Sustained
Outage due to a fall-in from inside the ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to the blowing
together of applicablethe lines and vegetation located inside the ROW, or a vegetation-related encroachment resulting in a Sustained
Outage due to a grow-in. If an investigation of Faults which do not cause a Fault by a Transmission Owner confirms that aSustained
outage and which are confirmed to have been caused by vegetation encroachment within the MVCD occurred, then it shall beare
considered the equivalent of a Real-time observation for violation severity levels.
With this approach, the VSLs were definedfor R1 and R2 are structured such that they directly correlate to the severity of a failure of a
Transmission Owner to manage vegetation and to the corresponding performance level of the Transmission Owner’s vegetation
program’s ability to meet the goalobjective of “preventing a Sustained Outagethe risk of those vegetation related outages that could
lead to Cascading.” Thus violation severity increases with a Transmission Owner’s inability to meet this goal and its potential of
leading to a Cascading event. The additional benefits of such a combination are that it simplifies the standard and clearly defines
performance for compliance. A performance-based requirement of this nature will promote high quality, cost effective vegetation
management programs that will deliver the overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For example, a limb initial investigations and
corrective actions may only partially break and intermittently contact anot identify and remove the actual outage cause then another
outage occurs after the line is re-energized and previous high conductor. temperatures return. Such events are considered to be a
single vegetation-related Sustained Outage under the Standardstandard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for various altitudes and operating
voltages that is used in the design of Transmission Facilities. Keeping vegetation from entering this space will prevent transmission
outages.
Draft 6: August 14, 2011
27
FAC-003-2 — Transmission Vegetation Management
If the Transmission Owner has applicable lines operated at nominal voltage levels not listed in Table 2, then the TO should use the
next largest clearance distance based on the next highest nominal voltage in the table to determine an acceptable distance.
Draft 6: August 14, 2011
28
FAC-003-2 — Transmission Vegetation Management
Requirement R3:
Requirement R3 is a competency based requirement concerned with the maintenance strategies, procedures, processes, or
specifications, a Transmission Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the Transmission Owner uses to plan
and perform vegetation work to prevent transmission Sustained Outages and minimize risk to the Transmission System.transmission
system. The approach provides the basis for evaluating the intent, allocation of appropriate resources, and the competency of the
Transmission Owner in managing vegetation. There are many acceptable approaches to manage vegetation and avoid Sustained
Outages. However, the Transmission Owner must be able to state whatshow the documentation of its approach is and how it conducts
work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7. However, regardless of the approach a
utility uses to manage vegetation, any approach a Transmission Owner chooses to use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or maximum vegetation height) to
ensure that MVCD clearances are never violated.
2. the work methods that the Transmission Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing as ain reaction to a number of different loading
variables. Changes in vertical and horizontal conductor positioning are the result of thermal and physical loads applied to the line.
Thermal loading is a function of line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading applied to the conductor affects sag and
sway by combining physical factors such as ice and wind loading. The movement of the transmission line conductor and the MVCD
is illustrated in Figure 1 below. In the Technical Reference document more figures and explanations of conductor dynamics are
provided.
Draft 6: August 14, 2011
29
FAC-003-2 — Transmission Vegetation Management
Draft 6: August 14, 2011
30
FAC-003-2 — Transmission Vegetation Management
Figure 1
Cross
A cross-section view of a single conductor at a given point along the span showingis shown with six possible
conductor positions due to movement resulting from thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the Transmission Owner for the mitigation of Fault
risk when a vegetation threat is confirmed. R4 involves the notification of potentially threatening vegetation conditions, without any
intentional delay, to the control center holding switching authority for that specific transmission line. Examples of acceptable
unintentional delays may include communication system problems (for example, cellular service or two-way radio disabled), crews
located in remote field locations with no communication access, delays due to severe weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in the form of a Transmission Owner’s
employee who personally identifies such a threat in the field. Confirmation could also be made by sending out an employee to
evaluate a situation reported by a landowner.
Draft 6: August 14, 2011
31
FAC-003-2 — Transmission Vegetation Management
Vegetation-related conditions that warrant a response include vegetation that is near or encroaching into the MVCD (a grow-in issue)
or vegetation that could fall into the transmission conductor (a fall-in issue). A knowledgeable verification of the risk would include
an assessment of the possible sag or movement of the conductor while operating between no-load conditions and its rating.
The Transmission Owner has the responsibility to ensure the proper communication between field personnel and the control center to
allow the control center to take the appropriate action until or as the vegetation threat is relieved. Appropriate actions may include a
temporary reduction in the line loading, switching the line out of service, or positioning the systemother preparatory actions in
recognition of the increasingincreased risk of outage on that circuit. The notification of the threat should be communicated in terms of
minutes or hours as opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at any moment. For example, some
Transmission Owners may have a danger tree identification program that identifies trees for removal with the potential to fall near the
line. These trees would not require notification to the control center unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the Transmission Owner for the mitigation of
Sustained Outage risk when temporarily constrained from performing vegetation maintenance. The intent of this requirement is to
deal with situations that prevent the Transmission Owner from performing planned vegetation management work and, as a result, have
the potential to put the transmission line at risk. Constraints to performing vegetation maintenance work as planned could result from
legal injunctions filed by property owners, the discovery of easement stipulations which limit the Transmission Owner’s rights, or
other circumstances.
This requirement is not intended to address situations where the transmission line is not at potential risk and the work event can be
rescheduled or re-planned using an alternate work methodology. For example, a land owner may prevent the planned use of chemicals
on non-threatening, low growth vegetation but agree to the use of mechanical clearing. In this case the Transmission Owner is not
under any immediate time constraint for achieving the management objective, can easily reschedule work using an alternate approach,
and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint, the Transmission Owner is required
to take an interim corrective action to mitigate the potential risk to the transmission line. A wide range of actions can be taken to
address various situations. General considerations include:
•
Identifying locations where the Transmission Owner is constrained from performing planned vegetation maintenance work
which potentially leaves the transmission line at risk.
Draft 6: August 14, 2011
32
FAC-003-2 — Transmission Vegetation Management
•
•
•
•
Developing the specific action to mitigate any potential risk associated with not performing the vegetation maintenance
work as planned.
Documenting and tracking the specific action taken for eachthe location.
In developing the specific action to mitigate the potential risk to the transmission line the Transmission Owner could
consider location specific measures such as modifying the inspection and/or maintenance intervals. Where a legal
constraint would not allow any vegetation work, the interim corrective action could include limiting the loading on the
transmission line.
The Transmission Owner should document and track the specific corrective action taken at each location. This location
may be indicated as one span, one tree or a combination of spans on one property where the constraint is considered to be
temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing Vegetation Inspections that fits general
industry practice. In addition, the fact. The provision that Vegetation Inspections can be performed in conjunction with general line
inspections further facilitates a Transmission Owner’s ability to meet this requirement. However, the Transmission Owner may
determine that more frequent vegetation specific inspections are needed to maintain reliability levels, dependent upon suchbased on
factors such as anticipated growth rates of the local vegetation, length of the local growing season for the geographical area, limited
ROW width, and local rainfall amounts. Therefore it is expected that some transmission lines may be designated with a higher
frequency of inspections.
The VSLVSLs for Requirement R6 has VSL categorieshave levels ranked by the failure to inspect a percentage of the required ROW
inspections completed.applicable lines to be inspected. To calculate the percentage of inspection completion, appropriate VSL the
Transmission Owner may choose units such as: circuit, pole line, line miles or kilometers, circuit miles or kilometers, pole line miles,
ROW miles, etc.
For example, when a Transmission Owner operates 2,000 miles of 230 kVapplicable transmission lines this Transmission Owner will
be responsible for inspecting all the 2,000 miles of 230 kV transmission lines at least once during the calendar year. If one of the
included lines was 100 miles long, and if it was not inspected during the year, then the amount failed to inspect would be 100/2000 =
0.05 or 5%. The “Low VSL” for R6 would apply in this example.
Requirement R7:
Draft 6: August 14, 2011
33
FAC-003-2 — Transmission Vegetation Management
R7 is a risk-based requirement. The Transmission Owner is required to implementcomplete its an annual work plan for vegetation
management to accomplish the purpose of this standard. Modifications to the work plan in response to changing conditions or to
findings from vegetation inspections may be made and documented provided they do not put the transmission system at risk. The
annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a “line-by-line” detailed description of
all work to be performed. It is only intended to require that the Transmission Owner provide evidence of annual planning and
execution of a vegetation management maintenance approach which successfully prevents encroachment of vegetation into the
MVCD.
For example, when a Transmission Owner identifies 1,000 miles of applicable transmission lines to be completed in the Transmission
Owner’s annual plan, the Transmission Owner will be responsible completing those identified miles. If a Transmission Owner makes
a modification to the annual plan that does not put the transmission system at risk of an encroachment the annual plan may be
modified. If 100 miles of the annual plan is deferred until next year the calculation to determine what percentage was completed for
the current year would be: 1000 – 100 (deferred miles) = 900 modified annual plan, or 900 / 900 = 100% completed annual miles. If a
Transmission Owner only completed 875 of the total 1000 miles with no acceptable documentation for modification of the annual plan
the calculation for failure to complete the annual plan would be: 1000 – 875 = 125 miles failed to complete then, 125 miles (not
completed) / 1000 total annual plan miles = 12.5% failed to complete.
The ability to modify the work plan allows the Transmission Owner to change priorities or treatment methodologies during the year as
conditions or situations dictate. For example recent line inspections may identify unanticipated high priority work, weather conditions
(drought) could make herbicide application ineffective during the plan year, or a major storm could require redirecting local resources
away from planned maintenance. This situation may also include complying with mutual assistance agreements by moving resources
off the Transmission Owner’s system to work on another system. Any of these examples could result in acceptable deferrals or
additions to the annual work plan. Modifications to the annual work plan must always ensure the reliability of the electric
Transmission system. provided that they do not put the transmission system at risk of a vegetation encroachment.
In general, the vegetation management maintenance approach should use the full extent of the Transmission Owner’s easement, fee
simple and other legal rights allowed. A comprehensive approach that exercises the full extent of legal rights on the ROW is superior
to incremental management because in the long term because it reduces the overall potential for encroachments, and it ensures that
future planned work and future planned inspection cycles are sufficient.
When developing the annual work plan the Transmission Owner should allow time for procedural requirements to obtain permits to
work on federal, state, provincial, public, tribal lands. In some cases the lead time for obtaining permits may necessitate preparing
Draft 6: August 14, 2011
34
FAC-003-2 — Transmission Vegetation Management
work plans more than a year prior to work start dates. Transmission Owners may also need to consider those special landowner
requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be completed as planned. Therefore,
deferrals or relevant changes to the annual plan shall be documented. Depending on the planning and documentation format used by
the Transmission Owner, evidence of successful annual work plan execution could consist of signed-off work orders, signed contracts,
printouts from work management systems, spreadsheets of planned versus completed work, timesheets, work inspection reports, or
paid invoices. Other evidence may include photographs, and walk-through reports.
Draft 6: August 14, 2011
35
FAC-003-2 — Transmission Vegetation Management
Draft 6: August 14, 2011
36
FAC-003-2 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 9
For Alternating Current Voltages (feet)
MVCD
(feet
( AC )
Nominal
System
Voltage
(kV)(KV)
( AC )
Maximum
System
Voltage
(kV) 10
MVCD
(feet)
MVCD
feet
(meters
))
sea
level
550
345
362
287
302
169
MVCD
feet
MVCD
feet
MVCD
feet
(meters
)
3,000ft
(914.4
m)
(meters
)
4,000ft
(1219.2
m)
(meters
)
5,000ft
(1524m
)
(meters
)
6,000ft
(1828.8
m)
(meters
)
7,000ft
(2133.6
m)
(mete
rs)
8,000ft
(2438.4
m)
(mete
rs)
9,000ft
(2743.2
m)
(mete
rs)
10,000f
t
(3048m
)
(meters
)
11,000f
t
(3352.8
m)
Over
3000 ft
up to
4000 ft
Over
4000 ft
up to
5000 ft
Over
5000 ft
up to
6000 ft
Over
6000 ft
up to
7000 ft
Over
7000 ft
up to
8000 ft
Over
8000 ft
up to
9000 ft
Over
9000 ft
up to
10000 ft
Over
10000 ft
up to
11000 ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
(2.71m)
(2.80m)
(2.88m)
(2.97m)
(3.05m)
(3.14m)
(3.22m)
(3.31m)
(3.39m)
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
5.25ft
5.45ft
(1.73m)
(1.79m)
(1.85m)
(1.91m)
(1.98m)
(2.04m)
(2.11m)
(2.17m)
(2.24m)
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
19ft
3.26ft
3.39ft
(1.08m)
(1.12m)
(1.16m)
(1.21m)
(1.26m)
(1.30m)
(1.35m)
(1.40m)
(1.44m)
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
3.09ft
3.22ft
(1.02m)
(1.06m)
(1.11m)
(1.15m)
(1.19m)
(1.24m)
(1.29m)
(1.33m)
(1.38m)
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
2.09ft
2.19ft
(0.69m)
(0.73m)
(0.76m)
(0.79m)
(0.82m)
(0.85m)
(0.89m)
(0.92m)
(0.96m)
15ft
3.12ft
3.03ft
2ft
(0.61m)
161*
MVCD
feet
8.61ft
2.97ft
(0.91m)
242
MVCD
feet
8.33ft
2ft
(0.95m)
230
MVCD
feet
Over
2000 ft
up to
3000 ft
5.06ft
(1.54m)
500
MVCD
feet
Over 1000
ft up to
2000 ft
8.06ft
(2.46m)
800
MVCD
feet
Over 500
ft up to
1000 ft
Over sea
level up
to 500 ft
765
MVCD
feet
2.05ft
9
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will be
achieved at time of vegetation maintenance.
10
Where applicable lines are operated at nominal voltages other than those listed, The Transmission Owner should use the maximum system voltage to determine
the appropriate clearance for that line.
Draft 6: August 14, 2011
37
FAC-003-2 — Transmission Vegetation Management
1.7ft
(0.52m)
138*
145
115*
121
88*
100
69*
72
74ft
1.41ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
1.78ft
1.86ft
(0.59m)
(0.62m)
(0.65m)
(0.67m)
(0.70m)
(0.73m)
(0.76m)
(0.79m)
(0.82m)
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
1.47ft
1.54ft
(0.49m)
(0.51m)
(0.53m)
(0.56m)
(0.58m)
(0.61m)
(0.63m)
(0.66m)
(0.69m)
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
1.21ft
1.26ft
(0.40m)
(0.42m)
(0.44m)
(0.46m)
(0.48m)
(0.50m)
(0.52m)
(0.54m)
(0.57m)
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
0.86ft
0.90ft
(0.29m)
(0.30m)
(0.31m)
(0.33m)
(0.34m)
(0.36m)
(0.37m)
(0.39m)
(0.41m)
(0.43m)
44ft
1.15ft
(0.35m)
18ft
0.82ft
(0.25m)
∗
84ft
* Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level up
to 152.4
m
Over
152.4 m up
to 304.8 m
Over 304.8
m up to
609.6m
Over
609.6m up
to 914.4m
Over
914.4m up
to
1219.2m
Over
1219.2m
up to
1524m
Over 1524 m
up to 1828.8
m
Over
1828.8m
up to
2133.6m
Over
2133.6m
up to
2438.4m
Over
2438.4m up
to 2743.2m
Over
2743.2m up
to 3048m
Over
3048m up
to
3352.8m
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
Draft 6: August 14, 2011
38
FAC-003-2 — Transmission Vegetation Management
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
69*
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above).
Draft 6: August 14, 2011
39
FAC-003-2 — Transmission Vegetation Management
Table 2 (cont.) — Minimum Vegetation Clearance Distances (MVCD) )
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
MVCD
feet
(meters)
MVCD
feet
(meters)
3,000ft
(914.4m)
Alt.
MVCD
feet
(meters)
4,000ft
(1219.2m)
Alt.
MVCD
feet
(meters)
5,000ft
(1524m)
Alt.
( DC )
Nominal
Pole to
Ground
Voltage (kV)
( DC )
Nominal
Pole to
Ground
Voltage (kV)
( DC )
Nominal
Pole to
Ground
Voltage (kV)
Nominal
Pole to
Ground
Voltage (kV)
MVCD
feet
(meters)
6,000ft
(1828.8m)
Alt.( DC )
MVCD
feet
(meters)
(8,000ft
(2438.4m)
Alt. ( DC )
Nominal
Pole to
Ground
Voltage (kV)
Nominal
Pole to
Ground
Voltage (kV)
DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nomin
al Pole
to
Groun
d
Voltag
e (kV)
( DC )
Nomin
al Pole
to
Groun
d
Voltag
e (kV)
Over sea
level up to
500 ft
Over
500 ft
up to
1000 ft
Over
1000 ft
up to
2000 ft
Over 2000 ft
up to 3000 ft
Over 3000 ft
up to 4000 ft
Over 4000 ft
up to 5000 ft
Over 5000 ft
up to 6000 ft
Over 6000 ft
up to 7000 ft
Over 7000 ft
up to 8000 ft
(Over sea
level up to
152.4 m)
(Over
152.4
m up
to
304.8
m
(Over
304.8
m up
to
609.6m
)
(Over
609.6m up to
914.4m
(Over
914.4m up to
1219.2m
(Over
1219.2m up
to 1524m
(Over 1524 m
up to 1828.8
m)
(Over
1828.8m up
to 2133.6m)
(Over
2133.6m up
to 2438.4m)
sea level
( DC )
Nominal
Pole to
Ground
Voltage (kV)
Draft 6: August 14, 2011
MVCD
feet
(meters)
9,000ft
(2743.2
m) Alt. (
MVCD
feet
(meters)
7,000ft
(2133.6m)
Alt.( DC )
40
MVCD
feet
(meters)
10,000ft
(3048m)
Alt. ( DC
MVCD
feet
(meters)
11,000ft
(3352.8
m) Alt.(
) Nominal
Pole to
Ground
Voltage
(kV)
DC )
Nominal
Pole to
Ground
Voltage
(kV)
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over
10000 ft up
to 11000 ft
(Over
2438.4m
up to
2743.2m)
(Over
2743.2m
up to
3048m)
(Over
3048m up
to
3352.8m)
FAC-003-2 — Transmission Vegetation Management
13.92ft14.1
±750
±600
±500
2ft
(4.24m30m)
10.07ft23ft
(3.07m12m)
7.89ft 8.03ft
(2.40m45m)
14.31ft
(4.36m)
14.70ft
(4.48m)
15.07ft
(4.59m)
15.45ft
(4.71m)
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.9ft91ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
10.39ft
(3.17m)
10.74ft
(3.26m)
11.04ft
(3.36m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
(13.54ft
8.16ft
(2.49m)
8.44ft
(2.57m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
6.57ft
6.77ft
6.98ft
5.35ft
(1.63m)6.6
5.55ft
(1.69m)6.8
5.75ft
(1.75m)7.0
5.95ft
(1.81m)7.3
6.15ft
(1.87m)7.5
6.36ft
(1.94m)7.8
3ft (2.02m)
6ft (2.09m)
9ft (2.16m)
3ft (2.23m)
6ft (2.30m)
0ft (2.38m)
8.03ft
(2.00m45
m)
8.27ft
(2.06m52
m)
8.51ft
(2.13m59
m)
4.02ft3.87ft
(1.23m18m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5.00ft
(1.52m)
±400
4.78ft 6.07ft
(1.46m85m)
6.18ft
(1.88m)
6.41ft
(1.95m)
±250
3.43ft 50ft
(1.05m07m)
3.57ft
(1.09m)
3.72ft
(1.13m)
(4.13m)
5ft
5.17ft
(1.58m)
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a misapplication. The SDT consulted specialists
who advised that the Gallet Equation would be a technically justified method. The explanation of why the Gallet approach is more
appropriate is explained in the paragraphs below.
The drafting team sought a method of establishing minimum clearance distances that uses realistic weather conditions and realistic
maximum transient over-voltages factors for in-service transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to conductor distances in FAC-003-1:
• avoid the problem associated with referring to tables in another standard (IEEE-516-2003)
• transmission lines operate in non-laboratory environments (wet conditions)
• transient over-voltage factors are lower for in-service transmission lines than for inadvertently re-energized transmission lines
with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in IEEE 516-2003 to determine the
minimum distance between a transmission line conductor and vegetation. The equations and methods provided in IEEE 516 were
developed by an IEEE Task Force in 1968 from test data provided by thirteen independent laboratories. The distances provided in
IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap, or in other words, dry laboratory conditions.
Consequently, the validity of using these distances in an outside environment application has been questioned.
Draft 6: August 14, 2011
41
FAC-003-2 — Transmission Vegetation Management
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the minimum clearance distances. Table 57
could be used if the Transmission Owner knew the maximum transient over-voltage factor for its system. Otherwise, Table 75 would
have to be used. Table 75 represented minimum air insulation distances under the worst possible case for transient over-voltage
factors. These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 550 kV phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for concern
in this particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is inadvertently re-energized immediately after the
line is de-energized and a trapped charge is still present. The intent of FAC-003 is to keep a transmission line that is in service from
becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst case
transient overvoltage assumptions are not appropriate for this application. Rather, the appropriate over voltage values are those that
occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are
negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 per unit. This value is a conservative estimate of the transient overvoltage that is created at the point of application (e.g. a substation) by switching a capacitor bank without pre-insertion devices (e.g.
closing resistors). At voltage levels where capacitor banks are not very common (e.g. Maximum System Voltage of 362 kV), the
maximum transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines and shunt reactor bank
switching. These transient voltages are usually 1.5 per unit or less.
Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order
to be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient
over-voltage factor of 2.0 per unit for transmission lines operated at 242302 kV and below is considered to be a realistic maximum in
this application. Likewise, for ac transmission lines operated at Maximum System Voltages of 362 kV and above a transient overvoltage factor of 1.4 per unit is considered a realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These equations are used for computing the
required strike distances for proper transmission line insulation coordination. They were developed for both wet and dry applications
and can be used with any value of transient over-voltage factor. The Gallet Equation also can take into account various air gap
geometries. This approach was used to design the first 500 kV and 765 kV lines in North America [1]..
Draft 6: August 14, 2011
42
FAC-003-2 — Transmission Vegetation Management
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical spark-over distances
computed using the Gallet wet equations, for each of the nominal voltage classes and identical transient over-voltage factors, the
Gallet equations yield a more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are not vastly different when the same
transient overvoltage factors are used; the “wet” equations will consistently produce slightly larger distances than the IEEE 516
equations when the same transient overvoltage is used. While the IEEE 516 equations were only developed for dry conditions the
Gallet equations have provisions to calculate spark-over distances for both wet and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live vegetation, there are no spark-over formulas
currently derived expressly for vegetation to conductor minimum distances. Therefore the SDT chose a proven method that has been
used in other EHV applications. The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage Factor
that is consistent with the absence of trapped charges on an in-service transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the Gallet equations using various
transient overvoltage values.
Draft 6: August 14, 2011
43
FAC-003-2 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations vs.
IEEE 516-2003 MAID distances
using various transient over-voltage factors
Table 7
(Table D.5 for feet)
( AC )
( AC )
Nom System
Voltage (kV)
Max System
Voltage (kV)
Over-voltage
Factor (T)
Transient
Gallet (wet)
@ Alt. 3000 feet
Clearance (ft.)
765
500
345
230
115
800
550
362
242
121
1.4
1.4
1.4
2.0
2.0
8.89
5.65
3.52
3.35
1.6
IEEE 516-2003
MAID (ft)
@ Alt. 3000 feet
8.65
4.92
3.13
2.8
1.4
Table 5
(historical maximums)
Draft 6: August 14, 2011
( AC )
( AC )
Nom System
Max System
Transient
Over-voltage
Clearance (ft.)
IEEE 516
Gallet (wet)
MAID (ft)
Voltage (kV)
Voltage (kV)
Factor (T)
765
800
2.0
14.36
13.95
500
550
2.4
11.0
10.07
345
362
3.0
8.55
7.47
230
115
242
121
3.0
3.0
5.28
2.46
4.2
2.1
@ Alt. 3000 feet
@ Alt. 3000 feet
44
FAC-003-2 — Transmission Vegetation Management
Table 7
Draft 6: August 14, 2011
( AC )
Nom System
Voltage (kV)
( AC )
Max System
Voltage (kV)
Transient
Over-voltage
Factor (T)
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
765
500
345
230
115
800
550
362
242
121
2.5
3.0
3.5
3.5
3.5
20.25
15.02
10.42
6.32
2.90
IEEE 516
MAID (ft)
@ Alt. 3000 feet
20.4
14.7
9.44
5.14
2.45
45
Implementation Plan
FAC-003-2
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
FAC-003-2 – Vegetation Management
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. There are two
revised definitions in the proposed standard. FAC-003-1 will be retired when FAC-003-2 becomes
effective.
Compliance with Standard
The standard applies to Transmission Owners.
Effective Date
The effective date is the date entities are expected to meet the performance identified in this
standard. The effective date allows entities time to make revisions to their existing transmission
vegetation management programs to comply with the new requirements.
This standard becomes effective on the first calendar day of the first calendar quarter one year after
the date of the order approving the standard from applicable regulatory authorities where such explicit
approval is required. Where no regulatory approval is required, the standard becomes effective on the
first calendar day of the first calendar quarter one year after Board of Trustees adoption.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of an
Interconnection Reliability Operating Limit (IROL) or designated by the Western Electricity
Coordinating Council (WECC) as an element of a Major WECC transfer Path, becomes subject to
this standard the latter of: 1) 12 months after the date the Planning Coordinator or WECC
initially designates the line as being an element of an IROL or an element of a Major WECC
transfer Path, or 2) January 1 of the planning year when the line is forecast to become an
element of an IROL or an element of a Major WECC transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element of an
IROL or a Major WECC Transfer Path which has a specified date for the removal of such
designation will no longer be subject to this standard effective on that specified date.
Implementation Plan – FAC-003-2
1
3. A line operated at 200 kV or above, currently subject to this standard which is a designated
element of an IROL or a Major WECC Transfer Path and which has a specified date for the
removal of such designation will be subject to Requirement R2 and no longer be subject to
Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an asset
owner and which was not previously subject to this standard, becomes subject to this standard
12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset owner
and which was not previously subject to this standard becomes subject to this standard 12
months after the acquisition date of the line if at the time of acquisition the line is designated
by the Planning Coordinator as an element of an IROL or by WECC as an element of a Major
WECC Transfer Path.
Implementation Plan – FAC-003-2
2
Implementation Plan
FAC-003-2
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
FAC-003-2 – Vegetation Management
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. There are two
revised definitions in the proposed standard. FAC-003-1 will be retired when FAC-003-2 becomes
effective.
Compliance with Standard
The standard applies to Transmission Owners.
Effective Date
The effective date is the date entities are expected to meet the performance identified in this standard.
The effective date allows entities time to make revisions to their existing transmission vegetation
management programs to comply with the new requirements.
This standard becomes effective on the Ffirst calendar day of the first calendar quarter one year after the
date of the order approving the standard from applicable regulatory authorities where such explicit
approval is required. Where no regulatory approval is required, the standard becomes effective on the first
calendar day of the first calendar quarter one year after Board of Trustees adoption.
Effective dates for individual lines when they undergo specific transition cases:
Exceptions:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of an
Interconnection Reliability Operating Limit (IROL) or designated by the Western Electricity
Coordinating Council (WECC) as an element of a Major WECC transfer pathPath, becomes
subject to this standard the latter of: 1) 12 months after the date the Planning Coordinator or
WECC initially designates the line as being an element of an IROL or an element of a Major
WECC transfer Path, or 2) January 1 of the planning year when the line is forecast to become an
element of an IROL or an element of a Major WECC transfer Pathsubject to this standard.
Implementation Plan – FAC-003-2
1
2. A line operated below 200 kV currently subject to this standard as a designated element of an
IROL or a Major WECC Transfer Path which has a specified date for the removal of such
designation will no longer be subject to this standard effective on that specified date.
1.3.A line operated at 200 kV or above, currently subject to this standard which is a designated
element of an IROL or a Major WECC Transfer Path and which has a specified date for the
removal of such designation will be subject to Requirement R2 and no longer be subject to
Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher thatwhich is newly acquired by an
asset owner and which was not previously subject to this standard, becomes subject to this
standard 12 months after the acquisition dateof the line.
2.5. An existing transmission line operated below 200kV which is newly acquired by an asset owner
and which was not previously subject to this standard becomes subject to this standard 12
months after the acquisition date of the line if at the time of acquisition the line is designated by
the Planning Coordinator as an element of an IROL or by WECC as an element of a Major
WECC Transfer Path.
Implementation Plan – FAC-003-2
2
Transmission Vegetation
Management
Standard FAC-003-2 Technical Reference
Prepared by the
North American Electric Reliability Corporation
Vegetation Management Standard Drafting Team for NERC
Project 2007-07
September 30, 2011
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Ta b le o f Co n t e n t s
Disclaimer........................................................................................................................................ 3
Introduction .................................................................................................................................... 4
Preface ............................................................................................................................................ 8
Effective Dates & Special States of Transition ................................................................................ 9
Definition of Terms ....................................................................................................................... 12
Applicability of the Standard ........................................................................................................ 14
Requirements R1 and R2 .............................................................................................................. 17
Requirement R3 ............................................................................................................................ 20
ANSI A300 – Best Management Practices for Tree Care Operations ........................................... 25
Requirement R4 ............................................................................................................................ 30
Requirement R5 ............................................................................................................................ 32
Requirement R6 ............................................................................................................................ 34
Requirement R7 ............................................................................................................................ 36
Appendix 1: Clearance Distance Derivation by the Gallet Equation ........................................... 39
Table 1 — Minimum Vegetation Clearance Distances (MVCD) .................................................... 44
List of Acronyms and Abbreviations ................................................................................................ii
References ......................................................................................................................................iii
2
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Dis cla im e r
This supporting document is supplemental to the reliability standard FAC-003-2 — Transmission
Vegetation Management and does not contain mandatory requirements subject to compliance
review. Throughout this document, for ready reference, there are “copies” in italic font of the
wording in the Standard. Any “copy” of any part of the Standard in this document should be
cross checked to the Standard and if any difference exists, then the Standard’s exact wording
should be considered the intended wording for this document.
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
3
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
I n t ro d u ct io n
This document is intended to provide supplemental information and guidance for complying
with the requirements of Reliability Standard FAC-003-2.
The purpose of the Standard is to improve the reliability of the electric transmission system by
preventing those vegetation related outages that could lead to Cascading.
Compliance with the Standard is mandatory and enforceable.
4
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Sp e cia l No t e : Th e Ap p lica t io n o f t h e Re s u lt s -Ba s e d
Ap p ro a ch t o FAC-0 0 3 -2
In its three-year assessment as the ERO, NERC acknowledged stakeholder comments and
committed to:
i) addressing quality issues to ensure each reliability standard has a clear statement of
purpose, and has outcome-focused requirements that are clear and measurable;
and
ii) eliminating requirements that do not have an impact on bulk power system
reliability.
In 2010, the Standards Committee approved a recommendation to use Project 2007-07
Vegetation Management as a first proof of concept for developing results-based standards.
This standard is not intended to address outages such as those due to vegetation fall-ins or
blow-ins from outside the Right-of-Way, vandalism, human activities or acts of nature.
Operating experience indicates that trees that have grown out of specification have contributed
to Cascading, especially under heavy electrical loading conditions.
This standard utilizes three types of requirements to provide layers of protection to prevent
vegetation related outages that could lead to Cascading:
a)
b)
c)
Performance-based defines a particular reliability objective or outcome to be
achieved. In its simplest form, a results-based requirement has four components:
who, under what conditions (if any), shall perform what action, to achieve what
particular result or outcome?
Risk-based preventive requirements to reduce the risks of failure to acceptable
tolerance levels. A risk-based reliability requirement should be framed as: who,
under what conditions (if any), shall perform what action, to achieve what
particular result or outcome that reduces a stated risk to the reliability of the bulk
power system?
Competency-based defines a minimum set of capabilities an entity needs to
have to demonstrate it is able to perform its designated reliability functions. A
competency-based reliability requirement should be framed as: who, under what
conditions (if any), shall have what capability, to achieve what particular result or
outcome to perform an action to achieve a result or outcome or to reduce a risk to
the reliability of the bulk power system?
The defense-in-depth strategy for reliability standards development recognizes that each
requirement in a NERC reliability standard has a role in preventing system failures, and that
these roles are complementary and reinforcing. Reliability standards should not be viewed as a
body of unrelated requirements, but rather should be viewed as part of a portfolio of
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
5
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
requirements designed to achieve an overall defense-in-depth strategy and comport with the
quality objectives of a reliability standard.
This NERC Vegetation Management Standard (“standard”) uses a defense-in-depth approach to
improve the reliability of the electric Transmission System by:
•
Requiring that vegetation be managed to prevent vegetation encroachment inside the
flash-over clearance (R1 and R2);
•
Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over conditions
including consideration of 1) conductor dynamics and 2) the interrelationships between
vegetation growth rates, control methods and the inspection frequency (R3);
•
Requiring timely notification to the appropriate control center of vegetation conditions
that could cause a flash-over at any moment (R4);
•
Requiring corrective actions to ensure that flash-over distances will not be violated due
to work constrains such as legal injunctions (R5);
•
Requiring inspections of vegetation conditions to be performed annually (R6); and
•
Requiring that the annual work needed to prevent flash-over is completed (R7).
For this standard, the requirements have been developed as follows:
•
Performance-based: Requirements 1 and 2
•
Competency-based: Requirement 3
•
Risk-based: Requirements 4, 5, 6 and 7
R3 serves as the first line of defense by ensuring that entities understand the problem they are
trying to manage and have fully developed strategies and plans to manage the problem. R1,
R2, and R7 serve as the second line of defense by requiring that entities carry out their plans
and manage vegetation. R6, which requires inspections, may be either a part of the first line of
defense (as input into the strategies and plans) or as a third line of defense (as a check of the
first and second lines of defense). R4 serves as the final line of defense, as it addresses cases in
which all the other lines of defense have failed.
Major outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations.
Adherence to the standard requirements for applicable lines on any kind of land or easement,
whether they are Federal Lands, state or provincial lands, public or private lands, franchises,
easements or lands owned in fee, will reduce and manage this risk. For the purpose of the
standard the term “public lands” includes municipal lands, village lands, city lands, and a host of
other governmental entities.
6
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
The standard addresses vegetation management along applicable overhead lines and does not
apply to underground lines, submarine lines or to line sections inside an electric station
boundary.
The standard focuses on transmission lines to prevent those vegetation related outages that
could lead to Cascading. It is not intended to prevent customer outages due to tree contact
with lower voltage distribution system lines. For example, localized customer service might be
disrupted if vegetation were to make contact with a 69kV transmission line supplying power to
a 12kV distribution station. However, this standard is not written to address such isolated
situations which have little impact on the overall electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses an
increased outage risk, especially when numerous transmission lines are operating at or near
their Rating. This can present a significant risk of consecutive line failures when lines are
experiencing large sags thereby leading to Cascading. Once the first line fails the shift of the
current to the other lines and/or the increasing system loads will lead to the second and
subsequent line failures as contact to the vegetation under those lines occurs. Conversely,
most other outage causes (such as trees falling into lines, lightning, animals, motor vehicles,
etc.) are not an interrelated function of the shift of currents or the increasing system loading.
These events are not any more likely to occur during heavy system loads than any other time.
There is no cause-effect relationship which creates the probability of simultaneous occurrence
of other such events. Therefore these types of events are highly unlikely to cause large-scale
grid failures. Thus, this standard places the highest priority on the management of vegetation
to prevent vegetation grow-ins.
The drafting team reviewed and edited version 1 of FAC-003-1 to remove prescriptive and
administrative language in order to distill the technical requirements down to their essential
reliability content. Explanatory text is offered within two special sections, Background and
Guideline and Technical Basis, to aid in understanding the standard and its requirements.
Rationale text boxes and other text boxes are also inserted throughout the standard to aid
understanding the sections. The Effective Dates section covers five special cases for lines that
undergo specific transitions as or after the standard has reached the general effective date.
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
7
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Preface
The NERC Vegetation Management Standard Drafting Team (VM SDT) acknowledges those
across the industry who contributed to the development of this Standard and companion
Technical Reference document. This Technical Reference document is intended to provide
supplemental explanatory background and guidance related to requirements contained in the
Standard but does not in itself contain requirements subject to compliance review.
The Standard requires the Transmission Owner to have documentation of the maintenance
strategies or procedures or processes or specifications it uses to be successful in managing
vegetation. This allows the Transmission Owner to exercise substantial flexibility in designing
its overall program to meet its specific needs provided that the Transmission Owner also meets
the purpose of the Standard.
While there are many approaches to vegetation management, the VMSDT supports industry
best practices contained in ANSI A300 (Part 7) – Integrated Vegetation Management (IVM)
practices on Utility Rights-of-way, as well as the companion publication Best Management
Practices – Integrated Vegetation Management, as an effective strategy to maintain compliance
with this Standard. ANSI A300 (Part 7), approved by industry consensus in 2006, contains many
elements needed for an effective vegetation management. Those elements are similar to the
requirements in this Standard. One key element is the “wire zone – border zone” concept.
Supported by over 50 years of continuous research, wire zone – border zone is a proven
method to manage vegetation on transmission rights-of-ways and is an industry accepted best
practice to help ensure electric system reliability.
The VM SDT believes that Transmission Owners who adopt and effectively implement IVM
principles, particularly the “wire zone – border zone” concept, are far less likely to experience a
vegetation caused outage than those who do not.
8
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Effective Dates & Special States of Transition
The first sentence of the Effective Dates section is standard language used in most NERC
standards to cover the general effective date and is sufficient to cover the vast majority of
situations. Five special cases are needed to cover effective dates for individual lines which
undergo transitions after the general effective date. These special cases cover the effective
dates for those lines which are initially becoming subject to the standard, those lines which are
changing their applicability within the standard, and those lines which are changing in a manner
that removes their applicability to the standard. The text for each of these five cases is copied
from the standard and is shown below in italic font. An explanation of the need for each special
exception follows each copied text section.
1. A line operated below 200kV, designated by the Planning Coordinator as an element
of an Interconnection Reliability Operating Limit (IROL) or designated by the Western
Electricity Coordinating Council (WECC) as an element of a Major WECC Transfer
Path, becomes subject to this standard the latter of: 1) 12 months after the date the
Planning Coordinator or WECC initially designates the line as being an element of an
IROL or an element of a Major WECC Transfer Path, or 2) January 1 of the planning
year when the line is forecast to become an element of an IROL or an element of a
Major WECC Transfer Path.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to
become elements of an IROL or Major WECC Transfer Path in a future Planning Year (PY). For
example, studies by the Planning Coordinator in 2011 may identify a line to have that
designation beginning in PY 2021, ten years after the planning study is performed. It is not
intended for the Standard to be immediately applicable to, or in effective for, that line until that
future PY begins. The effective date provision for such lines ensures that the line will become
subject to the standard on the January 1 of the PY specified with an allowance of at least 12
months for the Transmission Owner to make the necessary preparations to achieve compliance
on that line. The table below has some explanatory examples of the application.
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
9
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Date that
Planning Study is
completed
PY the line
will become
an IROL
element
Date 1
Date 2
The latter of Date 1
or Date 2
05/15/2011
2012
05/15/2012
01/01/2012
05/15/2012
05/15/2011
2013
05/15/2012
01/01/2013
01/01/2013
05/15/2011
2014
05/15/2012
01/01/2014
01/01/2014
05/15/2011
2021
05/15/2012
01/01/2021
01/01/2021
Effective Date
2. A line operated below 200 kV currently subject to this standard as a designated
element of an IROL or a Major WECC Transfer Path which has a specified date for the
removal of such designation will no longer be subject to this standard effective on
that specified date.
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or
Major WECC Transfer Path may be removed from that designation due to system
improvements, changes in generation, changes in loads or changes in studies and analysis of
the network.
3. A line operated at 200 kV or above, currently subject to this standard which is a
designated element of an IROL or a Major WECC Transfer Path and which has a
specified date for the removal of such designation will be subject to Requirement R2
and no longer be subject to Requirement R1 effective on that specified date
Case 3 is needed because a line operating at 200 kV or above that once was designated as an
element of an IROL or Major WECC Transfer Path may be removed from that designation due to
system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network. Such changes result in the need to apply R1 to that line until that date
is reached and then to apply R2 to that line thereafter.
4. An existing transmission line operated at 200kV or higher which is newly acquired by
an asset owner and which was not previously subject to this standard becomes
subject to this standard 12 months after the acquisition date.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be
acquired by a Transmission Owner from a third party such as a Distribution Provider or other
end-user who was using the line solely for local distribution purposes, but the Transmission
owner, upon acquisition, is incorporating the line into the interconnected electrical energy
transmission network which will thereafter make the line subject to the standard.
10
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
5. An existing transmission line operated below 200kV which is newly acquired by an
asset owner and which was not previously subject to this standard becomes subject
to this standard 12 months after the acquisition date of the line if at the time of
acquisition the line is designated by the Planning Coordinator as an element of an
IROL or by WECC as an element of a Major WECC Transfer Path.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by a
Transmission Owner from a third party such as a Distribution Provider or other end-user who
was using the line solely for local distribution purposes, but the Transmission owner, upon
acquisition, is incorporating the line into the interconnected electrical energy transmission
network. In this special case the line upon acquisition was designated as an element of an
Interconnection Reliability Operating Limit (IROL) or an element of a Major WECC transfer Path.
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
11
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Definition of Terms
Right-of-Way (ROW)*
The corridor of land under a transmission line(s)
The current glossary definition of this NERC
needed to operate the line(s). The width of the
term is modified to address the issues set forth
corridor is established by engineering or
in Paragraph 734 of FERC Order 693.
construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout
standard in effect when the line was built. The ROW width in no case exceeds the Transmission
Owner’s legal rights but may be less based on the aforementioned criteria.
The current NERC glossary definition of Right of Way has been modified to address the matter
set forth in Paragraph 734 of FERC Order 693. The Order pointed out that Transmission Owners
may in some cases own more property or rights than are needed to reliably operate
transmission lines. This modified definition represents a slight but significant departure from
the strict legal definition of “right of way” in that this definition is based on engineering and
construction considerations that establish the width of a corridor from a technical basis. The
pre-2007 maintenance records are included to allow the use of such vegetation widths if there
were no engineering or construction standards that referenced the width of right of way to be
maintained for vegetation on a particular line but the evidence exists in maintenance records
for a width that was in fact maintained prior to this standard becoming mandatory. Such
widths may be the only information available for lines that had limited or no vegetation
easement rights and were typically maintained primarily to ensure public safety. This standard
does not require additional easement rights to be purchased to satisfy a minimum right of way
width that did not exist prior to this standard becoming mandatory.
This definition does not imply that danger tree rights beyond the constructed and maintained
width are incorporated in the definition; therefore fall-ins from outside the ROW but within an
area with danger tree rights would not be considered fall-ins from within the ROW.
Vegetation Inspection*
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the Transmission Owner’s control
that are likely to pose a hazard to the line(s) prior
to the next planned maintenance or inspection. This
may be combined with a general line inspection.
The inspection includes the identification of any
vegetation that may pose a threat to reliability
12
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
prior to the next planned maintenance or inspection work, considering the current location of
the conductor and other possible locations of the conductor due to sag and sway for rated
conditions.
This definition allows both maintenance inspections and vegetation inspections to be
performed concurrently.
* This is a modification to a defined term in the NERC glossary and will be incorporated into the
NERC glossary of terms with final approval of this standard revision.
See the Guidelines and Technical Basis section on Requirement R6 contained within the
Standard for more details on inspections.
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a
method has been in the design of high voltage transmission lines. Keeping vegetation away
from high voltage conductors by this distance will prevent voltage flash-over to the vegetation.
See the explanatory text below for Requirement R3 and associated Figures 1, 2 and 3. Details
of the equations and an example calculation are provided in Appendix 1below of the Technical
Reference document. Table 1in Appendix 1 below provides MVCD values for various voltages
and altitudes.
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
13
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Applicability of the Standard
4. Applicability
4.1. Functional Entities:
Transmission Owners
4.2. Facilities: Defined below (referred to as “applicable lines”), including but not
limited to those that cross lands owned by federal 1, state, provincial, public,
private, or tribal entities:
4.2.1 Each overhead transmission lines operated at 200kV or higher.
4.2.2 Each overhead transmission lines operated below 200kV identified as an
element of an IROL under NERC Standard FAC-014 by the Planning
Coordinator.
4.2.3 Each overhead transmission lines operated below 200 kV identified as an
element of a Major WECC Transfer Paths in the Bulk Electric System by
WECC.
Rationale
4.2.4 Each overhead transmission
The areas excluded in 4.2.4 were excluded based
line identified above (4.2.1
on comments from industry for reasons
through 4.2.3) located
summarized as follows: 1) There is a very low risk
outside the fenced area of
from vegetation in this area. Based on an informal
the switchyard, station or
survey, no TOs reported such an event. 2)
substation and any portion of
Substations, switchyards, and stations have many
the span of the transmission
inspection and maintenance activities that are
line that is crossing the
necessary for reliability. Those existing process
manage the threat. As such, the formal steps in this
substation fence.
4.3. Enforcement: The reliability
obligations of the applicable entities
and facilities are contained within
the technical requirements of this
standard
standard are not well suited for this environment.
3) NERC has a project in place to address at a later
date the applicability of this standard to
Generation Owners. 4) Specifically addressing the
areas where the standard does and does not apply
makes the standard clearer.
In Order 693, FERC discussed the 200 kV bright-line test of applicability. While FERC did not
change the 200 kV bright-line, the Commission remained concerned that there may be some
transmission lines operating at lesser voltages that could have significant impact on the Bulk
Electric System that should therefore be subject to this standard.
1
EPAct 2005 section 1211c: “Access approvals by Federal agencies”.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
NERC Standard FAC-014 has the stated purpose, “To ensure that System Operating Limits (SOLs)
used in the reliable planning and operation of the Bulk Electric System (BES) are determined
based on an established methodology or methodologies.” FAC-014 requires Reliability
Coordinators, Planning Coordinators, and Transmission Planners to have a methodology to
identify all lines that might comprise an IROL. Thus, these entities would identify sub-200 kV
lines that qualify as part of an IROL and should be subject to FAC-003-2.
Although all three entities may prepare the list of elements, the list as provided by the Planning
Coordinator function is the more appropriate choice for this Standard. The Time Horizon
needed to plan vegetation management work does not lend itself to the operating horizon of a
Reliability Coordinator. Additionally, the Planning Coordinator has a wider-area view than the
Transmission Planner and could thus identify any elements of importance to a sub-set of its
area that might be missed by a Transmission Planner.
Transmission Owners, who do not already get the list of circuits included in the definition of an
IROL, can get them from the Planning Coordinator. Specifically R5 of FAC-014 specifies that
“The Reliability Coordinator, Planning Authority (Coordinator) and Transmission Planner shall
each provide its SOLs and IROLs to those entities that have a reliability-related need for those
limits and provide a written request that includes a schedule for delivery of those limits”
Vegetation-related Sustained Outages that occur due to natural disasters are beyond the
control of the Transmission Owner. These events are not classified as vegetation-related
Sustained Outages and are therefore exempt from the Standard. Transmission lines are not
designed to withstand the impacts of natural disasters such as flood, drought, earthquake,
major storms, fire, hurricane, tornado, landslides, ice storms, etc. In the aftermath of
catastrophic system damage from natural disasters the Transmission Owner’s focus is on
electric system restoration for public safety and critical support infrastructure.
Sustained Outages due to human or animal activity are beyond the control of the Transmission
Owner. These outages are not classified as vegetation-related Sustained Outages and are
therefore exempt from the Standard. Examples of these events may include new plantings by
outside parties of tall vegetation under the transmission line planted since the last Vegetation
Inspection, tree contacts with line initiated by vehicles, logging activities, etc.
The foregoing exemptions are addressed in a new footnote 2. Referred to collectively as force
majeure events and activities, this footnote applies to requirements R1 and R2 in FAC-003-2.
The reliability objective of this NERC Vegetation Management Standard (“Standard”) is to
prevent vegetation-related outages which could lead to Cascading by effective vegetation
maintenance while recognizing that certain outages such as those due to vandalism, human
errors and acts of nature are not preventable. Operating experience clearly indicates that trees
that have grown out of specification could contribute to a cascading grid failure, especially
under heavy electrical loading conditions.
Serious outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations. To
properly reduce and manage this risk, it is necessary to apply the Standard to applicable lines
on any kind of land or easement, whether they are Federal Lands, state or provincial lands,
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
public or private lands, franchises, easements or lands owned in fee. For the purposes of the
Standard and this Technical Reference document, the term “public lands” includes municipal
lands, village lands, city lands, and land owned by a host of other governmental entities.
The Standard addresses vegetation management along applicable overhead lines that serve to
connect one electric station to another. However, it is not intended to be applied to lines
sections inside the electric station fence or other boundary of an electric station, submarine or
underground lines.
The Standard is intended to reduce the risk of Cascading involving vegetation. It is not intended
to prevent customer outages from occurring due to tree contact with all transmission lines and
voltages. For example, localized customer service might be disrupted if vegetation were to
make contact with a 69kV transmission line supplying power to a 12kV distribution station.
However, this Standard is not written to address such isolated situations which have little
impact on the overall Bulk Electric System.
Vegetation growth is constant and always present. Unmanaged vegetation below numerous
transmission lines that are operating at or near their Rating is highly problematic. This situation
has led to multiple subsequent line failures and Cascading. Conversely, most other outage
causes (such as trees falling into lines, lightning, animals, motor vehicles, etc.) are statistically
intermittent. These events are not any more likely to occur during heavy system loads than any
other time. There is no cause-effect relationship which creates the probability of simultaneous
occurrence of other such events. Therefore these types of events are highly unlikely to cause
large-scale grid failures. Thus, this Standard’s emphasis is on vegetation grow-ins.
In preparing the original vegetation management standard in 2005, industry stakeholders set
the threshold for applicability of the standard at 200kV. This was because an unexpected loss
of lines operating at above 200kV has a higher probability of initiating a widespread blackout or
cascading outages compared with lines operating at less than 200kV.
The original NERC Standard FAC-003-1 also allowed for application of the standard to “critical”
circuits (critical from the perspective of initiating widespread blackouts or cascading outages)
operating below 200kV. While the percentage of these circuits is relatively low, it remains a
fact that there are sub-200kV circuits whose loss could contribute to a widespread outage.
Given the very limited exposure and unlikelihood of a major event related to these lowervoltage lines, it would be an imprudent use of resources to apply the Standard to all sub-200kV
lines. The drafting team, after evaluating several alternatives, selected the IROL and WECC
Major Transfer Path criteria to determine applicable lines below 200 kV that are subject to this
standard.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Requirements R1 and R2
R1. Each Transmission Owner shall manage
vegetation to prevent encroachments into
the Minimum Vegetation Clearance
Distance (MVCD) of its applicable line(s)
which are either an element of an IROL, or
an element of a Major WECC Transfer
Path; operating within its Rating and all
Rated Electrical Operating Conditions of
the types shown below 2:
1. An encroachment into the MVCD as
shown in FAC-003-Table 2, observed
in Real-time, absent a Sustained
Outage 3,
2. An encroachment due to a fall-in from
inside the Right-of-Way (ROW) that
caused a vegetation-related Sustained
Outage 4,
3. An encroachment due to the blowing
together of applicable lines and
vegetation located inside the ROW
that caused a vegetation-related
Sustained Outage4,
4. An encroachment due to vegetation
growth into the MVCD that caused a
vegetation-related Sustained Outage4.
R2. Each Transmission Owner shall manage
vegetation to prevent encroachments into
the MVCD of its applicable line(s) which
are not either an element of an IROL, or
an element of a Major WECC Transfer
2
Rationale for R1 and R2:
Lines with the highest significance to
reliability are covered in R1; all other lines are
covered in R2.
Ra tio n a le fo r th e typ e s o f fa ilu re to
m a n a g e ve g e ta tio n wh ic h a re lis te d in
o rd e r o f in c re a s in g de g re e s o f s e ve rity
in n o n -c o m p lia n t p e rfo rm a n c e a s it
re la te s to a fa ilu re o f a Tra n s m is s io n
Owne r's ve g e ta tio n m a in te n a n c e
p ro g ra m :
1. This management failure is found by
routine inspection or Fault event
investigation, and is normally symptomatic of
unusual conditions in an otherwise sound
program.
2. This management failure occurs when the
height and location of a side tree within the
ROW is not adequately addressed by the
program.
3. This management failure occurs when side
growth is not adequately addressed and may
be indicative of an unsound program.
4. This management failure is usually
indicative of a program that is not addressing
the most fundamental dynamic of vegetation
management, (i.e. a grow-in under the line).
If this type of failure is pervasive on multiple
lines, it provides a mechanism for a Cascade.
This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to this reliability standard,
including natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either
by the Transmission Owner or an applicable regulatory body, ice storms, and floods; human or animal activity such as logging, animal
severing tree, vehicle contact with tree, or installation, removal, or digging of vegetation. Nothing in this footnote should be construed to
limit the Transmission Owner’s right to exercise its full legal rights on the ROW.
3
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation encroachment within the MVCD has occurred from
vegetation within the ROW, this shall be considered the equivalent of a Real-time observation.
4
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage regardless of the actual
number of outages within a 24-hour period.
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Path; operating within its Rating and all Rated Electrical Operating Conditions of the types
shown below2:
1. An encroachment into the MVCD as shown in FAC-003-Table 2, observed in Real-time,
absent a Sustained Outage3,
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage4,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage4,
4. An encroachment due to vegetation growth into the MVCD that caused a vegetationrelated Sustained Outage4
M1. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-time observations of any MVCD encroachments. (R1)
M2. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R2. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-time observations of any MVCD encroachments. (R2)
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the prevention of vegetation encroachments within a minimum distance of
transmission lines. Content-wise, R1 and R2 are the same requirements; however, they apply to
different Facilities. Both R1 and R2 require each Transmission Owner to manage vegetation to
prevent encroachment within the MVCD of transmission lines. R1 is applicable to lines that are
identified as an element of an IROL or Major WECC transfer path. R2 is applicable to all other
lines that are not an element of an IROL, and not an element of a Major WECC Transfer Path.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation
management for an applicable line that is an element of an IROL or Major WECC Transfer Path
is a greater risk to the interconnected electric transmission system than applicable lines that
are not an element of an IROL or a Major WECC Transfer Path. Applicable lines that are not an
element of an IROL or Major WECC Transfer Path do require effective vegetation management,
but these lines are comparatively less operationally significant. As a reflection of this difference
in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and Medium for R2.
R1 and R2 state that if vegetation encroaches within the distances in Table 1 in Appendix 1 of
this supplemental Technical Reference document, it is in violation of the standard. Table
1below, which is the same as Table 2 in the standard, tabulates the distances necessary to
prevent spark-over based on the Gallet equations as described more fully in Appendix 1 below.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating and
Rated Electrical Operating Condition (potentially in violation of other standards), the
occurrence of a clearance encroachment may occur solely due to that condition. For example,
emergency actions taken by a Transmission Operator or Reliability Coordinator to protect an
Interconnection may cause excessive sagging and an outage. Another example would be ice
loading beyond the line’s Rating and Rated Electrical Operating Condition. Such vegetationrelated encroachments and outages are not violations of this standard.
Evidence of failures to adequately manage vegetation include real-time observation of a
vegetation encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related
encroachment resulting in a Sustained Outage due to a fall-in from inside the ROW, or a
vegetation-related encroachment resulting in a Sustained Outage due to the blowing together
of the lines and vegetation located inside the ROW, or a vegetation-related encroachment
resulting in a Sustained Outage due to a grow-in. Faults which do not cause a Sustained outage
and which are confirmed to have been caused by vegetation encroachment within the MVCD
are considered the equivalent of a Real-time observation for violation severity levels.
With this approach, the VSLs for R1 and R2 are structured such that they directly correlate to
the severity of a failure of a Transmission Owner to manage vegetation and to the
corresponding performance level of the Transmission Owner’s vegetation program’s ability to
meet the objective of “preventing the risk of those vegetation related outages that could lead
to Cascading.” Thus violation severity increases with a Transmission Owner’s inability to meet
this goal and its potential of leading to a Cascading event. The additional benefits of such a
combination are that it simplifies the standard and clearly defines performance for compliance.
A performance-based requirement of this nature will promote high quality, cost effective
vegetation management programs that will deliver the overall end result of improved reliability
to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For
example initial investigations and corrective actions may not identify and remove the actual
outage cause then another outage occurs after the line is re-energized and previous high
conductor temperatures return. Such events are considered to be a single vegetation-related
Sustained Outage under the standard where the Sustained Outages occur within a 24 hour
period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over,
for various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will prevent transmission outages.
If the TO has applicable lines operated at nominal voltage levels not listed in Table 2, then the
TO should use the next largest clearance distance based on the next highest nominal voltage in
the table to determine an acceptable distance.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Requirement R3
R3. Each Transmission Owner shall have
documented maintenance strategies or
procedures or processes or specifications it
uses to prevent the encroachment of
vegetation into the MVCD of its applicable
transmission lines that accounts for the
following:
3.1 Movement of applicable line
conductors under their Facility Rating
and all Rated Electrical Operating
Conditions;
Rationale
The documentation provides a basis for
evaluating the competency of the
Transmission Owner’s vegetation program.
There may be many acceptable approaches
to maintain clearances. Any approach must
demonstrate that the Transmission Owner
avoids vegetation-to-wire conflicts under all
Rated Electrical Operating Conditions. See
Figure 1 for an illustration of possible
conductor locations.
3.2 Inter-relationships between vegetation growth rates, vegetation
control methods, and inspection frequency.
M3. The maintenance strategies or procedures or processes or specifications
provided demonstrate that the Transmission Owner can prevent encroachment
into the MVCD considering the factors identified in the requirement. (R3)
Requirement R3 is a competency based requirement concerned with the maintenance
strategies, procedures, processes, or specifications, a Transmission Owner uses for vegetation
management.
An adequate transmission vegetation management program formally establishes the approach
the Transmission Owner uses to plan and perform vegetation work to prevent transmission
Sustained Outages and minimize risk to the transmission system. The approach provides the
basis for evaluating the intent, allocation of appropriate resources and the competency of the
Transmission Owner in managing vegetation. There are many acceptable approaches to
manage vegetation and avoid Sustained Outages. However, the Transmission Owner must be
able to show the documentation of its approach and how it conducts work to maintain
clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach a
Transmission Owner chooses to use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance
or maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the Transmission Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing in reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figures 1, 2, and 3 below.
Conductor Dynamics
In order for a Transmission Owner to develop a specific maintenance approach, it is important
to understand the dynamics of a line conductor’s movements. This paper will first address the
complexities inherent in observing and predicting conductor movement, particularly for field
personnel. It will then present some examples of maintenance approaches which Transmission
Owners may consider that take into account these complexities, and the practical approaches
that can be utilized by field personnel.
Additionally, it is important the Transmission Owner consider all conductor locations, the
MVCD, and vegetation growth between maintenance activities when developing a maintenance
approach.
Understanding Conductor Position and Movement
The conductor’s position in space at any point in time is continuously changing as a reaction to
a number of different loading variables. Changes in vertical and horizontal conductor
positioning are the result of thermal and physical loads applied to the line. Thermal loading is a
function of line current and the combination of numerous variables influencing ambient heat
dissipation including wind velocity/direction, ambient air temperature and precipitation.
Physical loading applied to the conductor affects sag and sway by combining physical factors
such as ice and wind loading.
As a consequence of these loading variables, the conductor’s position in space is dynamic and
moving. When calculating the range of conductor positions, the Transmission Owner should use
the same design criteria and assumptions that are used to establish Ratings and System
Operating Limits (SOLs), as described in other standards. Typically, the greatest conductor
movements occur at mid-span. As the conductor moves through various positions, a spark-over
zone surrounding the conductor moves with it. The radius of the spark-over zone may be found
by referring to Table 1 below. For illustrations of this zone and conductor movements, Figures
1, 2 and 3 below are provided. At the time of making a field observation, however, it is very
difficult to precisely know where the conductor is in relation to its wide range of all possible
positions. Therefore, Transmission Owners must adopt maintenance approaches that account
for this dynamic situation.
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Figure 1
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Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Figure 2
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Figure 3
A cross-section view of a single conductor at a given point along the span is
shown with six possible conductor positions due to movement resulting from
thermal and mechanical loading.
Selecting a Maintenance Approach
In order to maintain adequate separation between vegetation and transmission line
conductors, the Transmission Owner must craft a maintenance strategy that keeps vegetation
well away from the spark-over zone mentioned above. In fact, it is generally necessary to
incorporate a variety of maintenance strategies. For example, one Transmission Owner may
utilize a combination of routine cycles, traditional IVM techniques and long-term planning.
Another Transmission Owner may place a higher reliance on frequent inspections and follow-up
remediation as opposed to a set cyclical approach. This variation of approaches is further
warranted when factors, such as terrain, vegetation types, weather and climate, and any,
environmental, legal or other land use constraints, must be considered in developing a
Transmission Owner’s specific approach to satisfying R3.
The following describes some strategies which may be utilized by a Transmission Owner. A
Transmission Owner’s basic maintenance approach in relatively flat terrain could be to remove
all incompatible vegetation from the ROW if it has the right to do so and has no constraints. In
mountainous terrain, however, this strategy could change to managing vegetation based on
vegetation-to-conductor clearances, since it might not be necessary to remove vegetation in a
valley that is far below the conductors at maximum sag.
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If faced with easement constraints on a line design with sufficient ground clearance, the
approach could be to allow vegetation such as fruit trees, but only up to a given height at
maturity (for example 10 feet from the ground). If constraints cannot be overcome and if design
clearances are sufficient, an exception to the Transmission Owner’s 10-foot guideline might be
made. If an approach is chosen to manage vegetation based primarily on clearance distances it
could include an inspection regimen to regularly ensure that impending clearance problems are
identified early for rectification.
ANSI A3 0 0 – Be s t Ma n a g e m e n t Pra ct ice s fo r Tr e e Ca r e Op e r a t io n s
A description of ANSI A-300, part 7, is offered below to illustrate another maintenance
approach that could be used in developing a comprehensive transmission vegetation
management program.
Introduction
Integrated Vegetation Management (IVM) is a best management practice conveyed in the
American National Standard for Tree Care Operations, Part 7 (ANSI 2006) and the International
Society of Arboriculture Best Management Practices: Integrated Vegetation Management
(Miller 2007). IVM is consistent with the requirements in FAC-003-02, and it provides
practitioners with what industry experts consider to be appropriate techniques to apply to
electric right-of-way projects in order to meet or exceed the Standard.
IVM is a system of managing plant communities whereby managers set objectives; identify
compatible and incompatible vegetation; consider action thresholds; and evaluate, select and
implement the most appropriate control method or methods to achieve set objectives. The
choice of control method or methods should be based on the environmental impact and
anticipated effectiveness; along with site characteristics, security, economics, current land use
and other factors.
Planning and Implementation
Best management practices provide a systematic way of planning and implementing a
vegetation management program. While designed primarily with transmission systems in mind,
it is also applicable to distribution projects. As presented in ANSI A300 part 7 and the ISA best
management practices, IVM consists of 6 elements:
1)
2)
3)
4)
5)
6)
Set Objectives
Evaluate the Site
Define Action Thresholds
Evaluate and Select Control Methods
Implement IVM
Monitor Treatment and Quality Assurance
The setting of objectives, defining action thresholds, and evaluating and selecting control
methods all require decisions. The planning and implementation process is cyclical and
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
continuous, because vegetation is dynamic and managers must have the flexibility to adjust
their plans. Adjustments may be made at each stage as new information becomes available
and circumstances evolve.
Set Objectives
Objectives should be clearly defined and documented. Examples of objectives can
include promoting safety, preventing sustained outages caused by vegetation growing
into electric facilities, maintaining regulatory compliance, protecting structures and
security, restoring electric service during emergencies, maintaining access and clear
lines of sight, protecting the environment, and facilitating cost effectiveness.
Objectives should be based on site factors, such as workload and vegetation type, in
addition to human, equipment and financial resources. They will vary from utility to
utility and project to project, depending on line voltage and criticality, as well as
topographical, environmental, fiscal and political considerations. However, where it is
appropriate, the overriding focus should be on environmentally-sound, cost effective
control of species that potentially conflict with the electric facility, while promoting
compatible, early successional, sustainable plant communities.
Work Load Evaluations
Work-load evaluations are inventories of vegetation that could have a bearing on
management objectives. Work load assessments can capture a variety of vegetation
characteristics, such as location, height, species, size and condition, hazard status,
density and clearance from conductors. Assessments should be conducted considering
voltage, conductor sag from ambient temperatures and loading, and the potential
influence of wind on line sway.
Evaluate and Select Control Methods
Control methods are the process through which managers achieve objectives. The most
suitable control method best achieves management objectives at a particular site. Many
cases call for a combination of methods. Managers have a variety of controls from
which to choose, including manual, mechanical, herbicide and tree growth regulators,
biological, and cultural options.
Manual Control Methods
Manual methods employ workers with hand-carried tools, including chainsaws,
handsaws, pruning shears and other devices to control incompatible vegetation. The
advantage of manual techniques is that they are selective and can be used where others
may not be. On the other hand, manual techniques can be inefficient and expensive
compared to other methods.
Mechanical Control Methods
Mechanical controls are done with machines. They are efficient and cost effective,
particularly for clearing dense vegetation during initial establishment, or reclaiming
neglected or overgrown right of way. On the other hand, mechanical control methods
can be non-selective and disturb sensitive sites.
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Tree Growth Regulator and Herbicide Control Methods
Tree growth regulators and herbicides can be effective for vegetation management.
Tree growth regulators (TGRs) are designed to reduce growth rates by interfering with
natural plant processes. TGRs can be helpful where removals are prohibited or
impractical by reducing the growth rates of some fast-growing species.
Herbicides control plants by interfering with specific botanical biochemical pathways.
Herbicide use can control individual plants that are prone to re-sprout or sucker after
removal. When trees that re-sprout or sucker are removed without herbicide treatment,
dense thickets develop, impeding access, swelling workloads, increasing costs, blocking
lines-of-site, and deteriorating wildlife habitat. Treating suckering plants allows early
successional, compatible species to dominate the right-of-way and out-compete
incompatible species, ultimately reducing work.
Cultural Control Methods
Cultural methods modify habitat to discourage incompatible vegetation and establish
and manage desirable, early successional plant communities. Cultural methods take
advantage of seed banks of native, compatible species lying dormant on site. In the long
run, cultural control is the most desirable method where it is applicable.
A cultural control known as cover-type conversion provides a competitive advantage to
short-growing, early successional plants, allowing them to thrive and eventually outcompete unwanted tree species for sunlight, essential elements and water. The early
successional plant community is relatively stable, tree-resistant and reduces the amount
of work, including herbicide application, with each successive treatment.
Wire-Border Zone
The wire-border zone technique is a management philosophy that can be applied
through cultural control. W.C. Bramble and W.R. Byrnes developed it in the mid-1980s
out of research begun in 1952 on a transmission right-of-way in the Pennsylvania State
Game Lands 33 Research and Demonstration project (Yahner and Hutnik (2004).
The wire zone is the section of a utility transmission right-of-way directly under the
wires and extending outward about 10 feet on each side. The wire zone is managed to
promote a low-growing plant community dominated by grasses, herbs and small shrubs
(under 3 feet in height at maturity). The border zone is the remainder of the right-ofway. It is managed to establish small trees and tall shrubs (under 25 feet in height at
maturity). When properly managed, diverse, tree-resistant plant communities develop
in wire and border zones. The communities not only protect the electric facility and
reduce long-term maintenance, but also enhance wildlife habitat, forest ecology and
aesthetic values.
Although the wire-border zone is a best practice in many instances, it is not necessarily
universally suitable. For example, standard wire-border zone prescriptions may be
unnecessary where lines are high off the ground, such as across low valleys or canyons,
so the technique can be modified without sacrificing reliability.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
One way to accommodate variances in topography is to establish different regions
based on wire height. For example, over canyon bottoms or other areas where
conductors are 100 feet or more above the ground, only a few trees are likely to be tall
enough to conflict with the lines. In those cases, trees that potentially interfere with the
transmission lines can be removed selectively on a case-by-case basis.
In areas where the wire is lower, perhaps between 50-100 feet from the ground, a
border zone community can be developed throughout the right-of-way. Note that in
many cases, conductor attachment points are more than 50 feet off the ground, so a
border zone community can be cultivated near structures. Where the line is less than
50 feet off the ground, managers could apply a full wire-border zone prescription.
An environmental advantage of this type of modification is stream protection. Streams
often course through the valleys and canyons where lines are likely to be elevated.
Leaving timber or border zone communities in canyon bottoms helps shelter this
valuable habitat, enabling managers to achieve environmentally sensitive objectives.
Implement IVM
All laws and regulations governing IVM practices and specifications written by qualified
vegetation managers must be followed. Integrated vegetation management control
methods should be implemented on regular work schedules, which are based on
established objectives and completed assessments. Work should progress systematically,
using control measures determined to be best for varying conditions at specific locations
along a right-of-way. Some considerations used in developing schedules include the
importance and type of line, vegetation clearances, workloads, growth rate of
predominant vegetation, geography, accessibility, and in some cases, time lapsed since
the last scheduled work.
Clearances Following Work
Clearances following work should be sufficient to meet management objectives,
including preventing trees from entering the Minimum Vegetation Clearance Distance,
electric safety risks, service-reliability threats and cost.
Monitor Treatment and Quality Assurance
An effective program includes documented processes to evaluate results. Evaluations
can involve quality assurance while work is underway and after it is completed.
Monitoring for quality assurance should begin early to correct any possible
miscommunication or misunderstanding on the part of crewmembers. Early and
consistent observation and evaluation also provides an opportunity to modify the plan,
if need be, in time for a successful outcome.
Utility vegetation management programs should have systems and procedures in place
for documenting and verifying that vegetation management work was completed to
specifications. Post-control reviews can be comprehensive or based on a statistically
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
representative sample. This final review points back to the first step and the planning
process begins again.
Summary of A-300 example
Integrated Vegetation Management offers among others, a systematic way of planning and
implementing a vegetation management program as presented in ANSI A300 Part 7. This
methodology enables a program to comply with the NERC Transmission Vegetation
Management Program standard (FAC-003-2). Managers should select control options to best
promote management objectives.
Vegetation Inspections
The standard in R6 establishes the frequency of vegetation inspections. These inspections can
be used to “evaluate the site” as referred to in the second element of ANSI A300 Part 7. This
necessary frequency may need to be less than the annually based on anticipated growth rates
of the local vegetation, length of the growing season for the geographical area, limited ROW
width, rainfall amounts, etc.
Annual Work Plan
Requirement R7 of the Standard addresses the execution of the annual work plan. A
comprehensive approach that exercises the full extent of legal rights is superior to incremental
management in the long term because it reduces overall encroachments, and it ensures that
future planned work and future planned inspection cycles are sufficient at all locations on the
ROW. Removal is superior to pruning. Removal minimizes the possibility of conflicts between
energized conductors and vegetation. When this is not possible, the approach should be to use
vegetation maintenance methods to work towards or achieve the maximum use of the ROW.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Requirement R4
R4. Each Transmission Owner, without any
intentional time delay, shall notify the
control center holding switching
authority for the associated applicable
transmission line when the Transmission
Owner has confirmed the existence of a
vegetation condition that is likely to
cause a Fault at any moment.
Rationale
This is to ensure expeditious communication
between the Transmission Owner and the
control center when a critical situation is
confirmed.
M4. Each Transmission Owner that has a confirmed vegetation condition likely to cause a Fault
at any moment will have evidence that it notified the control center holding switching
authority for the associated transmission line without any intentional time delay. Examples
of evidence may include control center logs, voice recordings, switching orders, clearance
orders and subsequent work orders. (R4)
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the
Transmission Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4
involves the notification of potentially threatening vegetation conditions, without any
intentional delay, to the control center holding switching authority for that specific
transmission line. Examples of acceptable unintentional delays may include communication
system problems (for example, cellular service or two-way radio disabled), crews located in
remote field locations with no communication access, delays due to severe weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of a Transmission Owner’s employee who personally identifies such a threat in the
field. Confirmation could also be made by sending out an employee to evaluate a situation
reported by a landowner.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an assessment
of the possible sag or movement of the conductor while operating between no-load conditions
and its rating.
The Transmission Owner has the responsibility to ensure the proper communication between
field personnel and the control center to allow the control center to take the appropriate action
until the vegetation threat is relieved. Appropriate actions may include a temporary reduction
in the line loading, switching the line out of service, or positioning the system in recognition of
the increasing risk of outage on that circuit. The notification of the threat should be
communicated in terms of minutes or hours as opposed to a longer time frame for corrective
action plans (see R5).
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All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some Transmission Owners may have a danger tree identification
program that identifies trees for removal with the potential to fall near the line. These trees
would not require notification to the control center unless they pose an immediate fall-in
threat.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Requirement R5
R5. When a Transmission Owner is constrained
from performing vegetation work on an
applicable line operating within their
Rating and all Rated Electrical Operating
Conditions, and the constraint may lead to
a vegetation encroachment into the MVCD
prior to the implementation of the next
annual work plan, then the Transmission
Owner shall take corrective action to
ensure continued vegetation management
to prevent encroachments.
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
Transmission Owner from performing
planned vegetation maintenance work.
In cases where the transmission line is put at
potential risk due to constraints, the intent
is for the Transmission Owner to put interim
measures in place, rather than do nothing.
The corrective action process is not
M5. Each Transmission Owner has evidence of
intended to address situations where a
the corrective action taken for each
planned work methodology cannot be
constraint where an applicable
performed but an alternate work
transmission line was put at potential
methodology can be used.
risk. Examples of acceptable forms of
evidence may include initially-planned
work orders, documentation of constraints from landowners, court orders, inspection
records of increased monitoring, documentation of the de-rating of lines, revised work
orders, invoices, or evidence that a line was de-energized. (R5)
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
Transmission Owner for the mitigation of Sustained Outage risk when temporarily constrained
from performing vegetation maintenance. The intent of this requirement is to deal with
situations that prevent the Transmission Owner from performing planned vegetation
management work and, as a result, have the potential to put the transmission line at risk.
Constraints to performing vegetation maintenance work as planned could result from legal
injunctions filed by property owners, the discovery of easement stipulations which limit the
Transmission Owner’s rights, or other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
Transmission Owner is not under any immediate time constraint for achieving the management
objective, can easily reschedule work using an alternate approach, and therefore does not need
to take interim corrective action.
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However, in situations where transmission line reliability is potentially at risk due to a
constraint, the Transmission Owner is required to take an interim corrective action to mitigate
the potential risk to the transmission line. A wide range of actions can be taken to address
various situations. General considerations include:
•
Identifying locations where the Transmission Owner is constrained from performing
planned vegetation maintenance work which potentially leaves the transmission line
at risk.
•
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
•
Documenting and tracking the specific action taken for each location.
•
In developing the specific action to mitigate the potential risk to the transmission
line the Transmission Owner could consider location specific measures such as
modifying the inspection and/or maintenance intervals. Where a legal constraint
would not allow any vegetation work, the interim corrective action could include
limiting the loading on the transmission line.
•
The Transmission Owner should document and track the specific corrective action
taken at each location. This location may be indicated as one span, one tree or a
combination of spans on one property where the constraint is considered to be
temporary.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Requirement R6
R6. Each Transmission Owner shall perform a
Vegetation Inspection of 100% of its
applicable lines (measured in units of
choice - circuit, pole line, line miles or
kilometers, etc.) at least once per calendar
year and with no more than 18 months
between inspections on the same ROW. 5
Rationale
Inspections are used by Transmission Owners
to assess the condition of the entire ROW. The
information from the assessment can be used
to determine risk, determine future work and
evaluate recently-completed work. This
requirement sets a minimum Vegetation
Inspection frequency of once per calendar
year but with no more than 18 months
between inspections on the same ROW.
Based upon average growth rates across
North America and on common utility
practice, this minimum frequency is
reasonable. Transmission Owners should
consider local and environmental factors that
could warrant more frequent inspections.
M6. Each Transmission Owner has evidence
that it conducted Vegetation Inspections
of the transmission line ROW for all
applicable lines at least once per calendar
year but with no more than 18 months
between inspections on the same ROW.
Examples of acceptable forms of evidence
may include completed and dated work orders, dated invoices, or dated inspection
records. (R6)
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections that fits general industry practice. In addition, the fact that Vegetation
Inspections can be performed in conjunction with general line inspections further facilitates a
Transmission Owner’s ability to meet this requirement. However, the Transmission Owner may
determine that more frequent inspections are needed to maintain reliability levels, dependent
upon such factors as anticipated growth rates of the local vegetation, length of the growing
season for the geographical area, limited ROW width, and rainfall amounts. Therefore it is
expected that some transmission lines may be designated with a higher frequency of
inspections.
Footnote 5 is added to address the situation where a Transmission Owner through no fault of
its own, would be unable to complete the vegetation inspection within the allotted time period.
This would include the situation of mutual aid as well as disasters to the Transmission Owner’s
own system.
5
When the Transmission Owner is prevented from performing a Vegetation Inspection within the timeframe in R6 due to a natural disaster,
the TO is granted a time extension that is equivalent to the duration of the time the TO was prevented from performing the Vegetation
Inspection.
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The VSL for Requirement R6 has VSL categories ranked by the percentage of the required ROW
inspections completed. To calculate the percentage of inspection completion, the Transmission
Owner may choose units such as: line miles or kilometers, circuit miles or kilometers, pole line
miles, ROW miles, etc.
For example, when a Transmission Owner operates 2,000 miles of applicable transmission lines
this Transmission Owner will be responsible for inspecting all the 2,000 miles of lines at least
once during the calendar year. If one of the included lines was 100 miles long, and if it was not
inspected during the year, then the amount failed to inspect would be 100/2000 = 0.05 or 5%.
The “Low VSL” for R6 would apply in this example.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Requirement R7
R7.
Each Transmission Owner shall complete
Rationale
100% of its annual vegetation work plan
of applicable lines to ensure no
This requirement sets the expectation that
vegetation encroachments occur within
the work identified in the annual work plan
the MVCD. Modifications to the work
will be completed as planned. It allows
plan in response to changing conditions
modifications to the planned work for
or to findings from vegetation inspections
changing conditions, taking into
may be made (provided they do not allow
consideration anticipated growth of
encroachment of vegetation into the
vegetation and all other environmental
MVCD) and must be documented. The
factors, provided that those modifications
percent completed calculation is based on do not put the transmission system at risk of
the number of units actually completed
a vegetation encroachment.
divided by the number of units in the final
amended plan (measured in units of
choice - circuit, pole line, line miles or kilometers, etc.) Examples of reasons for
modification to annual plan may include:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of a Transmission Owner 6
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
M7. Each Transmission Owner has evidence that it completed its annual vegetation work plan.
Examples of acceptable forms of evidence may include a copy of the completed annual
work plan (including modifications if any), dated work orders, dated invoices, or dated
inspection records. (R7)
R7 is a risk-based requirement. The Transmission Owner is required to implement its work plan
for vegetation management to accomplish the purpose of this Standard. Modifications to the
work plan in response to changing conditions or to findings from vegetation inspections may be
made and documented provided they do not put the transmission system at risk. The annual
6
Circumstances that are beyond the control of a Transmission Owner include but are not limited to natural disasters such as earthquakes, fires,
tornados, hurricanes, landslides, ice storms, floods, or major storms as defined either by the TO or an applicable regulatory body.
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work plan requirement is not intended to necessarily require a “span-by-span”, or even a “lineby-line” detailed description of all work to be performed. It is only intended to require that the
Transmission Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation
into the MVCD.
For example, when a Transmission Owner identifies 1,000 miles of applicable transmission lines
to be completed in the TO’s annual plan, the Transmission Owner will be responsible
completing those identified miles. If a TO makes a modification to the annual plan that does
not put the transmission system at risk of an encroachment the annual plan may be modified.
If 100 miles of the annual plan is deferred until next year the calculation to determine what
percentage was completed for the current year would be: 1000 – 100 (deferred miles) = 900
modified annual plan, or 900 / 900 = 100% completed annual miles. If a TO only completed 875
of the total 1000 miles with no acceptable documentation for modification of the annual plan
the calculation for failure to complete the annual plan would be: 1000 – 875 = 125 miles failed
to complete then, 125 miles (not completed) / 1000 total annual plan miles = 12.5% failed to
complete.
The ability to modify the work plan allows the Transmission Owner to change priorities or
treatment methodologies during the year as conditions or situations dictate. For example
recent line inspections may identify unanticipated high priority work, weather conditions
(drought) could make herbicide application ineffective during the plan year, or a major storm
could require redirecting local resources away from planned maintenance or work may be
deferred to a subsequent year because of slower-than-expected growth. This situation may
also include complying with mutual assistance agreements by moving resources off the
Transmission Owner’s system to work on another system. Any of these examples could result
in acceptable deferrals or additions to the annual work plan. Modifications to the annual work
plan must always ensure the reliability of the electric Transmission system.
In general, the vegetation management maintenance approach should use the full extent of the
Transmission Owner’s legal rights on the ROW. A comprehensive approach that exercises the
full extent of legal rights on the ROW is superior to incremental management in the long term
because it reduces the overall potential for encroachments, and it ensures that future planned
work and future planned inspection cycles are sufficient.
When developing the annual work plan the Transmission Owner should allow time for
procedural requirements to obtain permits to work on federal, state, provincial, public, tribal
lands. In some cases the lead time for obtaining permits may necessitate preparing work plans
more than a year prior to work start dates. Transmission Owners may also need to consider
those special landowner requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the Transmission
Owner, evidence of successful annual work plan execution could consist of signed-off work
orders, signed contracts, printouts from work management systems, spreadsheets of planned
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence
may include photographs and walk-through reports.
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Appendix 1: Clearance Distance Derivation by the
Gallet Equation
The Gallet Equation is a well-known method of computing the required strike distance for
proper insulation coordination, and has the ability to take into account various air gap
geometries, as well as non-standard atmospheric conditions. When the Gallet Equation and
conservative probabilistic methods are combined, i.e. deterministic design, spark-over
probabilities of 10-6 or less are achieved. This approach is well known for its conservatism and
was used to design the first 500 kV and 765 kV lines in North America [1]. Thus, the
deterministic design approach using the Gallet Equation is used for the standard to compute
the minimum strike distance between transmission lines and the vegetation that may be
present in or along the transmission corridor.
Method Explanation (Gallet Equation)
In 1975 G. Gallet published a benchmark paper that provided a method to compute the critical
flashover voltage (CFO) of various air gap geometries [4]. The Gallet Equation uses various “gap
factors” to take into account various air gap geometries. Various gap factor values are provided
in [1]. If the vegetation in a transmission corridor, e.g. a tree, is assumed electrically to be a
large structure then the CFO of such an air gap geometry can be computed for dry or wet
conditions using a well established equation proposed by Gallet [1],[2],[4],
CFOA = k w ⋅ k g ⋅ δ m ⋅
3400
8
1+
D
(1)
where,
kw
is defined as the factor that takes into account wet or
dry conditions
(dry = 1.0 and wet = 0.96) and phase arrangement (multiply by 1.08 for outside
phase), e.g. outside phase and wet conditions = (0.96)(1.08) = 1.037,
kg
is defined as the gap factor (1.3 for conductor to large structure),
D
is the strike distance (m),
CFOA
is the CFO for the relative air density (kV).
δ
is defined as the relative air density and is approximately equal to (2) where A
is the altitude in km,
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
δ =e
−
A
8.6
(2)
=
m 1.25G0 ( G0 − 0.2 )
(3)
CFOs
500 ⋅ D
(4)
3400
8
1+
D
(5)
G0 =
CFOs = k w ⋅ k g ⋅
where CFOS is the CFO for standard atmospheric conditions (kV). Using (1)-(5), the required CFOA can be
computed using an iterative process.
Once the CFOA is known, deterministic methods can be used to determine the required
clearance distance. If we let the maximum switching overvoltage be equal to the withstand
voltage of the air gap (CFOA - 3σ) then the CFOA can be written as (6).
CFOA =
Vm
σ
1− 3
CFOA
(6)
where
Vm is equal to the maximum switching overvoltage, i.e. the value that has a 0.135% chance of being
exceeded,
σ is the standard deviation of the air gap insulation,
CFOA is the critical flashover voltage of the air gap insulation under non-standard atmospheric conditions.
The ratio of σ to the CFOA given in (6) can be assumed to be 0.05 (5%) [1]. Thus, (6) can be
written as (7).
CFOA =
Vm
0.85
(7)
Substituting (7) into (1) we arrive at (8).
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ m ⋅
40
3400
8
1+
D
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
(8)
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Equation 8 relates the maximum transient overvoltage, Vm, to the air gap distance, D. Using (8)
to compute the required clearance distance for the specified air gap geometry (conductor to
large structure) results in a probability of flashover in the range of 10-6.
Transient Overvoltage
In general, the worst case transient overvoltages occurring on a transmission line are caused by
energizing or re-energizing the line with the latter being the extreme case if trapped charge is
present. The intent of FAC-003 is to keep a transmission line that is in service from becoming
de-energized (i.e. tripped out) due to sparkover from the line conductor to nearby vegetation.
Thus, the worst case scenarios that are typically analyzed for insulation coordination purposes
(e.g. line energization and re-energization) can be ignored. For the purposes of FAC-003-2, the
worst case transient overvoltage then becomes the maximum value that can occur with the line
energized. Determining a realistic value of transient overvoltage for this situation is difficult
because the maximum transient overvoltage factors listed in the literature are based on a
switching operation of the line in question. In other words, these maximum overvoltage values
(e.g. the values listed in [2], [3] and [5]) are based on the assumption that the subject line is
being energized, re-energized or de-energized. These operations, by their very nature, will
create the largest transient overvoltages. Typical values of transient overvoltages of in-service
lines, as such, are not readily available in the literature because the resulting level of
overvoltage is negligible compared with the maximum (e.g. re-energizing a transmission line
with trapped charge). A conservative value for the maximum transient overvoltage that can
occur anywhere along the length of an in-service ac line is approximately 2.0 p.u.[2]. This value
is a conservative estimate of the transient overvoltage that is created at the point of application
(e.g. a substation) by switching a capacitor bank without a pre-insertion device (e.g. closing
resistors). At voltage levels where capacitor banks are not very common (e.g. 362 kV), the
maximum transient overvoltage of an “in-service” ac line are created by fault initiation on
adjacent ac lines and shunt reactor bank switching. These transient voltages are usually 1.5 p.u.
or less [2]. It is well known that these theoretical transient overvoltages will not be
experienced at locations remote from the bus at which they were created; however, in order to
be conservative, it will be assumed that all nearby ac lines are subjected to this same level of
overvoltage. Thus, a maximum transient overvoltage factor of 2.0 p.u. for 302 kV and below
and 1.4 p.u. for ac transmission lines 362 kV and above is used to compute the required
clearance distances for vegetation management purposes.
The overvoltage characteristics of dc transmission lines vary somewhat from their ac
counterparts. The referenced empirically derived transient overvoltage factor used to calculate
the minimum clearance distances from dc transmission lines to vegetation for the purpose of
FAC-003-2 will be 1.8 p.u.[3].
Example Calculation
An example calculation is presented below using the proposed method of computing the
vegetation clearance distances. It is assumed that the line in question has a maximum
operating voltage of 550 kVrms line-to-line. Using a per unit transient overvoltage factor of 1.4,
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
the result is a peak transient voltage of 629 kVcrest. It is further assumed that the line in
question operates at a maximum altitude of 7000 feet (2.134 km) above sea level.
The required withstand voltage of the air gap must be equal to or greater than 629 kVcrest.
Since the altitude is above sea level, (1) - (5) have to be iterated on to achieve the desired
result. Equation (9) can be used as an initial guess for the clearance distance.
8
3400 ⋅ k w ⋅ k g
Di =
Vm
0.85
(9)
−1
For our case here, Vm is equal to 629 kV, kw = 1.037 and kg = 1.3. Thus,
Di =
8
3400 ⋅ k w ⋅ k g
Vm
0.85
=
−1
(10)
8
= 1.535m
3400 ⋅ 1.037 ⋅ 1.3
−1
629
0.85
Using (2)-(5) and (8) the withstand voltage of the air gap is next computed. This value will then
be compared to the maximum transient overvoltage.
CFOS = k w ⋅ k g ⋅
−
GO =
3400
3400
= 1.037 ⋅ 1.3 ⋅
= 737.7 kV
8
8
1+
1.535
D
A
−
2.134
8.6
8.6
=
δ e=
e =
0.78
(12)
CFOS
737.7
=
= 0.961
500 ⋅ D (500 ) ⋅ (1.535 )
(13)
m = 1.25 ⋅ GO (GO − 0.2 ) = 1.25 ⋅ 0.961(0.961 − 0.2 ) = 0.915
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ
m
(11)
1+
3400
3400
0.915
⋅
= (0.85 )(1.037 )(1.3 )(0.78 )
8
8
1+
1+
D
1.535
(14)
= 499.8 kV
(15)
The calculated Vm is less than 629 kV; thus, the clearance distance must be increased. A few
iterations using (2)-(5) and (8) are required until the computed Vm ≥ 629 kV. For this case it was
found that D = 1.978 m (6.49 feet) yielded Vm = 629.3 kV. Using this clearance distance the
following values were computed for the final iteration.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
CFOS = k w ⋅ k g ⋅
−
3400
3400
= 1.037 ⋅ 1.3 ⋅
= 908.5 kV
8
8
1+
1+
D
1.978
A
−
2.134
8.6
8.6
=
δ e=
e =
0.78
GO =
(17)
(18)
CFOS
908.5
=
= 0.919
500 ⋅ D (500 ) ⋅ (1.978 )
m = 1.25 ⋅ GO (GO − 0.2 ) = 1.25 ⋅ 0.919(0.919 − 0.2 ) = 0.825
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ m ⋅
(16)
3400
3400
= (0.85 )(1.037 )(1.3 )(0.78 )0.825
8
8
1+
1+
D
1.978
(19)
= 629.3kV
(20)
Therefore, the minimum vegetation clearance distance for a maximum line to line ac operating
voltage of 550 kV at 7000 feet above sea level is 1.978 m (6.49 feet). Table 1 provides
calculated distances for various altitudes and maximum system operating ac voltages.
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
43
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Ta b le 1 — Min im u m Ve g e t a t io n Cle a ra n ce Dis t a n ce s ( MVCD) 7
For Alternating Current Voltages (feet)
MVCD
(feet)
MVCD
(feet)
MVCD feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
Over sea
level up to
500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over
10000 ft
up to
11000 ft
( AC )
Nominal
System
Voltage (KV)
( AC )
Maximum
System
Voltage (kV) 8
765
800
8.2ft
8.33ft
8.61ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
500
550
5.15ft
5.25ft
5.45ft
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
345
362
3.19ft
3.26ft
3.39ft
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
287
302
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
230
242
3.03ft
3.09ft
3.22ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
161*
169
2.05ft
2.09ft
2.19ft
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
138*
145
1.74ft
1.78ft
1.86ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
115*
121
1.44ft
1.47ft
1.54ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
88*
100
1.18ft
1.21ft
1.26ft
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
69*
72
0.84ft
0.86ft
0.90ft
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
* Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above).
7
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will be achieved at time of vegetation
maintenance.
8
Where applicable lines are operated at nominal voltages other than those listed, The Transmission Owner should use the maximum system voltage to determine the appropriate clearance for that line.
44
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Table 1 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level
Over 152.4m
Over 304.8m
up to
Over 609.6m
Over 914.4m
up to
Over 1219.2m
up to
Over 1524 m
Over 1828.8m
up to
Over 2133.6m
up to
Over 2438.4m
up to
Over 2743.2m
up to
Over 3048m
up to
3352.8m
1219.2m
1524m
2133.6m
2438.4m
2743.2m
3048m
up to
up to
152.4m
304.8m
up to
609.6m
up to
914.4m
1828.8m
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
69*
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
45
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Table 1 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
46
Over sea
level up to
500 ft
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
Over 500 ft
up to
1000 ft
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage (kV)
( DC )
Nominal
Pole to
Ground
Voltage (kV)
( DC )
Nominal
Pole to
Ground
Voltage (kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage (kV)
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000 ft
up to 7000
ft
Over 7000 ft
up to 8000
ft
Over 8000 ft
up to 9000
ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over 152.4
m up to
304.8 m
(Over 304.8
m up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to 1219.2m
(Over
1219.2m up
to 1524m
(Over 1524
m up to
1828.8 m)
(Over
1828.8m up
to 2133.6m)
(Over
2133.6m up
to 2438.4m)
(Over
2438.4m up
to 2743.2m)
(Over
2743.2m up
to 3048m)
(Over
3048m up to
3352.8m)
±750
14.12ft
(4.30m)
14.31ft
(4.36m)
14.70ft
(4.48m)
15.07ft
(4.59m)
15.45ft
(4.71m)
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.91ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
±600
10.23ft
(3.12m)
10.39ft
(3.17m)
10.74ft
(3.26m)
11.04ft
(3.36m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
13.54ft
(4.13m)
±500
8.03ft
(2.45m)
8.16ft
(2.49m)
8.44ft
(2.57m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
±400
6.07ft
(1.85m)
6.18ft
(1.88m)
6.41ft
(1.95m)
6.63ft
(2.02m)
6.86ft
(2.09m)
7.09ft
(2.16m)
7.33ft
(2.23m)
7.56ft
(2.30m)
7.80ft
(2.38m)
8.03ft
(2.45m)
8.27ft
(2.52m)
8.51ft
(2.59m)
±250
3.50ft
(1.07m)
3.57ft
(1.09m)
3.72ft
(1.13m)
3.87ft
(1.18m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5.00ft
(1.52m)
5.17ft
(1.58m)
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
List of Acronyms and Abbreviations
ANSI
American National Standards Institute
IEEE
Institute of Electrical and Electronics Engineers
IVM
Integrated Vegetation Management
NERC
North American Electric Reliability Corporation
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
ii
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
References
Andrew Hileman, Insulation Coordination for Power System, Marcel Dekker, New York, NY
1999
EPRI, EPRI Transmission Line Reference Book 345 kV and Above, Electric Power Research
Council, Palo Alto, Ca. 1975.
IEEE Std. 516-2003 IEEE Guide for Maintenance Methods on Energized Power Lines
G. Gallet, G. Leroy, R. Lacey, I. Kromer, General Expression for Positive Switching Impulse
Strength Valid Up to Extra Long Air Gaps, IEEE Transactions on Power Apparatus and
Systems, Vol. pAS-94, No. 6, Nov./Dec. 1975.
IEEE Std. 1313.2-1999 (R2005) IEEE Guide for the Application of Insulation Coordination.
2007 National Electric Safety Code
EPRI, HVDC Transmission Line Reference Book, EPRI TR-102764 , Project 2472-03, Final Report,
September 1993
ANSI. 2001. American National Standard for Tree Care Operations – Tree, Shrub, and Other
Plant Maintenance – Standard Practices (Pruning). Part 1. American National Standards
Institute, NY
ANSI. 2006. American National Standard for Tree Care Operations – Tree, Shrub, and Other
Plant Maintenance – Standard Practices (Integrated Vegetation Management a. Electric
Utility Rights-of-way). Part 7. American National Standards Institute, NY.
Cieslewicz, S. and R. Novembri. 2004. Utility Vegetation Management Final Report. Federal
Energy Regulatory Commission. Commissioned to support the Federal Investigation of the
August 14, 2003 Northeast Blackout. Federal Energy Regulatory Commission, Washington,
DC. pg. 39.
Kempter, G.P. 2004. Best Management Practices: Utility Pruning of Trees. International
Society of Arboriculture, Champaign, IL
Miller, R.H. 2007. Best Management Practices: Integrated Vegetation Management. Society of
Arboriculture, Champaign, IL.
Yahner, R.H. and R.J. Hutnik. 2004. Integrated Vegetation Management on an electric
transmission right-of-way in Pennsylvania, U.S. Journal of Arboriculture. 30:295-300
Results-based Initiative Ad Hoc Group. Acceptance Criteria of a Reliability Standard.
iii
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
Transmission Vegetation Management
Standard FAC-003-2 Technical Reference
Prepared by the
North American Electric Reliability Corporation
Vegetation Management Standard Drafting Team
for NERC Project 2007-07
September 30, 2011
Disclaimer
This supporting document is supplemental to the reliability standard FAC-003-2 —
Transmission Vegetation Management and does not contain mandatory requirements
subject to compliance review.December
17, 2010
NERC Standard FAC-003-2 Technical Reference
Throughout this document, for ready reference, there are “copies” in italic font of the wording in
the Standard. Any “copy” of any part of the Standard in this document should be cross checked
to the Standard and if any difference exists, then the Standard’s exact wording should be
considered the intended wording for this document.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
3
NERC Standard FAC-003-2 Technical Reference
Introduction
This document is intended to provide supplemental information and guidance for complying with
the requirements of Reliability Standard FAC-003-2.
The purpose of the Standard is to improve the reliability of the electric transmission system by
preventing those vegetation related outages that could lead to Cascading.
Compliance with the Standard is mandatory and enforceable.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
4
NERC Standard FAC-003-2 Technical Reference
Special Note: The Application of the Results-Based
Approach to FAC-003-2
In its three-year assessment as the ERO, NERC acknowledged stakeholder comments and
committed to:
i) addressing quality issues to ensure each reliability standard has a clear statement of
purpose, and has outcome-focused requirements that are clear and measurable; and
ii) eliminating requirements that do not have an impact on bulk power system reliability.
In 2010, the Standards Committee approved a recommendation to use Project 2007-07
Vegetation Management as a first proof of concept for developing results-based standards.
The Standard Drafting Team (SDT) employed a defense-in-depth 1 strategy for FAC-003-2,
where each requirement has a role in preventingThis standard is not intended to address outages
such as those due to vegetation fall-ins or blow-ins from outside the Right-of-Way, vandalism,
human activities or acts of nature. Operating experience indicates that trees that have grown out
of specification have contributed to Cascading, especially under heavy electrical loading
conditions.
This standard utilizes three types of requirements to provide layers of protection to prevent
vegetation related outages that could lead to Cascading. This portfolio of requirements was
designed to achieve an overall defense-in-depth strategy and to comply with the quality
objectives identified in the Acceptance Criteria of a Reliability Standard document.:
The SDT developed a portfolio of performance, risk, and competency-based mandatory
reliability requirements to support an effective defense-in-depth strategy. Each Requirement was
developed using one of the following requirement types:
a)
b)
Performance-based - defines a particular reliability objective or outcome to be
achieved. In its simplest form, a results-based requirement has four components:
who, under what conditions (if any), shall perform what action, to achieve what
particular result or outcome?
Risk-based - preventive requirements to reduce the risks of failure to acceptable
tolerance levels. A risk-based reliability requirement should be framed as: who,
under what conditions (if any), shall perform what action, to achieve what particular
result or outcome that reduces a stated risk to the reliability of the bulk power
system?
1
A defense-in-depth strategy for reliability standards recognizes that each requirement in the NERC standards has a
role in preventing system failures, and that these roles are complementary and reinforcing. These prevention
measures should be arranged in a series of defensive layers or walls. No single defensive layer provides complete
protection from failure by itself. But taken together, with well-designed layers including performance, risk, and
competency-based requirements, a defense-in-depth approach can be very effective in preventing future large scale
power system failures.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
5
NERC Standard FAC-003-2 Technical Reference
c)
Competency-based - defines a minimum set of capabilities an entity needs to have
to demonstrate it is able to perform its designated reliability functions. A
competency-based reliability requirement should be framed as: who, under what
conditions (if any), shall have what capability, to achieve what particular result or
outcome to perform an action to achieve a result or outcome or to reduce a risk to
the reliability of the bulk power system?
The defense-in-depth strategy for reliability standards development recognizes that each
requirement in a NERC reliability standard has a role in preventing system failures, and that
these roles are complementary and reinforcing. Reliability standards should not be viewed as a
body of unrelated requirements, but rather should be viewed as part of a portfolio of
requirements designed to achieve an overall defense-in-depth strategy and comport with the
quality objectives of a reliability standard.
This NERC Vegetation Management Standard (“standard”) uses a defense-in-depth approach to
improve the reliability of the electric Transmission System by:
•
•
•
•
•
•
Requiring that vegetation be managed to prevent vegetation encroachment inside the
flash-over clearance (R1 and R2);
Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over conditions
including consideration of 1) conductor dynamics and 2) the interrelationships between
vegetation growth rates, control methods and the inspection frequency (R3);
Requiring timely notification to the appropriate control center of vegetation conditions
that could cause a flash-over at any moment (R4);
Requiring corrective actions to ensure that flash-over distances will not be violated due to
work constrains such as legal injunctions (R5);
Requiring inspections of vegetation conditions to be performed annually (R6); and
Requiring that the annual work needed to prevent flash-over is completed (R7).
For this standard, the requirements have been developed as follows:
•
•
•
Performance-based: Requirements 1 and 2
Competency-based: Requirement 3
Risk-based: Requirements 4, 5, 6 and 7
R3 serves as the first line of defense by ensuring that entities understand the problem they are
trying to manage and have fully developed strategies and plans to manage the problem. R1, R2,
and R7 serve as the second line of defense by requiring that entities carry out their plans and
manage vegetation. R6, which requires inspections, may be either a part of the first line of
defense (as input into the strategies and plans) or as a third line of defense (as a check of the first
and second lines of defense). R4 serves as the final line of defense, as it addresses cases in
which all the other lines of defense have failed.
Major outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
6
NERC Standard FAC-003-2 Technical Reference
Adherence to the standard requirements for applicable lines on any kind of land or easement,
whether they are Federal Lands, state or provincial lands, public or private lands, franchises,
easements or lands owned in fee, will reduce and manage this risk. For the purpose of the
standard the term “public lands” includes municipal lands, village lands, city lands, and a host of
other governmental entities.
The standard addresses vegetation management along applicable overhead lines and does not
apply to underground lines, submarine lines or to line sections inside an electric station
boundary.
The standard focuses on transmission lines to prevent those vegetation related outages that could
lead to Cascading. It is not intended to prevent customer outages due to tree contact with lower
voltage distribution system lines. For example, localized customer service might be disrupted if
vegetation were to make contact with a 69kV transmission line supplying power to a 12kV
distribution station. However, this standard is not written to address such isolated situations
which have little impact on the overall electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses an
increased outage risk, especially when numerous transmission lines are operating at or near their
Rating. This can present a significant risk of consecutive line failures when lines are
experiencing large sags thereby leading to Cascading. Once the first line fails the shift of the
current to the other lines and/or the increasing system loads will lead to the second and
subsequent line failures as contact to the vegetation under those lines occurs. Conversely, most
other outage causes (such as trees falling into lines, lightning, animals, motor vehicles, etc.) are
not an interrelated function of the shift of currents or the increasing system loading. These
events are not any more likely to occur during heavy system loads than any other time. There is
no cause-effect relationship which creates the probability of simultaneous occurrence of other
such events. Therefore these types of events are highly unlikely to cause large-scale grid
failures. Thus, this standard places the highest priority on the management of vegetation to
prevent vegetation grow-ins.
The drafting team reviewed and edited version 1 of FAC-003-1 to remove prescriptive
and administrative language in order to distill the technical requirements down to their
essential reliability content. Text that Explanatory text is explanatory in nature is placed
in ao
offered within two special section of the standard entitled sections, Background and
Guideline and Technical Basis,, to aid in the understanding of the standard and its
requirements. Furthermore, Rationale text boxes and other text boxes are also inserted
alongside each requirementtthroughout the standard to communicateaaid understanding the
sections. The Effective Dates section covers five special cases for lines that undergo
specific transitions as or after the foundation for standard has reached the requirement.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
7
NERC Standard FAC-003-2 Technical Reference
Disclaimer
This supporting document is supplemental to the reliability standard FAC-003-2 —
Transmission Vegetation Management and does not contain mandatory requirements subject to
compliance review.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
8
NERC Standard FAC-003-2 Technical Reference
general effective date.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
9
NERC Standard FAC-003-2 Technical Reference
Preface
The NERC Vegetation Management Standard Drafting Team (VM SDT) acknowledges those
across the industry who contributed to the development of this Standard and companion
Technical Reference document. TheThis Technical Reference document is intended to provide
supplemental explanatory background and guidance related to requirements contained in the
Standard but does not in itself contain requirements subject to compliance review.
The VM SDT believes that a well-designed and executed Transmission Vegetation Management
Program (TVMP) will have few problems meeting the requirements of this Standard. While the
Standard requires a TVMP the Transmission Owner to contain certain elements,have
documentation of the maintenance strategies or procedures or processes or specifications it uses
to be successful in managing vegetation. This allows the Transmission Owner to exercise
substantial flexibility in designing a TVMPits overall program to meet localits specific needs
provided itthat the Transmission Owner also meets the purpose of the Standard.
While there are many approaches to vegetation management, the VMSDT supports industry best
practices contained in ANSI A300 (Part 7) – Integrated Vegetation Management (IVM) practices
on Utility Rights-of-way, as well as the companion publication Best Management Practices –
Integrated Vegetation Management, as an effective strategy to maintain compliance with this
Standard. ANSI A300 (Part 7), approved by industry consensus in 2006, contains many elements
needed for an effective TVMP as required byvegetation management. Those elements are
similar to the requirements in this Standard. One key element is the “wire zone – border zone”
concept. Supported by over 50 years of continuous research, wire zone – border zone is a proven
method to manage vegetation on transmission rights-of-ways and is an industry accepted best
practice to help ensure electric system reliability.
The VM SDT believes that Transmission Owners who adopt and effectively implement IVM
principles, particularly the “wire zone – border zone” concept, are far less likely to experience a
vegetation caused outage than those who do not.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
10
NERC Standard FAC-003-2 Technical Reference
Def inition of TermsEffective Dates & Special States of
Transition
The first sentence of the Effective Dates section is standard language used in most NERC
standards to cover the general effective date and is sufficient to cover the vast majority of
situations. Five special cases are needed to cover effective dates for individual lines which
undergo transitions after the general effective date. These special cases cover the effective dates
for those lines which are initially becoming subject to the standard, those lines which are
changing their applicability within the standard, and those lines which are changing in a manner
that removes their applicability to the standard. The text for each of these five cases is copied
from the standard and is shown below in italic font. An explanation of the need for each special
exception follows each copied text section.
1. A line operated below 200kV, designated by the Planning Coordinator as an element
of an Interconnection Reliability Operating Limit (IROL) or designated by the
Western Electricity Coordinating Council (WECC) as an element of a Major WECC
Transfer Path, becomes subject to this standard the latter of: 1) 12 months after the
date the Planning Coordinator or WECC initially designates the line as being an
element of an IROL or an element of a Major WECC Transfer Path, or 2) January 1
of the planning year when the line is forecast to become an element of an IROL or an
element of a Major WECC Transfer Path.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to
become elements of an IROL or Major WECC Transfer Path in a future Planning Year (PY).
For example, studies by the Planning Coordinator in 2011 may identify a line to have that
designation beginning in PY 2021, ten years after the planning study is performed. It is not
intended for the Standard to be immediately applicable to, or in effective for, that line until that
future PY begins. The effective date provision for such lines ensures that the line will become
subject to the standard on the January 1 of the PY specified with an allowance of at least 12
months for the Transmission Owner to make the necessary preparations to achieve compliance
on that line. The table below has some explanatory examples of the application.
Date that
Planning Study
is completed
05/15/2011
05/15/2011
05/15/2011
05/15/2011
PY the line
will become
an IROL
element
2012
2013
2014
2021
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
Date 1
05/15/2012
05/15/2012
05/15/2012
05/15/2012
Date 2
01/01/2012
01/01/2013
01/01/2014
01/01/2021
Effective Date
The latter of Date 1
or Date 2
05/15/2012
01/01/2013
01/01/2014
01/01/2021
11
NERC Standard FAC-003-2 Technical Reference
2. A line operated below 200 kV currently subject to this standard as a designated
element of an IROL or a Major WECC Transfer Path which has a specified date for
the removal of such designation will no longer be subject to this standard effective on
that specified date.
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or
Major WECC Transfer Path may be removed from that designation due to system improvements,
changes in generation, changes in loads or changes in studies and analysis of the network.
3. A line operated at 200 kV or above, currently subject to this standard which is a
designated element of an IROL or a Major WECC Transfer Path and which has a
specified date for the removal of such designation will be subject to Requirement R2
and no longer be subject to Requirement R1 effective on that specified date
Case 3 is needed because a line operating at 200 kV or above that once was designated as an
element of an IROL or Major WECC Transfer Path may be removed from that designation due
to system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network. Such changes result in the need to apply R1 to that line until that date is
reached and then to apply R2 to that line thereafter.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an
asset owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be
acquired by a Transmission Owner from a third party such as a Distribution Provider or other
end-user who was using the line solely for local distribution purposes, but the Transmission
owner, upon acquisition, is incorporating the line into the interconnected electrical energy
transmission network which will thereafter make the line subject to the standard.
5. An existing transmission line operated below 200kV which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date of the line if at the time of acquisition the
line is designated by the Planning Coordinator as an element of an IROL or by WECC as
an element of a Major WECC Transfer Path.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by a
Transmission Owner from a third party such as a Distribution Provider or other end-user who
was using the line solely for local distribution purposes, but the Transmission owner, upon
acquisition, is incorporating the line into the interconnected electrical energy transmission
network. In this special case the line upon acquisition was designated as an element of an
Interconnection Reliability Operating Limit (IROL) or an element of a Major WECC transfer
Path.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
12
NERC Standard FAC-003-2 Technical Reference
Definition of Terms
Right-of-Way (ROW)*
The corridor of land under a transmission line(s)
The current glossary definition of this NERC
needed to operate the line(s). The width of the
term is modified to address the issues set forth
corridor is established by engineering or
in Paragraph 734 of FERC Order 693.
construction standards as documented in either
construction documents, pre-2007 vegetation
maintenance records, or by the blowout standard in effect when the line was built. The ROW
width in no case exceeds the Transmission Owner’s legal rights but may be less based on the
aforementioned criteria.
The current NERC glossary definition of Right of Way has been modified to address the matter
set forth in Paragraph 734 of FERC Order 693. The Order pointed out that Transmission Owners
may in some cases own more property or rights than are needed to reliably operate transmission
lines. This modified definition represents a slight but significant departure from the strict legal
definition of “right of way” in that this definition is based on engineering and construction
considerations that establish the width of a corridor from a technical basis. The pre-2007
maintenance records are included to allow the use of such vegetation widths if there were no
engineering or construction standards that referenced the width of right of way to be maintained
for vegetation on a particular line but the evidence exists in maintenance records for a width that
was in fact maintained prior to this standard becoming mandatory. Such widths may be the only
information available for lines that had limited or no vegetation easement rights and were
typically maintained primarily to ensure public safety. This standard does not require additional
easement rights to be purchased to satisfy a minimum right of way width that did not exist prior
to this standard becoming mandatory.
This definition does not imply that danger tree rights beyond the constructed and maintained
width are incorporated in the definition; therefore fall-ins from outside the ROW but within an
area with danger tree rights would not be considered fall-ins from within the ROW.
Vegetation Inspection*
The systematic examination of vegetation conditions
on a Right-of-Way and those vegetation conditions
under the Transmission Owner’s control that are
likely to pose a hazard to the line(s) prior to the
next planned maintenance or inspection. This may
be combined with a general line inspection.
The inspection includes the identification of any
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
13
NERC Standard FAC-003-2 Technical Reference
vegetation that may pose a threat to reliability prior to the next planned maintenance or
inspection work, considering the current location of the conductor and other possible locations of
the conductor due to sag and sway for rated conditions.
This definition allows both maintenance inspections and vegetation inspections to be performed
concurrently.
* This is a modification to a defined term in the NERC glossary and will be incorporated into the
NERC glossary of terms with final approval of this standard revision.
See the Guidelines and Technical Basis section on Requirement R6 contained within the
Standard for more details on inspections.
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is
a method has been in the design of high voltage transmission lines. Keeping vegetation away
from high voltage conductors by this distance will prevent voltage flash-over to the vegetation.
See the explanatory text below for Requirement R3 and associated Figures 1, 2 and 3. Details of
the equations and an example calculation are provided in Appendix 1below of the Technical
Reference document. Table 1in Appendix 1 below provides MVCD values for various voltages
and altitudes.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
14
NERC Standard FAC-003-2 Technical Reference
Applicability of the Standard
4. Applicability
4.1. Functional Entities:
Transmission Owners
4.2. Facilities: Defined below (referred to as “applicable lines”), including but not
limited to those that cross lands owned by federal 1, state, provincial, public,
private, or tribal entities:
4.2.1
OverheadEach overhead transmission lines operated at 200kV or higher.
4.2.2
Overhead Each overhead transmission lines operated below 200kV having
been identified as included in the definitionan element of an Interconnection
Reliability Operating Limit (IROL) under NERC Standard FAC -014 by the
Planning Coordinator.
4.2.3
OverheadEach overhead transmission lines operated below 200 kV having
been identified as included in the definitionan element of one of thea Major
WECC Transfer Paths in the
Bulk Electric System by
Rationale
WECC.
-The areas excluded in 4.2.4 were excluded based
4.2.4
This standard applies toEach
overhead transmission
linesline identified above
(4.2.1 through 4.2.3) located
outside the fenced area of the
switchyard, station or
substation and any portion of
the span of the transmission
line that is crossing the
substation fence.
on comments from industry for reasons summarized
as follows: 1) There is a very low risk from
vegetation in this area. Based on an informal
survey, no TOs reported such an event. 2)
Substations, switchyards, and stations have many
inspection and maintenance activities that are
necessary for reliability. Those existing process
manage the threat. As such, the formal steps in this
standard are not well suited for this environment. 3)
The standard was written for Transmission Owners.
Rolling the excluded areas into this standard will
bring GO and DP into the standard, even though
NERC has an initiativea project in place to address
this bigger registry issue.at a later date the
applicability of this standard to Generation Owners
4.3. Enforcement: The reliability
obligations of the applicable entities
and facilities are contained within
the technical requirements of this standard. [Straw proposal]
In Order 693, FERC discussed the 200 kV bright-line test of applicability. While FERC did not
change the 200 kV bright -line, the Commission remained concerned that there may be some
transmission lines operating at lesser voltages that could have significant impact on the Bulk
Electric System that should therefore be subject to this standard.
1
EPAct 2005 section 1211c: “Access approvals by Federal agencies”.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
15
NERC Standard FAC-003-2 Technical Reference
NERC Standard FAC-014 has the stated purpose, “To ensure that System Operating Limits
(SOLs) used in the reliable planning and operation of the Bulk Electric System (BES) are
determined based on an established methodology or methodologies.” FAC-014 requires
Reliability Coordinators, Planning Coordinators, and Transmission Planners to have a
methodology to identify all lines that might comprise an IROL. Thus, these entities would
identify sub-200 kV lines that qualify as part of an IROL and should be subject to FAC-003-2.
Although all three entities may prepare the list of elements, FAC-003-2 presently does not
specify that it is the the list from as provided by the Planning Coordinator that should be used by
Transmission Ownersfunction is the more appropriate choice for FAC-003. However, thethis
Standard. The Time Horizon needed to plan vegetation management work does not lend itself to
the operating horizon of a Reliability Coordinator. Additionally, the Planning Coordinator has a
wider-area view than the Transmission Planner and could thus identify any elements of
importance to a sub-set of its area that might be missed by a Transmission Planner.
Transmission Owners, who do not already get the list of circuits included in the definition of an
IROL, can get them from the Planning Coordinator. Specifically R5 of FAC-014 specifies that
“The Reliability Coordinator, Planning Authority (Coordinator) and Transmission Planner
shall each provide its SOLs and IROLs to those entities that have a reliability-related need for
those limits and provide a written request that includes a schedule for delivery of those limits”
Vegetation-related Sustained Outages that occur due to natural disasters are beyond the control
of the Transmission Owner. These events are not classified as vegetation-related Sustained
Outages and are therefore exempt from the Standard. Transmission lines are not designed to
withstand the impacts of natural disasters such as flood, drought, earthquake, major storms, fire,
hurricane, tornado, landslides, ice storms, etc. In the aftermath of catastrophic system damage
from natural disasters the Transmission Owner’s focus is on electric system restoration for public
safety and critical support infrastructure.
Sustained Outages due to human or animal activity are beyond the control of the Transmission
Owner. These outages are not classified as vegetation-related Sustained Outages and are
therefore exempt from the Standard. Examples of these events may include new plantings by
outside parties of tall vegetation under the transmission line planted since the last Vegetation
Inspection, tree contacts with line initiated by vehicles, logging activities, etc.
The foregoing exemptions are addressed in a new footnote 2. Referred to collectively as force
majeure events and activities, this footnote applies to requirements R1 and R2 in FAC-003-2.
The reliability objective of this NERC Vegetation Management Standard (“Standard”) is to
prevent vegetation-related outages which could lead to Cascading by effective vegetation
maintenance while recognizing that certain outages such as those due to vandalism, human errors
and acts of nature are not preventable. Operating experience clearly indicates that trees that have
grown out of specification could contribute to a cascading grid failure, especially under heavy
electrical loading conditions.
Serious outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations. To
properly reduce and manage this risk, it is necessary to apply the Standard to applicable lines on
any kind of land or easement, whether they are Federal Lands, state or provincial lands, public or
private lands, franchises, easements or lands owned in fee. For the purposes of the Standard and
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
16
NERC Standard FAC-003-2 Technical Reference
this Technical Reference document, the term “public lands” includes municipal lands, village
lands, city lands, and land owned by a host of other governmental entities.
The Standard addresses vegetation management along applicable overhead lines that serve to
connect one electric station to another. However, it is not intended to be applied to lines sections
inside the electric station fence or other boundary of an electric station, submarine or
underground lines.
The Standard is intended to reduce the risk of Cascading involving vegetation. It is not intended
to prevent customer outages from occurring due to tree contact with all transmission lines and
voltages. For example, localized customer service might be disrupted if vegetation were to make
contact with a 69kV transmission line supplying power to a 12kV distribution station. However,
this Standard is not written to address such isolated situations which have little impact on the
overall Bulk Electric System.
Vegetation growth is constant and always present. Unmanaged vegetation poses an increased
outage risk whenbelow numerous transmission lines that are operating at or near their Rating. is
highly problematic. This poses a significant risk ofsituation has led to multiple subsequent line
failures and Cascading. On the other hand Conversely, most other outage causes (such as trees
falling into lines, lightning, animals, motor vehicles, etc.) are statistically intermittent. The
probability of occurrence of these These events isare not dependent onany more likely to occur
during heavy system loads. than any other time. There is no cause-effect relationship which
creates the probability of simultaneous occurrence of other such events. Therefore these types of
events are highly unlikely to cause large-scale grid failures. Thus, this Standard’s emphasis is on
vegetation grow-ins.
In preparing the original vegetation management standard in 2005, industry stakeholders set the
threshold for applicability of the standard at 200kV. This was because an unexpected loss of
lines operating at above 200kV has a higher probability of initiating a widespread blackout or
cascading outages compared with lines operating at less than 200kV.
The original NERC Standard FAC-003-1 also allowed for application of the standard to
“critical” circuits (critical from the perspective of initiating widespread blackouts or cascading
outages) operating below 200kV. While the percentage of these circuits is relatively low, it
remains a fact that there are sub-200kV circuits whose loss could contribute to a widespread
outage. Given the very limited exposure and unlikelihood of a major event related to these
lower-voltage lines, it would be an imprudent use of resources to apply the Standard to all sub200kV lines. The drafting team, after evaluating several alternatives, selected the IROL and
WECC Major Transfer Path criteria to determine applicable lines below 200 kV that are subject
to this standard.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
17
NERC Standard FAC-003-2 Technical Reference
Requirements R1 and R2
R1. Each Transmission Owner shall manage
vegetation to prevent encroachments of
the types shown below, into the
Minimum Vegetation Clearance Distance
(MVCD) of any of its applicable line(s)
identified aswhich are either an
element of an Interconnection
Reliability Operating Limit
(IROL) in the planning horizon
by the Planning Coordinator;,
or an element of a Major Western
Electricity Coordinating
Council (WECC) transfer
path(s); Transfer Path; operating
within its Rating and all Rated Electrical
2
Operating Conditions. of the types shown
below 3:
1. 1.
An encroachment into the MVCD
as shown in FAC-003-Table 2,
observed in Real-time, absent a
Sustained Outage 4,
2. 2. An encroachment due to a fall-in
from inside the Right-of-Way (ROW)
Rationale for R1 and R2:
Lines with the highest significance to
reliability are covered in R1; all other lines are
covered in R2.
Ra tio n a le
The MVCD is a calculated minimum distance
stated in feet (meters) to prevent flash-over
between conductors and vegetation, for
various altitudes and operating voltages. The
distances in Table 2 were derived using a
proven transmission design method. The fo r
th e typ e s o f fa ilu re to m a n a g e
ve g e ta tio n wh ic h a re lis te d in o rde r o f
in c re a s in g d e g re e s of s e ve rity in n o n c o m p lia n t p e rfo rm a nc e a s it re la te s to
a fa ilu re o f a TO’sTra n s m is s io n
Own e r's ve g e ta tio n m a in te n a n c e
p ro g ra m since the encroachments listed
require different:
1. This management failure is found by
routine inspection or Fault event investigation,
and increasing levelsis normally symptomatic
of skillsunusual conditions in an otherwise
sound program.
2. This management failure occurs when the
height and knowledgelocation of a side tree
within the ROW is not adequately addressed
2
by the
This requirement does not apply to circumstances that are beyond
theprogram.
control of a Transmission Owner subject to
this reliability standard, including natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, wind
shear, fresh gale, major storms as defined either by the Transmission
Owner
or an applicable
regulatory
3. This
management
failure
occursbody,
wheniceside
storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree,
arboricultural activities or horticultural or agricultural activities, or removal or digging of vegetation. Nothing in this
footnote should be construed to limit the Transmission Owner’s right to exercise its full legal rights on the ROW.
3
This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to
this reliability standard, including natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, wind
shear, fresh gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice
storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree, or
installation, removal, or digging of vegetation. Nothing in this footnote should be construed to limit the
Transmission Owner’s right to exercise its full legal rights on the ROW.
4
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation encroachment within the
MVCD has occurred from vegetation within the ROW, this shall be considered the equivalent of a Real-time
observation.
FAC-003-2 Technical Reference
18
December 17, 2010August 14, 2011
NERC Standard FAC-003-2 Technical Reference
that caused a vegetation-related Sustained Outage 5,
3. 3. An encroachment due to the blowing together of applicable lines and vegetation
located inside the ROW that caused a vegetation-related Sustained OutageOutage4,
4. 4. An encroachment due to a grow-in vegetation growth into the MVCD that
caused a vegetation-related Sustained Outage. Outage4.
[VRF – High] [Time Horizon – Real-time]
R2. Each Transmission Owner shall manage vegetation to prevent encroachments of the types
shown below, into the MVCD of any of its applicable line(s) that iswhich are not either an
element of an IROL;, or an element of a Major WECC transfer pathTransfer Path;
operating within its Rating and all Rated Electrical Operating Conditions.2 of the types
shown below2:
1. 1.
An encroachment into the MVCD as shown in FAC-003-Table 2, observed in
Real-time, absent a Sustained OutageOutage3,
2. 2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained OutageOutage4,
3. 3. An encroachment due to blowing together of applicable lines and vegetation
located inside the ROW that caused a vegetation-related Sustained OutageOutage4,
4. 4. An encroachment due to a grow-invegetation growth into the MVCD that
caused a vegetation-related Sustained Outage. [VRF – Medium] [Time
Horizon – Real-time]Outage4
M1. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-time observations of any MVCD encroachments.
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation
encroachment within the MVCD has occurred from vegetation within the ROW, this
shall be considered the equivalent of a Real-time observation.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. (R1)
5
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage
regardless of the actual number of outages within a 24-hour period.
FAC-003-2 Technical Reference
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December 17, 2010August 14, 2011
NERC Standard FAC-003-2 Technical Reference
M2. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R2. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-time observations of any MVCD encroachments. (R1)
M2.
EachIf a later confirmation of a Fault by the Transmission Owner
showshas evidence that ait managed vegetation to prevent encroachment withininto
the MVCD has occurred from vegetation within the ROW, this shall be considered
the equivalentas described in R2. Examples of acceptable forms of a Real-time
observation.
Multipleevidence may include dated attestations, dated reports containing no Sustained
Outages on an individual line, if caused by the same vegetation, will be reported as
one outage regardlessassociated with encroachment types 2 through 4 above, or
records confirming no Real-time observations of the actual number of outages within
a 24-hour period.any MVCD encroachments. (R2)
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the prevention of vegetation encroachments within a minimum distance of
transmission lines. Content-wise, R1 and R2 are the same requirements; however, they apply to
different Facilities. Both R1 and R2 require each Transmission Owner to manage vegetation to
prevent encroachment within the Minimum Vegetation Clearance Distance (“MVCD”) of
transmission lines. R1 is applicable to lines “that are identified as an element of an
Interconnection Reliability Operating Limit (IROL) or Major Western Electricity Coordinating
Council (WECC) transfer path (operating within Rating and Rated Electrical Operating
Conditions) to avoid a Sustained Outage”.. R2 applies is applicable to all other applicable lines
that are not an element of an IROL or, and not an element of a Major WECC Transfer Path.
The separation of applicability (between R1 and R2) recognizes that an encroachment into the
MVCD of an IROL or Major WECC Transfer Path transmissioninadequate vegetation
management for an applicable line that is an element of an IROL or Major WECC Transfer Path
is a greater risk to the interconnected electric transmission system. than applicable lines that are
not an element of an IROL or a Major WECC Transfer Path. Applicable lines that are not an
element of an IROL or Major WECC Transfer Path are required to be clear ofdo require effective
vegetation management, but these lines are comparatively less operationally significant. As a
reflection of this difference in risk impact, the Violation Risk Factors (VRFs) are assigned as
High for R1 and Medium for R2.
These requirements (R1 and R2) state that if vegetation encroaches within the distances in Table
1 in Appendix 1 of this supplemental Transmission Vegetation Management Standard FAC-0032 Technical Reference document, it is in violation of the standard. Table 21below, which is the
same as Table 2 in the standard, tabulates the distances necessary to prevent spark-over based on
the Gallet equations as described more fully in Appendix 1 below.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
20
NERC Standard FAC-003-2 Technical Reference
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating and
Rated Electrical Operating Condition (potentially in violation of other standards), the occurrence
of a clearance encroachment may occur solely due to that condition. For example, emergency
actions taken by a Transmission Operator or Reliability Coordinator to protect an
Interconnection may cause the transmission line to sag moreexcessive sagging and come closer
to vegetation, potentially causing an outage. Another example would be ice loading beyond the
line’s Rating and Rated Electrical Operating Condition. Such vegetation-related encroachments
and outages are not a violationviolations of these requirementsthis standard.
Evidence of violation of Requirement R1 and R2failures to adequately manage vegetation
include real-time observation of a vegetation encroachment into the MVCD (absent a Sustained
Outage), or a vegetation-related encroachment resulting in a Sustained Outage due to a fall-in
from inside the ROW, or a vegetation-related encroachment resulting in a Sustained Outage due
to the blowing together of applicablethe lines and vegetation located inside the ROW, or a
vegetation-related encroachment resulting in a Sustained Outage due to a grow-in. If an
investigation of Faults which do not cause a Fault by a Transmission Owner confirms that
aSustained outage and which are confirmed to have been caused by vegetation encroachment
within the MVCD occurred, then it shall beare considered the equivalent of a Real-time
observation for violation severity levels.
With this approach, the VSLs were definedfor R1 and R2 are structured such that they directly
correlate to the severity of a failure of a Transmission Owner to manage vegetation and to the
corresponding performance level of the Transmission Owner’s vegetation program’s ability to
meet the goalobjective of “preventing a Sustained Outagethe risk of those vegetation related
outages that could lead to Cascading.” Thus violation severity increases with a Transmission
Owner’s inability to meet this goal and its potential of leading to a Cascading event. The
additional benefits of such a combination are that it simplifies the standard and clearly defines
performance for compliance. A performance-based requirement of this nature will promote high
quality, cost effective vegetation management programs that will deliver the overall end result of
improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For
example, a limb initial investigations and corrective actions may only partially break and
intermittently contact anot identify and remove the actual outage cause then another outage
occurs after the line is re-energized and previous high conductor temperatures return. Such
events are considered to be a single vegetation-related Sustained Outage under the
Standardstandard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will prevent transmission outages.
If the TO has applicable lines operated at nominal voltage levels not listed in Table 2, then the
TO should use the next largest clearance distance based on the next highest nominal voltage in
the table to determine an acceptable distance.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
21
NERC Standard FAC-003-2 Technical Reference
Requirement R3
Rationale
The documentation provides a basis for
evaluating the competency of the
Transmission Owner’s vegetation program.
There may be many acceptable approaches to
maintain clearances. Any approach must
demonstrate that the Transmission Owner
avoids vegetation-to-wire conflicts under all
Rated Electrical Operating Conditions. See
Figure 1 for an illustration of possible
conductor locations.
R3. Each Transmission Owner shall have
documented maintenance strategies or
procedures or processes or specifications
it uses to prevent the encroachment of
vegetation into the MVCD of its applicable
transmission lines that include(s)accounts
for the following:
3.1 Accounts for the movementMovement
of applicable transmission line
conductors under their Facility Rating
and all Rated Electrical Operating
Conditions;
3.2 Accounts for the interInter-relationships between vegetation growth
rates, vegetation control methods, and inspection frequency.
[VRF – Lower] [Time Horizon – Long Term Planning]
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the Transmission Owner can prevent encroachment into the
MVCD considering the factors identified in the requirement. (R3)
Requirement R3 is a competency based requirement concerned with the maintenance strategies,
procedures, processes, or specifications, a Transmission Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the
Transmission Owner uses to plan and perform vegetation work to prevent transmission Sustained
Outages and minimize risk to the Transmission System.transmission system. The approach
provides the basis for evaluating the intent, allocation of appropriate resources and the
competency of the Transmission Owner in managing vegetation. There are many acceptable
approaches to manage vegetation and avoid Sustained Outages. However, the Transmission
Owner must be able to state whatshow the documentation of its approach is and how it conducts
work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach a
Transmission Owner chooses to use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the Transmission Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing as ain reaction to
a number of different loading variables. Changes in vertical and horizontal conductor
positioning are the result of thermal and physical loads applied to the line. Thermal loading is a
function of line current and the combination of numerous variables influencing ambient heat
dissipation including wind velocity/direction, ambient air temperature and precipitation.
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Physical loading applied to the conductor affects sag and sway by combining physical factors
such as ice and wind loading. The movement of the transmission line conductor and the MVCD
is illustrated in Figures 1, 2, and 3 below.
Conductor Dynamics
In order for a Transmission Owner to develop a specific maintenance approach, it is important to
understand the dynamics of a line conductor’s movement.movements. This paper will first
address the complexities inherent in observing and predicting conductor movement, particularly
for field personnel. It will then present some examples of maintenance approaches which
Transmission Owners may consider that take into account these complexities, while resulting
inand the practical approaches forthat can be utilized by field personnel.
Additionally, it is important the Transmission Owner consider all conductor locations, the
MVCD, and vegetation growth between maintenance activities when developing a maintenance
approach.
Understanding Conductor Position and Movement
The conductor’s position in space at any point in time is continuously changing as a reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading.
As a consequence of these loading variables, the conductor’s position in space is dynamic and
moving. When calculating the range of conductor positions, the Transmission Owner should use
the same design criteria and assumptions that the Transmission Owner uses when establishingare
used to establish Ratings and SOL,System Operating Limits (SOLs), as described in other
standards. Typically, the greatest conductor movement would bemovements occur at mid-span.
As the conductor moves through various positions, a spark-over zone surrounding the conductor
moves with it. The radius of the spark-over zone may be found by referring to Table 1
(“Minimum Vegetation Clearance Distances”) in the standard.below. For illustrations of this
zone and conductor movements, Figures 1 through, 2 and 3 below demonstrate these
concepts.are provided. At the time of making a field observation, however, it is very difficult to
precisely know where the conductor is in relation to its wide range of all possible positions.
Therefore, Transmission Owners must adopt maintenance approaches that account for this
dynamic situation.
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Figure 1
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Figure 2
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Cross-Section View of a Single Conductor
At a Given Point Along The Span
Showing Six Possible Conductor Positions Due to Movement
Resulting From Thermal and Mechanical Loading
For Consideration in Developing a Maintenance Approach
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Figure 3
A cross-section view of a single conductor at a given point along the span is
shown with six possible conductor positions due to movement resulting from
thermal and mechanical loading.
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Selecting a Maintenance Approach
In order to maintain adequate separation between vegetation and transmission line conductors,
the Transmission Owner must craft a maintenance strategy that keeps vegetation well away from
the spark-over zone mentioned above. In fact, it is generally necessary to incorporate a variety of
maintenance strategies. For example, one Transmission Owner may utilize a combination of
routine cycles, traditional IVM techniques and long-term planning. Another Transmission Owner
may place a higher reliance on frequent inspections and quickfollow-up remediation as opposed
to a set cyclical approach. This variation of approaches is further warranted when factors, such
as terrain, vegetation types, weather and climate, and any, environmental, legal andor other land
use constraints, vegetation types, and climates, aremust be considered in developing a
Transmission Owner’s specific approach to satisfying this requirementR3.
The following is a sample description of one combination ofdescribes some strategies which may
be utilized by a Transmission Owner. A Transmission Owner’s basic maintenance approach in
relatively flat terrain could be to remove all incompatible vegetation from the right of wayROW
if it has the right to do so and has no constraints. In mountainous terrain, however, this strategy
could change to one where the Transmission Owner managesmanaging vegetation based on
vegetation-to-conductor clearances, since it might not be necessary to remove vegetation in a
valley that is far below the conductors at maximum sag.
If faced with easement constraints and assumingon a line design with sufficient ground
clearance, the Transmission Owner ’s approach could then be to allow vegetation such as fruit
trees, but perhaps only up to a given height at maturity (perhapsfor example 10 feet from the
ground). If constraints cannot be overcome and if design clearances are sufficient, an exception
to the Transmission Owner’s 10-foot guideline might be made. Finally, if the Transmission
Owner hasIf an approach is chosen to utilizemanage vegetation-to-conductor based primarily on
clearance distance methods, the Transmission Ownerdistances it could haveinclude an inspection
regimen in place to regularly ensure that any impending clearance problems are identified early
for rectification.
ANSI A300 – Best Management Practices for Tree Care Operations
A description of ANSI A-300, part 7, is offered below to illustrate another maintenance approach
that could be used in developing a comprehensive transmission vegetation management program.
Introduction
Integrated Vegetation Management (IVM) is a best management practice conveyed in the
American National Standard for Tree Care Operations, Part 7 (ANSI 2006) and the International
Society of Arboriculture Best Management Practices: Integrated Vegetation Management
(Miller 2007). IVM is consistent with the requirements in FAC-003-02, and it provides
practitioners with what industry experts consider to be appropriate techniques to apply to electric
right-of-way projects in order to meet or exceed the Standard.
IVM is a system of managing plant communities whereby managers set objectives; identify
compatible and incompatible vegetation; consider action thresholds; and evaluate, select and
implement the most appropriate control method or methods to achieve set objectives. The choice
of control method or methods should be based on the environmental impact and anticipated
effectiveness; along with site characteristics, security, economics, current land use and other
factors.
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Planning and Implementation
Best management practices provide a systematic way of planning and implementing a vegetation
management program. While designed primarily with transmission systems in mind, it is also
applicable to distribution projects. As presented in ANSI A300 part 7 and the ISA best
management practices, IVM consists of 6 elements:
1)
2)
3)
4)
5)
6)
Set Objectives
Evaluate the Site
Define Action Thresholds
Evaluate and Select Control Methods
Implement IVM
Monitor Treatment and Quality Assurance
The setting of objectives, defining action thresholds, and evaluating and selecting control
methods all require decisions. The planning and implementation process is cyclical and
continuous, because vegetation is dynamic and managers must have the flexibility to adjust their
plans. Adjustments may be made at each stage as new information becomes available and
circumstances evolve.
Set Objectives
Objectives should be clearly defined and documented. Examples of objectives can
include promoting safety, preventing sustained outages caused by vegetation growing
into electric facilities, maintaining regulatory compliance, protecting structures and
security, restoring electric service during emergencies, maintaining access and clear lines
of sight, protecting the environment, and facilitating cost effectiveness.
Objectives should be based on site factors, such as workload and vegetation type, in
addition to human, equipment and financial resources. They will vary from utility to
utility and project to project, depending on line voltage and criticality, as well as
topographical, environmental, fiscal and political considerations. However, where it is
appropriate, the overriding focus should be on environmentally-sound, cost effective
control of species that potentially conflict with the electric facility, while promoting
compatible, early successional, sustainable plant communities.
Work Load Evaluations
Work-load evaluations are inventories of vegetation that could have a bearing on
management objectives. Work load assessments can capture a variety of vegetation
characteristics, such as location, height, species, size and condition, hazard status, density
and clearance from conductors. Assessments should be conducted considering voltage,
conductor sag from ambient temperatures and loading, and the potential influence of
wind on line sway.
Evaluate and Select Control Methods
Control methods are the process through which managers achieve objectives. The most
suitable control method best achieves management objectives at a particular site. Many
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cases call for a combination of methods. Managers have a variety of controls from which
to choose, including manual, mechanical, herbicide and tree growth regulators,
biological, and cultural options.
Manual Control Methods
Manual methods employ workers with hand-carried tools, including chainsaws,
handsaws, pruning shears and other devices to control incompatible vegetation. The
advantage of manual techniques is that they are selective and can be used where others
may not be. On the other hand, manual techniques can be inefficient and expensive
compared to other methods.
Mechanical Control Methods
Mechanical controls are done with machines. They are efficient and cost effective,
particularly for clearing dense vegetation during initial establishment, or reclaiming
neglected or overgrown right of way. On the other hand, mechanical control methods can
be non-selective and disturb sensitive sites.
Tree Growth Regulator and Herbicide Control Methods
Tree growth regulators and herbicides can be effective for vegetation management. Tree
growth regulators (TGRs) are designed to reduce growth rates by interfering with natural
plant processes. TGRs can be helpful where removals are prohibited or impractical by
reducing the growth rates of some fast-growing species.
Herbicides control plants by interfering with specific botanical biochemical pathways.
Herbicide use can control individual plants that are prone to re-sprout or sucker after
removal. When trees that re-sprout or sucker are removed without herbicide treatment,
dense thickets develop, impeding access, swelling workloads, increasing costs, blocking
lines-of-site, and deteriorating wildlife habitat. Treating suckering plants allows early
successional, compatible species to dominate the right-of-way and out-compete
incompatible species, ultimately reducing work.
Cultural Control Methods
Cultural methods modify habitat to discourage incompatible vegetation and establish and
manage desirable, early successional plant communities. Cultural methods take
advantage of seed banks of native, compatible species lying dormant on site. In the long
run, cultural control is the most desirable method where it is applicable.
A cultural control known as cover-type conversion provides a competitive advantage to
short-growing, early successional plants, allowing them to thrive and eventually outcompete unwanted tree species for sunlight, essential elements and water. The early
successional plant community is relatively stable, tree-resistant and reduces the amount
of work, including herbicide application, with each successive treatment.
Wire-Border Zone
The wire-border zone technique is a management philosophy that can be applied through
cultural control. W.C. Bramble and W.R. Byrnes developed it in the mid-1980s out of
research begun in 1952 on a transmission right-of-way in the Pennsylvania State Game
Lands 33 Research and Demonstration project (Yahner and Hutnik (2004).
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The wire zone is the section of a utility transmission right-of-way directly under the wires
and extending outward about 10 feet on each side. The wire zone is managed to promote
a low-growing plant community dominated by grasses, herbs and small shrubs (under 3
feet in height at maturity). The border zone is the remainder of the right-of-way. It is
managed to establish small trees and tall shrubs (under 25 feet in height at maturity).
When properly managed, diverse, tree-resistant plant communities develop in wire and
border zones. The communities not only protect the electric facility and reduce long-term
maintenance, but also enhance wildlife habitat, forest ecology and aesthetic values.
Although the wire-border zone is a best practice in many instances, it is not necessarily
universally suitable. For example, standard wire-border zone prescriptions may be
unnecessary where lines are high off the ground, such as across low valleys or canyons,
so the technique can be modified without sacrificing reliability.
One way to accommodate variances in topography is to establish different regions based
on wire height. For example, over canyon bottoms or other areas where conductors are
100 feet or more above the ground, only a few trees are likely to be tall enough to conflict
with the lines. In those cases, trees that potentially interfere with the transmission lines
can be removed selectively on a case-by-case basis.
In areas where the wire is lower, perhaps between 50-100 feet from the ground, a border
zone community can be developed throughout the right-of-way. Note that in many cases,
conductor attachment points are more than 50 feet off the ground, so a border zone
community can be cultivated near structures. Where the line is less than 50 feet off the
ground, managers could apply a full wire-border zone prescription.
An environmental advantage of this type of modification is stream protection. Streams
often course through the valleys and canyons where lines are likely to be elevated.
Leaving timber or border zone communities in canyon bottoms helps shelter this valuable
habitat, enabling managers to achieve environmentally sensitive objectives.
Implement IVM
All laws and regulations governing IVM practices and specifications written by qualified
vegetation managers must be followed. Integrated vegetation management control
methods should be implemented on regular work schedules, which are based on
established objectives and completed assessments. Work should progress systematically,
using control measures determined to be best for varying conditions at specific locations
along a right-of-way. Some considerations used in developing schedules include the
importance and type of line, vegetation clearances, work loadsworkloads, growth rate of
predominant vegetation, geography, accessibility, and in some cases, time lapsed since the
last scheduled work.
Clearances Following Work
Clearances following work should be sufficient to meet management objectives,
including preventing trees from entering the Minimum Vegetation Clearance Distance,
electric safety risks, service-reliability threats and cost.
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Monitor Treatment and Quality Assurance
An effective program includes documented processes to evaluate results. Evaluations
can involve quality assurance while work is underway and after it is completed.
Monitoring for quality assurance should begin early to correct any possible
miscommunication or misunderstanding on the part of crewmembers. Early and
consistent observation and evaluation also provides an opportunity to modify the plan, if
need be, in time for a successful outcome.
Utility vegetation management programs should have systems and procedures in place
for documenting and verifying that vegetation management work was completed to
specifications. Post-control reviews can be comprehensive or based on a statistically
representative sample. This final review points back to the first step and the planning
process begins again.
Summary of A-300 example
Integrated Vegetation Management offers among others, a systematic way of planning and
implementing a vegetation management program as presented in ANSI A300 Part 7. This
methodology enables a program to comply with the NERC Transmission Vegetation
Management Program standard (FAC-003-2). Managers should select control options to best
promote management objectives.
Vegetation Inspections
As with the ANSI A-300 example, The Transmission Owner’s transmission vegetation
management program (TVMP)standard in R6 establishes the frequency of vegetation
inspections. These inspections can be used to “evaluate the site” as referred to in the second
element of ANSI A300 Part 7. This necessary frequency may need to be less than the annually
based upon many factors. Such local and environmental factors may includeon anticipated
growth rates of the local vegetation, length of the growing season for the geographical area,
limited Rights of WayROW width, rainfall amounts, etc.
Annual Work Plan
Requirement R7 of the Standard addresses the execution of the annual work plan. A
comprehensive approach that exercises the full extent of legal rights is superior to incremental
management in the long term because it reduces overall encroachments, and it ensures that future
planned work and future planned inspection cycles are sufficient at all locations on the Right of
WayROW. Removal is superior to pruning. Removal minimizes the possibility of conflicts
between energized conductors and vegetation. SinceWhen this is not always possible, the
Transmission Owner’s approach should be to use its prescribed vegetation maintenance methods
to work towards or achieve the maximum use of the Right of WayROW.
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Requirement R4
R4. Each Transmission Owner, without any
intentional time delay, shall notify the
control center holding switching
authority for the associated applicable
transmission line when the Transmission
Owner has confirmed the existence of a
vegetation condition that is likely to
cause a Fault at any moment.
Rationale
ToThis is to ensure expeditious
communication between the Transmission
Owner and the control center when a critical
situation is confirmed.
[VRF – Medium] [Time Horizon – Real-time]
M4. Each Transmission Owner that has a confirmed vegetation condition likely to cause a Fault
at any moment will have evidence that it notified the control center holding switching
authority for the associated transmission line without any intentional time delay. Examples
of evidence may include control center logs, voice recordings, switching orders, clearance
orders and subsequent work orders. (R4)
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the
Transmission Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4
involves the notification of potentially threatening vegetation conditions, without any intentional
delay, to the control center holding switching authority for that specific transmission line.
Examples of acceptable unintentional delays may include communication system problems (for
example, cellular service or two-way radio disabled), crews located in remote field locations
with no communication access, delays due to severe weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of a Transmission Owner’s employee who personally identifies such a threat in the
field. Confirmation could also be made by sending out an employee to evaluate a situation
reported by a landowner.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an assessment
of the possible sag or movement of the conductor while operating between no-load conditions
and its rating.
The Transmission Owner has the responsibility to ensure the proper communication between
field personnel and the control center to allow the control center to take the appropriate action
until the vegetation threat is relieved. Appropriate actions may include a temporary reduction in
the line loading, switching the line out of service, or positioning the system in recognition of the
increasing risk of outage on that circuit. The notification of the threat should be communicated in
terms of minutes or hours as opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some Transmission Owners may have a danger tree identification
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program that identifies trees for removal with the potential to fall near the line. These trees
would not require notification to the control center unless they pose an immediate fall-in threat.
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Requirement R5
R5. When a Transmission Owner is
constrained from performing vegetation
work on an applicable line operating
within their Rating and all Rated Electrical
Operating Conditions, and the constraint
may lead to a vegetation encroachment
into the MVCD of its applicable
transmission lines prior to the
implementation of the next annual work
plan, then the Transmission Owner shall
take corrective action to ensure continued
vegetation management to prevent
encroachments. [VRF – Medium] [Time
Horizon – Operations Planning]
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
Transmission Owner from performing
planned vegetation maintenance work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the Transmission Owner to put interim
measures in place, rather than do nothing.
The corrective action process is not intended
to address situations where a planned work
methodology cannot be performed but an
alternate work methodology can be used.
M5. Each Transmission Owner has evidence of the corrective action taken for each constraint
where an applicable transmission line was put at potential risk. Examples of acceptable
forms of evidence may include initially-planned work orders, documentation of constraints
from landowners, court orders, inspection records of increased monitoring,
documentation of the de-rating of lines, revised work orders, invoices, andor evidence that
a line was de-energized. (R5)
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
Transmission Owner for the mitigation of Sustained Outage risk when temporarily constrained
from performing vegetation maintenance. The intent of this requirement is to deal with situations
that prevent the Transmission Owner from performing planned vegetation management work
and, as a result, have the potential to put the transmission line at risk. Constraints to performing
vegetation maintenance work as planned could result from legal injunctions filed by property
owners, the discovery of easement stipulations which limit the Transmission Owner’s rights, or
other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
Transmission Owner is not under any immediate time constraint for achieving the management
objective, can easily reschedule work using an alternate approach, and therefore does not need to
take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the Transmission Owner is required to take an interim corrective action to mitigate the potential
risk to the transmission line. A wide range of actions can be taken to address various situations.
General considerations include:
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•
•
•
•
•
Identifying locations where the Transmission Owner is constrained from performing
planned vegetation maintenance work which potentially leaves the transmission line
at risk.
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for each location.
In developing the specific action to mitigate the potential risk to the transmission line
the Transmission Owner could consider location specific measures such as modifying
the inspection and/or maintenance intervals. Where a legal constraint would not allow
any vegetation work, the interim corrective action could include limiting the loading
on the transmission line.
The Transmission Owner should document and track the specific corrective action
taken at each location. This location may be indicated as one span, one tree or a
combination of spans on one property where the constraint is considered to be
temporary.
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Requirement R6
R6. Each Transmission Owner shall perform a
Vegetation Inspection of 100% of its
applicable transmission lines (measured
in units of choice - circuit, pole line, line
miles or kilometers, etc.) at least once per
calendar year and with no more than 18
months between inspections on the same
ROW. 6
[VRF – Medium] [Time Horizon –
Operations Planning]
Rationale
Inspections are used by Transmission Owners
to assess the condition of the entire ROW. The
information from the assessment can be used to
determine risk, determine future work and
evaluate recently-completed work. This
requirement sets a minimum Vegetation
Inspection frequency of once per calendar year
but with no more than 18 months between
inspections on the same ROW. Based upon
average growth rates across North America
and on common utility practice, this minimum
frequency is reasonable. Transmission Owners
should consider local and environmental
factors that could warrant more frequent
inspections.
M6. Each Transmission Owner has evidence
that it conducted Vegetation Inspections of
the transmission line ROW for all
applicable transmission lines at least once
per calendar year but with no more than
18 months between inspections on the same ROW. Examples of acceptable forms of
evidence may include completed and dated work orders, dated invoices, or dated
inspection records. (R6)
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections that fits general industry practice. In addition, the fact that Vegetation
Inspections can be performed in conjunction with general line inspections further facilitates a
Transmission Owner’s ability to meet this requirement. However, the Transmission Owner may
determine that more frequent inspections are needed to maintain reliability levels, dependent
upon such factors as anticipated growth rates of the local vegetation, length of the growing
season for the geographical area, limited ROW width, and rainfall amounts. Therefore it is
expected that some transmission lines may be designated with a higher frequency of inspections.
The SDTFootnote 5 is added footnote 3 to address the situation where a Transmission Owner
through no fault of its own, would be unable to complete the vegetation inspection within the
allotted time period. This would include the situation of mutual aid as well as disasters to the
Transmission Owner’s own system.
The VSL for Requirement R6 has VSL categories ranked by the percentage of the required ROW
inspections completed. To calculate the percentage of inspection completion, the Transmission
Owner may choose units such as: line miles or kilometers, circuit miles or kilometers, pole line
miles, ROW miles, etc.
6
When the Transmission Owner is prevented from performing a Vegetation Inspection within the timeframe in R6
due to a natural disaster, the TO is granted a time extension that is equivalent to the duration of the time the TO was
prevented from performing the Vegetation Inspection.
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For example, when a Transmission Owner operates 2,000 miles of 230 kVapplicable
transmission lines this Transmission Owner will be responsible for inspecting all the 2,000 miles
of 230 kV transmission lines at least once during the calendar year. If one of the included lines
was 100 miles long, and if it was not inspected during the year, then the amount failed to inspect
would be 100/2000 = 0.05 or 5%. The “Low VSL” for R6 would apply in this example.
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The “Low VSL” for R6 would apply in this example.
Requirement R7
R7.
Each Transmission Owner shall complete
Rationale
100% of its annual vegetation work plan
This requirement sets the expectation that the
of applicable lines to ensure no
work identified in the annual work plan will
vegetation encroachments occur within
be completed as planned. An annual
the MVCD. Modifications to the work
vegetation work planIt allows for
plan in response to changing conditions
workmodifications to be modifiedthe
or to findings from vegetation inspections
planned work for changing conditions, taking
may be made (provided they do not put
into consideration anticipated growth of
the transmission system at riskallow
vegetation and all other environmental
encroachment of a vegetation
factors, provided that the changesthose
encroachmentinto the MVCD) and must
modifications do not violate theput the
be documented. The percent completed
calculation is based on the number of units actually completed divided by the number of
units in the final amended plan (measured in units of choice - circuit, pole line, line miles
or kilometers, etc.) Examples of reasons for modification to annual plan may include:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of a Transmission Owner 7
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
[VRF – Medium] [Time Horizon – Operations Planning]
M7. Each Transmission Owner has evidence that it completed its annual vegetation work plan.
Examples of acceptable forms of evidence may include a copy of the completed annual
work plan (including modifications if any), dated work orders, dated invoices, or dated
inspection records. (R7)
R7 is a risk-based requirement. The Transmission Owner is required to implement an annualits
work plan for vegetation management to accomplish the purpose of this Standard. Modifications
to the work plan in response to changing conditions or to findings from vegetation inspections
may be made and documented provided they do not put the transmission system at risk. The
7
circumstancesCircumstances that are beyond the control of a Transmission Owner include but are not limited to
natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, ice storms, floods, or major storms as
defined either by the TO or an applicable regulatory body, ice storms, and floods; arboricultural, horticultural or
agricultural activities.
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annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a
“line-by-line” detailed description of all work to be performed. It is only intended to require that
the Transmission Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation into
the MVCD.
For example, when a Transmission Owner identifies 1,000 miles of applicable transmission lines
to be completed in the TO’s annual plan, the Transmission Owner will be responsible completing
those identified miles. If a TO makes a modification to the annual plan that does not put the
transmission system at risk of an encroachment the annual plan may be modified. If 100 miles of
the annual plan is deferred until next year the calculation to determine what percentage was
completed for the current year would be: 1000 – 100 (deferred miles) = 900 modified annual
plan, or 900 / 900 = 100% completed annual miles. If a TO only completed 875 of the total 1000
miles with no acceptable documentation for modification of the annual plan the calculation for
failure to complete the annual plan would be: 1000 – 875 = 125 miles failed to complete then,
125 miles (not completed) / 1000 total annual plan miles = 12.5% failed to complete.
The ability to modify the work plan allows the Transmission Owner to change priorities or
treatment methodologies during the year as conditions or situations dictate. For example recent
line inspections may identify unanticipated high priority work, weather conditions (drought)
could make herbicide application ineffective during the plan year, or a major storm could require
redirecting local resources away from planned maintenance or work may be deferred to a
subsequent year because of slower-than-expected growth. This situation may also include
complying with mutual assistance agreements by moving resources off the Transmission
Owner’s system to work on another system. Any of these examples could result in acceptable
deferrals or additions to the annual work plan. Modifications to the annual work plan must
always ensure the reliability of the electric Transmission system.
In general, the vegetation management maintenance approach should use the full extent of the
Transmission Owner’s legal rights on the ROW. A comprehensive approach that exercises the
full extent of legal rights on the ROW is superior to incremental management in the long term
because it reduces the overall potential for encroachments, and it ensures that future planned
work and future planned inspection cycles are sufficient.
When developing the annual work plan, the Transmission Owner should allow time for
reasonable and predictable procedural requirements to obtain permits to work on federal, state,
provincial, public, tribal lands. In some cases, the lead time for obtaining permits may
necessitate preparing work plans more than a year prior to thework start of work.dates.
Transmission Owners may also need to consider those special landowner requirements as
documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the Transmission
Owner, evidence of successful annual work plan execution could consist of signed-off work
orders, signed contracts, printouts from work management systems, spreadsheets of planned
versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence
may include photographs and walk-through reports.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
42
NERC Standard FAC-003-2 Technical Reference
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
43
NERC Standard FAC-003-2 Technical Reference
Appendix 1: Clearance Distance Derivation by the Gallet
Equation
The Gallet Equation is a well-known method of computing the required strike distance for proper
insulation coordination, and has the ability to take into account various air gap geometries, as
well as non-standard atmospheric conditions. When the Gallet Equation and conservative
probabilistic methods are combined, i.e. deterministic design, sparkoverspark-over probabilities
of 10-6 or less are achieved. This approach is well known for its conservatism and was used to
design the first 500 kV and 765 kV lines in North America [1]. Thus, the deterministic design
approach using the Gallet Equation is used for the standard to compute the minimum strike
distance between transmission lines and the vegetation that may be present in or along the
transmission corridor.
Method Explanation (Gallet Equation)
In 1975 G. Gallet published a benchmark paper that provided a method to compute the critical
flashover voltage (CFO) of various air gap geometries [4]. The Gallet Equation uses various
“gap factors” to take into account various air gap geometries. Various gap factor values are
provided in [1]. If the vegetation in a transmission corridor, e.g. a tree, is assumed electrically to
be a large structure then the CFO of such an air gap geometry can be computed for dry or wet
conditions using a well established equation proposed by Gallet [1],[2],[4],
CFOA = k w ⋅ k g ⋅ δ m ⋅
3400
8
1+
D
(1)
where,
kw
is defined as the factor that takes into account wet or dry conditions (dry = 1.0
and wet = 0.96) and phase arrangement (multiply by 1.08 for outside phase), e.g.
outside phase and wet conditions = (0.96)(1.08) = 1.037,
kg
is defined as the gap factor (1.3 for conductor to large structure),
D
is the strike distance (m),
CFOA
is the CFO for the relative air density (kV).
δ
is defined as the relative air density and is approximately equal to (2) where A is
the altitude in km,
δ =e
−
A
8.6
(2)
=
m 1.25G0 ( G0 − 0.2 )
(3)
CFOs
500 ⋅ D
(4)
G0 =
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
44
NERC Standard FAC-003-2 Technical Reference
CFOs = k w ⋅ k g ⋅
3400
8
1+
D
(5)
where CFOS is the CFO for standard atmospheric conditions (kV). Using (1)-(5), the required CFOA can be
computed using an iterative process.
Once the CFOA is known, deterministic methods can be used to determine the required clearance
distance. If we let the maximum switching overvoltage be equal to the withstand voltage of the
air gap (CFOA - 3σ) then the CFOA can be written as (6).
Vm
σ
1− 3
CFOA
CFOA =
(6)
where
Vm is equal to the maximum switching overvoltage, i.e. the value that has a 0.135% chance of being
exceeded,
σ is the standard deviation of the air gap insulation,
CFOA is the critical flashover voltage of the air gap insulation under non-standard atmospheric conditions.
The ratio of σ to the CFOA given in (6) can be assumed to be 0.05 (5%) [1]. Thus, (6) can be
written as (7).
CFOA =
Vm
0.85
(7)
Substituting (7) into (1) we arrive at (8).
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ m ⋅
3400
8
1+
D
(8)
Equation 8 relates the maximum transient overvoltage, Vm, to the air gap distance, D. Using (8)
to compute the required clearance distance for the specified air gap geometry (conductor to large
structure) results in a probability of flashover in the range of 10-6.
TRANSIENT OVERVOLTAGE
In general, the worst case transient overvoltages occurring on a transmission line are caused by
energizing or re-energizing the line with the latter being the extreme case if trapped charge is
present. The intent of FAC-003 is to keep a transmission line that is in service from becoming
de-energized (i.e. tripped out) due to sparkover from the line conductor to nearby vegetation.
Thus, the worst case scenarios that are typically analyzed for insulation coordination purposes
(e.g. line energization and re-energization) can be ignored. For the purposes of FAC-003-2, the
worst case transient overvoltage then becomes the maximum value that can occur with the line
energized. Determining a realistic value of transient overvoltage for this situation is difficult
because the maximum transient overvoltage factors listed in the literature are based on a
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
45
NERC Standard FAC-003-2 Technical Reference
switching operation of the line in question. In other words, these maximum overvoltage values
(e.g. the values listed in [2], [3] and [5]) are based on the assumption that the subject line is being
energized, re-energized or de-energized. These operations, by their very nature, will create the
largest transient overvoltages. Typical values of transient overvoltages of in-service lines, as
such, are not readily available in the literature because the resulting level of overvoltage is
negligible compared with the maximum (e.g. re-energizing a transmission line with trapped
charge). A conservative value for the maximum transient overvoltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 p.u.[2]. This value is a
conservative estimate of the transient overvoltage that is created at the point of application (e.g. a
substation) by switching a capacitor bank without a pre-insertion device (e.g. closing resistors).
At voltage levels where capacitor banks are not very common (e.g. 362 kV), the maximum
transient overvoltage of an “in-service” ac line are created by fault initiation on adjacent ac lines
and shunt reactor bank switching. These transient voltages are usually 1.5 p.u. or less [2]. It is
well known that these theoretical transient overvoltages will not be experienced at locations
remote from the bus at which they were created; however, in order to be conservative, it will be
assumed that all nearby ac lines are subjected to this same level of overvoltage. Thus, a
maximum transient overvoltage factor of 2.0 p.u. for 242302 kV and below and 1.4 p.u. for ac
transmission lines 362 kV and above is used to compute the required clearance distances for
vegetation management purposes.
The overvoltage characteristics of dc transmission lines vary somewhat from their ac
counterparts. The referenced empirically derived transient overvoltage factor used to calculate
the minimum clearance distances from dc transmission lines to vegetation for the purpose of
FAC-003-2 will be 1.8 p.u.[3].
EXAMPLE CALCULATION
An example calculation is presented below using the proposed method of computing the
vegetation clearance distances. It is assumed that the line in question has a maximum operating
voltage of 550 kVrms line-to-line. Using a per unit transient overvoltage factor of 1.4, the result
is a peak transient voltage of 629 kVcrest. It is further assumed that the line in question operates
at a maximum altitude of 7000 feet (2.134 km) above sea level.
The required withstand voltage of the air gap must be equal to or greater than 629 kVcrest. Since
the altitude is above sea level, (1) - (5) have to be iterated on to achieve the desired result.
Equation (9) can be used as an initial guess for the clearance distance.
Di =
8
3400 ⋅ k w ⋅ k g
Vm
0.85
(9)
−1
For our case here, Vm is equal to 629 kV, kw = 1.037 and kg = 1.3. Thus,
Di =
8
3400 ⋅ k w ⋅ k g
Vm
0.85
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
=
−1
8
= 1.535m
3400 ⋅ 1.037 ⋅ 1.3
−1
629
0.85
(10)
46
NERC Standard FAC-003-2 Technical Reference
Using (2)-(5) and (8) the withstand voltage of the air gap is next computed. This value will then
be compared to the maximum transient overvoltage.
CFOS = k w ⋅ k g ⋅
−
3400
3400
= 1.037 ⋅ 1.3 ⋅
= 737.7 kV
8
8
1+
1+
D
1.535
A
−
2.134
8.6
8.6
=
δ e=
e =
0.78
(12)
CFOS
737.7
=
= 0.961
500 ⋅ D (500 ) ⋅ (1.535 )
(13)
GO =
m = 1.25 ⋅ GO (GO − 0.2 ) = 1.25 ⋅ 0.961(0.961 − 0.2 ) = 0.915
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ
m
(11)
3400
3400
0.915
⋅
= (0.85 )(1.037 )(1.3 )(0.78 )
8
8
1+
1+
D
1.535
(14)
= 499.8 kV
(15)
The calculated Vm is less than 629 kV; thus, the clearance distance must be increased. A few
iterations using (2)-(5) and (8) are required until the computed Vm ≥ 629 kV. For this case it was
found that D = 1.978 m (6.49 feet) yielded Vm = 629.3 kV. Using this clearance distance the
following values were computed for the final iteration.
CFOS = k w ⋅ k g ⋅
=
δ
3400
3400
= 1.037 ⋅ 1.3 ⋅
= 908.5 kV
8
8
1+
1+
D
1.978
A
8.6
e=
−
GO =
−
e
2.134
8.6
=
0.78
(17)
CFOS
908.5
=
= 0.919
500 ⋅ D (500 ) ⋅ (1.978 )
(18)
m = 1.25 ⋅ GO (GO − 0.2 ) = 1.25 ⋅ 0.919(0.919 − 0.2 ) = 0.825
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ m ⋅
3400
3400
= (0.85 )(1.037 )(1.3 )(0.78 )0.825
8
8
1+
1+
D
1.978
(16)
(19)
= 629.3kV
(20)
Therefore, the minimum vegetation clearance distance for a maximum line to line ac operating
voltage of 550 kV at 7000 feet above sea level is 1.978 m (6.49 feet). Table 1 provides
calculated distances for various altitudes and maximum system operating ac voltages.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
47
NERC Standard FAC-003-2 Technical Reference
TABLE 1 — Minimum Vegetation Clearance Distances (MVCD)
For Alternating Current Voltages (feet)
MVCD
(feet
( AC )
Nominal
System
Voltage
(kV)(KV)
( AC )
Maximum
System
Voltage
(kV) 10
MVCD
(feet)
MVCD
feet
(meters)
)
sea level
550
345
362
287
302
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
(meters)
3,000ft
(914.4m
)
(meters)
4,000ft
(1219.2
m)
(meters)
5,000ft
(1524m)
(meters)
6,000ft
(1828.8
m)
(meters)
7,000ft
(2133.6
m)
(meter
s)
8,000ft
(2438.4
m)
(meter
s)
9,000ft
(2743.2
m)
(meter
s)
10,000ft
(3048m)
(meters)
11,000ft
(3352.8
m)
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over
10000 ft
up to
11000 ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
8.61ft
(2.71m)
(2.80m)
(2.88m)
(2.97m)
(3.05m)
(3.14m)
(3.22m)
(3.31m)
(3.39m)
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
5.25ft
5.45ft
(1.73m)
(1.79m)
(1.85m)
(1.91m)
(1.98m)
(2.04m)
(2.11m)
(2.17m)
(2.24m)
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
19ft
3.26ft
3.39ft
(1.08m)
(1.12m)
(1.16m)
(1.21m)
(1.26m)
(1.30m)
(1.35m)
(1.40m)
(1.44m)
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
3.09ft
3.22ft
(1.02m)
(1.06m)
(1.11m)
(1.15m)
(1.19m)
(1.24m)
(1.29m)
(1.33m)
(1.38m)
15ft
3.12ft
2.97ft
(0.91m)
242
MVCD
feet
8.33ft
2ft
(0.95m)
230
MVCD
feet
Over 2000
ft up to
3000 ft
5.06ft
(1.54m)
500
MVCD
feet
Over 1000
ft up to
2000 ft
8.06ft
(2.46m)
800
MVCD
feet
Over 500
ft up to
1000 ft
Over sea
level up to
500 ft
765
9
3.03ft
2ft
(0.61m)
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
161*
169
2.05ft
1.7ft
2.09ft
2.19ft
(0.69m)
(0.73m)
(0.76m)
(0.79m)
(0.82m)
(0.85m)
(0.89m)
(0.92m)
(0.96m)
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
138*
145
(0.52m)
1.78ft
1.86ft
(0.59m)
(0.62m)
(0.65m)
(0.67m)
(0.70m)
(0.73m)
(0.76m)
(0.79m)
(0.82m)
9
The distances in this Table are the minimums required to prevent FlashoverFlash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will be
achieved at time of vegetation maintenance.
10
Where applicable lines are operated at nominal voltages other than those listed, The Transmission Owner should use the maximum system voltage to determine the
appropriate clearance for that line.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
48
NERC Standard FAC-003-2 Technical Reference
74ft
1.41ft
(0.43m)
115*
121
88*
100
69*
72
44ft
1.15ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
1.47ft
1.54ft
(0.49m)
(0.51m)
(0.53m)
(0.56m)
(0.58m)
(0.61m)
(0.63m)
(0.66m)
(0.69m)
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
1.21ft
1.26ft
(0.40m)
(0.42m)
(0.44m)
(0.46m)
(0.48m)
(0.50m)
(0.52m)
(0.54m)
(0.57m)
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
0.86ft
0.90ft
(0.29m)
(0.30m)
(0.31m)
(0.33m)
(0.34m)
(0.36m)
(0.37m)
(0.39m)
(0.41m)
(0.35m)
18ft
0.82ft
(0.25m)
84ft
* Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above).
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
49
NERC Standard FAC-003-2 Technical Reference
TABLE 1 (CONT.)) — Minimum Vegetation Clearance Distances (MVCD) 7
For DirectAlternating Current Voltages (meters)
( DC )
AC )
Nominal
Pole to
Groun
d
( AC )
Maximum
System
Voltage
8
(kV)
MVCD
feet (
(kV)
±750
meters)
13.92ft
(4.24m)
Over sea
level
up to
152.4m
±600
Over 152.4m
up to
304.8m
Over 304.8m
up to
609.6m
7.89ft
(2.40m)
800
49m
550
57m
MVCD feet
( meters)
MVCD feet
meters)
3,000ft
(914.4m)
Alt.
4,000ft
(1219.2m)
Alt.
5,000ft
(1524m)
Alt.
15.07ft
(4.59m)Ov
15.45ft
(4.71m)Ov
15.82ft
(4.82m)Ove
er 609.6m
up to
914.4m
er 914.4m
up to
1219.2m
r 1219.2m up
to
1524m
8.71ft
(2.65m)71
2.54m
2.62m
4.78ft
(1.46m)
±40050
MVCD feet
( meters)
11.04ft
(3.36m)
10.07ft (3.07m)
±50076
0
MVCD
meters
sea
level
System
Voltage
(KV)
5
MVCD
meters
1.6m
1.66m
3.43ft
(1.05m)
11.35ft
(3.46m)
8.99ft
(2.74m)80
m
m
5.35ft
(1.63m)73
5.55ft
(1.69m)79
m
m
4.02ft
(1.23m)08
4.02ft
(1.23m)12
11.66ft
(3.55m)
(
5.75ft
(1.75m)85m
362
0.97m
0.99m
1.03m
m
m
4.18ft
(1.27m)16m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
230
242
0.92m
0.94m
0.98m
1.02m
161*
169
0.62m
0.64m
0.67m
138*
145
0.53m
0.54m
115*
121
0.44m
0.45m
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
(
MVCD feet
meters)
(
MVCD feet
meters)
(
MVCD feet
meters)
(
MVCD feet
( meters)
(8,000ft
(2438.4m)
Alt.
9,000ft
(2743.2m)
Alt.
10,000ft
(3048m)
Alt.
11,000ft
(3352.8m)
Alt.
16.2ft
(4.94m)Ov
16.55ft
(5.04m)Ove
16.9ft
(5.15m)Over
17.27ft
(5.26m)Over
17.62ft
(5.37m)Ove
17.97ft
(5.48m)Ov
er 1524 m
up to
1828.8m
r 1828.8m up
to
2133.6m
2133.6m up to
2438.4m
2438.4m up to
2743.2m
r 2743.2m up
to
3048m
er 3048m up
to 3352.8m
11.98ft
(3.65m)
9.25ft
(2.82m)88m
MVCD feet
meters)
7,000ft
(2133.6m)
Alt.
6,000ft
(1828.8m)
Alt.
5
±25034
MVCD feet
( meters)
12.3ft
(3.75m)
9.55ft
(2.91m)97
9.82ft
(2.99m)3.05
m
m
5.95ft
(1.81m)91
m
4.34ft
(1.32m)21
6.15ft
(1.87m)98m
12.62ft
(3.85m)
10.1ft
(3.08m)14m
6.36ft
(1.94m)2.04
m
12.92ft
(3.94m)
10.38ft
(3.16m)22m
6.57ft
(2.00m)11m
13.24ft
(4.04m)
(13.54ft
4.13m)
10.65ft
(3.25m)31m
6.77ft
(2.06m)17m
10.92ft
(3.33m)39
m
6.98ft
(2.13m)24
m
5.17ft
(1.58m)44
m
4.5ft
(1.37m)26m
4.66ft
(1.42m)30m
4.83ft
(1.47m)35m
5ft
(1.52m)40m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
50
m
NERC Standard FAC-003-2 Technical Reference
88*
69*
∗
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
51
NERC Standard FAC-003-2 Technical Reference
TABLE 1 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
±750
±600
±500
±400
±250
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
Over sea
level up to
500 ft
Over 500 ft
up to
1000 ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000 ft
up to 7000
ft
Over 7000 ft
up to 8000
ft
Over 8000 ft
up to 9000
ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over 152.4
m up to
304.8 m
(Over 304.8
m up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to 1219.2m
(Over
1219.2m up
to 1524m
(Over 1524
m up to
1828.8 m)
(Over
1828.8m up
to 2133.6m)
(Over
2133.6m up
to 2438.4m)
(Over
2438.4m up
to 2743.2m)
(Over
2743.2m up
to 3048m)
(Over
3048m up to
3352.8m)
14.12ft
(4.30m)
10.23ft
(3.12m)
8.03ft
(2.45m)
6.07ft
(1.85m)
3.50ft
(1.07m)
14.31ft
(4.36m)
10.39ft
(3.17m)
8.16ft
(2.49m)
6.18ft
(1.88m)
3.57ft
(1.09m)
14.70ft
(4.48m)
10.74ft
(3.26m)
8.44ft
(2.57m)
6.41ft
(1.95m)
3.72ft
(1.13m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
6.63ft
(2.02m)
3.87ft
(1.18m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
6.86ft
(2.09m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
7.09ft
(2.16m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
7.33ft
(2.23m)
4.34ft
(1.32m)
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
7.56ft
(2.30m)
4.5ft
(1.37m)
16.91ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
7.80ft
(2.38m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
8.03ft
(2.45m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
8.27ft
(2.52m)
5.00ft
(1.52m)
17.97ft
(5.48m)
13.54ft
(4.13m)
10.92ft
(3.33m)
8.51ft
(2.59m)
5.17ft
(1.58m)
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
52
NERC Standard FAC-003-2 Technical Reference
List of Acronyms and Abbreviations
ANSI
American National Standards Institute
IEEE
Institute of Electrical and Electronics Engineers
IVM
Integrated Vegetation Management
NERC
North American Electric Reliability Corporation
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
53
NERC Standard FAC-003-2 Technical Reference
References
Andrew Hileman, Insulation Coordination for Power System, Marcel Dekker, New York, NY
1999
EPRI, EPRI Transmission Line Reference Book 345 kV and Above, Electric Power Research
Council, Palo Alto, Ca. 1975.
IEEE Std. 516-2003 IEEE Guide for Maintenance Methods on Energized Power Lines
G. Gallet, G. Leroy, R. Lacey, I. Kromer, General Expression for Positive Switching Impulse
Strength Valid Up to Extra Long Air Gaps, IEEE Transactions on Power Apparatus and
Systems, Vol. pAS-94, No. 6, Nov./Dec. 1975.
IEEE Std. 1313.2-1999 (R2005) IEEE Guide for the Application of Insulation Coordination.
2007 National Electric Safety Code
EPRI, HVDC Transmission Line Reference Book, EPRI TR-102764 , Project 2472-03, Final
Report, September 1993
ANSI. 2001. American National Standard for Tree Care Operations – Tree, Shrub, and Other
Plant Maintenance – Standard Practices (Pruning). Part 1. American National Standards
Institute, NY
ANSI. 2006. American National Standard for Tree Care Operations – Tree, Shrub, and Other
Plant Maintenance – Standard Practices (Integrated Vegetation Management a. Electric
Utility Rights-of-way). Part 7. American National Standards Institute, NY.
Cieslewicz, S. and R. Novembri. 2004. Utility Vegetation Management Final Report. Federal
Energy Regulatory Commission. Commissioned to support the Federal Investigation of the
August 14, 2003 Northeast Blackout. Federal Energy Regulatory Commission, Washington,
DC. pg. 39.
Kempter, G.P. 2004. Best Management Practices: Utility Pruning of Trees. International
Society of Arboriculture, Champaign, IL
Miller, R.H. 2007. Best Management Practices: Integrated Vegetation Management. Society of
Arboriculture, Champaign, IL.
Yahner, R.H. and R.J. Hutnik. 2004. Integrated Vegetation Management on an electric
transmission right-of-way in Pennsylvania, U.S. Journal of Arboriculture. 30:295-300
Results-based Initiative Ad Hoc Group. Acceptance Criteria of a Reliability Standard.
FAC-003-2 Technical Reference
December 17, 2010August 14, 2011
54
Standard FAC-003-1 — Transmission Vegetation Management Program
A.
B.
Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number:
FAC-003-1
3.
Purpose: To improve the reliability of the electric transmission systems by preventing
outages from vegetation located on transmission rights-of-way (ROW) and minimizing
outages from vegetation located adjacent to ROW, maintaining clearances between
transmission lines and vegetation on and along transmission ROW, and reporting vegetationrelated outages of the transmission systems to the respective Regional Reliability
Organizations (RRO) and the North American Electric Reliability Council (NERC).
4.
Applicability:
4.1. Transmission Owner.
4.2. Regional Reliability Organization.
4.3. This standard shall apply to all transmission lines operated at 200 kV and above and to
any lower voltage lines designated by the RRO as critical to the reliability of the
electric system in the region.
5.
Effective Dates:
5.1.
One calendar year from the date of adoption by the NERC Board of Trustees for
Requirements 1 and 2.
5.2.
Sixty calendar days from the date of adoption by the NERC Board of Trustees for
Requirements 3 and 4.
Requirements
R1. The Transmission Owner shall prepare, and keep current, a formal transmission vegetation
management program (TVMP). The TVMP shall include the Transmission Owner’s
objectives, practices, approved procedures, and work specifications 1.
R1.1. The TVMP shall define a schedule for and the type (aerial, ground) of ROW vegetation
inspections. This schedule should be flexible enough to adjust for changing
conditions. The inspection schedule shall be based on the anticipated growth of
vegetation and any other environmental or operational factors that could impact the
relationship of vegetation to the Transmission Owner’s transmission lines.
R1.2. The Transmission Owner, in the TVMP, shall identify and document clearances
between vegetation and any overhead, ungrounded supply conductors, taking into
consideration transmission line voltage, the effects of ambient temperature on
conductor sag under maximum design loading, and the effects of wind velocities on
conductor sway. Specifically, the Transmission Owner shall establish clearances to be
achieved at the time of vegetation management work identified herein as Clearance 1,
and shall also establish and maintain a set of clearances identified herein as Clearance
2 to prevent flashover between vegetation and overhead ungrounded supply
conductors.
R1.2.1. Clearance 1 — The Transmission Owner shall determine and document
appropriate clearance distances to be achieved at the time of transmission
vegetation management work based upon local conditions and the expected
time frame in which the Transmission Owner plans to return for future
1
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices, while
not a requirement of this standard, is considered to be an industry best practice.
Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
1 of 5
Standard FAC-003-1 — Transmission Vegetation Management Program
vegetation management work. Local conditions may include, but are not
limited to: operating voltage, appropriate vegetation management techniques,
fire risk, reasonably anticipated tree and conductor movement, species types
and growth rates, species failure characteristics, local climate and rainfall
patterns, line terrain and elevation, location of the vegetation within the span,
and worker approach distance requirements. Clearance 1 distances shall be
greater than those defined by Clearance 2 below.
R1.2.2. Clearance 2 — The Transmission Owner shall determine and document
specific radial clearances to be maintained between vegetation and conductors
under all rated electrical operating conditions. These minimum clearance
distances are necessary to prevent flashover between vegetation and
conductors and will vary due to such factors as altitude and operating voltage.
These Transmission Owner-specific minimum clearance distances shall be no
less than those set forth in the Institute of Electrical and Electronics Engineers
(IEEE) Standard 516-2003 (Guide for Maintenance Methods on Energized
Power Lines) and as specified in its Section 4.2.2.3, Minimum Air Insulation
Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 516-2003,
phase-to-ground distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 516-2003,
phase-to-phase voltages, with appropriate altitude correction
factors applied.
R1.3. All personnel directly involved in the design and implementation of the TVMP shall
hold appropriate qualifications and training, as defined by the Transmission Owner, to
perform their duties.
R1.4. Each Transmission Owner shall develop mitigation measures to achieve sufficient
clearances for the protection of the transmission facilities when it identifies locations
on the ROW where the Transmission Owner is restricted from attaining the clearances
specified in Requirement 1.2.1.
R1.5. Each Transmission Owner shall establish and document a process for the immediate
communication of vegetation conditions that present an imminent threat of a
transmission line outage. This is so that action (temporary reduction in line rating,
switching line out of service, etc.) may be taken until the threat is relieved.
R2. The Transmission Owner shall create and implement an annual plan for vegetation
management work to ensure the reliability of the system. The plan shall describe the methods
used, such as manual clearing, mechanical clearing, herbicide treatment, or other actions. The
plan should be flexible enough to adjust to changing conditions, taking into consideration
anticipated growth of vegetation and all other environmental factors that may have an impact
on the reliability of the transmission systems. Adjustments to the plan shall be documented as
they occur. The plan should take into consideration the time required to obtain permissions or
permits from landowners or regulatory authorities. Each Transmission Owner shall have
systems and procedures for documenting and tracking the planned vegetation management
work and ensuring that the vegetation management work was completed according to work
specifications.
Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
2 of 5
Standard FAC-003-1 — Transmission Vegetation Management Program
R3. The Transmission Owner shall report quarterly to its RRO, or the RRO’s designee, sustained
transmission line outages determined by the Transmission Owner to have been caused by
vegetation.
R3.1. Multiple sustained outages on an individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the actual number of outages within a 24hour period.
R3.2. The Transmission Owner is not required to report to the RRO, or the RRO’s designee,
certain sustained transmission line outages caused by vegetation: (1) Vegetationrelated outages that result from vegetation falling into lines from outside the ROW that
result from natural disasters shall not be considered reportable (examples of disasters
that could create non-reportable outages include, but are not limited to, earthquakes,
fires, tornados, hurricanes, landslides, wind shear, major storms as defined either by
the Transmission Owner or an applicable regulatory body, ice storms, and floods), and
(2) Vegetation-related outages due to human or animal activity shall not be considered
reportable (examples of human or animal activity that could cause a non-reportable
outage include, but are not limited to, logging, animal severing tree, vehicle contact
with tree, arboricultural activities or horticultural or agricultural activities, or removal
or digging of vegetation).
R3.3. The outage information provided by the Transmission Owner to the RRO, or the
RRO’s designee, shall include at a minimum: the name of the circuit(s) outaged, the
date, time and duration of the outage; a description of the cause of the outage; other
pertinent comments; and any countermeasures taken by the Transmission Owner.
R3.4. An outage shall be categorized as one of the following:
R3.4.1. Category 1 — Grow-ins: Outages caused by vegetation growing into lines
from vegetation inside and/or outside of the ROW;
R3.4.2. Category 2 — Fall-ins: Outages caused by vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages caused by vegetation falling into lines from
outside the ROW.
R4. The RRO shall report the outage information provided to it by Transmission Owner’s, as
required by Requirement 3, quarterly to NERC, as well as any actions taken by the RRO as a
result of any of the reported outages.
C.
Measures
M1. The Transmission Owner has a documented TVMP, as identified in Requirement 1.
M1.1. The Transmission Owner has documentation that the Transmission Owner performed
the vegetation inspections as identified in Requirement 1.1.
M1.2. The Transmission Owner has documentation that describes the clearances identified in
Requirement 1.2.
M1.3. The Transmission Owner has documentation that the personnel directly involved in the
design and implementation of the Transmission Owner’s TVMP hold the qualifications
identified by the Transmission Owner as required in Requirement 1.3.
M1.4. The Transmission Owner has documentation that it has identified any areas not
meeting the Transmission Owner’s standard for vegetation management and any
mitigating measures the Transmission Owner has taken to address these deficiencies as
identified in Requirement 1.4.
Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
3 of 5
Standard FAC-003-1 — Transmission Vegetation Management Program
M1.5. The Transmission Owner has a documented process for the immediate communication
of imminent threats by vegetation as identified in Requirement 1.5.
M2. The Transmission Owner has documentation that the Transmission Owner implemented the
work plan identified in Requirement 2.
M3. The Transmission Owner has documentation that it has supplied quarterly outage reports to
the RRO, or the RRO’s designee, as identified in Requirement 3.
M4. The RRO has documentation that it provided quarterly outage reports to NERC as identified in
Requirement 4.
D.
Compliance
1.
2.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
RRO
NERC
1.2.
Compliance Monitoring Period and Reset
One calendar Year
1.3.
Data Retention
Five Years
1.4.
Additional Compliance Information
The Transmission Owner shall demonstrate compliance through self-certification
submitted to the compliance monitor (RRO) annually that it meets the requirements of
NERC Reliability Standard FAC-003-1. The compliance monitor shall conduct an onsite audit every five years or more frequently as deemed appropriate by the compliance
monitor to review documentation related to Reliability Standard FAC-003-1. Field
audits of ROW vegetation conditions may be conducted if determined to be necessary
by the compliance monitor.
Levels of Non-Compliance
2.1.
Level 1:
2.1.1.
The TVMP was incomplete in one of the requirements specified in any
subpart of Requirement 1, or;
2.1.2.
Documentation of the annual work plan, as specified in Requirement 2, was
incomplete when presented to the Compliance Monitor during an on-site
audit, or;
2.1.3.
The RRO provided an outage report to NERC that was incomplete and did not
contain the information required in Requirement 4.
2.2. Level 2:
2.2.1.
The TVMP was incomplete in two of the requirements specified in any
subpart of Requirement 1, or;
2.2.2.
The Transmission Owner was unable to certify during its annual selfcertification that it fully implemented its annual work plan, or documented
deviations from, as specified in Requirement 2.
2.2.3.
The Transmission Owner reported one Category 2 transmission vegetationrelated outage in a calendar year.
Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
4 of 5
Standard FAC-003-1 — Transmission Vegetation Management Program
2.3. Level 3:
2.4.
E.
2.3.1.
The Transmission Owner reported one Category 1 or multiple Category 2
transmission vegetation-related outages in a calendar year, or;
2.3.2.
The Transmission Owner did not maintain a set of clearances (Clearance 2),
as defined in Requirement 1.2.2, to prevent flashover between vegetation
and overhead ungrounded supply conductors, or;
2.3.3.
The TVMP was incomplete in three of the requirements specified in any
subpart of Requirement 1.
Level 4:
2.4.1.
The Transmission Owner reported more than one Category 1 transmission
vegetation-related outage in a calendar year, or;
2.4.2.
The TVMP was incomplete in four or more of the requirements specified in
any subpart of Requirement 1.
Regional Differences
None Identified.
Version History
Version
Date
Action
Change Tracking
Version 1
TBA
1. Added “Standard Development
Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date: April
7, 2006” to footer.
4. Added “Draft 3: November 17, 2005” to
footer.
Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
5 of 5
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Standard FAC-003-1
Definitions of Terms
Proposed Standard FAC-003-2 RBS Draft 4
Definitions of Terms Used in Standard
Right of Way
A corridor of land on which
electric lines may be located.
The Transmission Owner may
own the land in fee, own an
easement, or have certain
franchise, prescription, or
license rights to construct and
maintain lines.
Right-of-Way (ROW)
The corridor of land under a transmission line(s) needed to
operate the line(s). The width of the corridor is established
by engineering or construction standards as documented
in either construction documents, pre-2007 vegetation
maintenance records, or by the blowout standard in effect
when the line was built. The ROW width in no case exceeds
the Transmission Owner’s legal rights but may be less
based on the aforementioned criteria.
Observations
This definition is intended to more clearly
recognize the establishment of the Right
of Way thought documentation.
The current glossary definition of this NERC
term is modified to address the issues set forth
in Paragraph 734 of FERC Order 693.
Vegetation Inspection
The systematic examination of a
transmission corridor to
document vegetation conditions.
Vegetation Inspection
The systematic examination of vegetation conditions on a Rightof-Way and those vegetation conditions under the Transmission
Owner’s control that are likely to pose a hazard to the line(s)
prior to the next planned maintenance or inspection. This may
be combined with a general line inspection.
1
This definition is intended to explain the
reason for Vegetation Inspections, and to
make clear that entities may perform other
inspections at the same time as the
Vegetation Inspection.
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Standard FAC-003-1
Proposed Standard FAC-003-2 RBS Draft 4
Observations
The current glossary definition of this NERC term is
modified to allow both maintenance inspections and
vegetation inspections to be performed concurrently.
Current definition of Vegetation Inspection: The
systematic examination of a transmission corridor to
document vegetation conditions.
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to
prevent flash-over between conductors and vegetation, for
various altitudes and operating voltages.
3. Purpose: To improve the
reliability of the electric
transmission systems by
preventing
outages from vegetation located
on transmission rights-of-way
(ROW) and minimizing outages
from vegetation located adjacent
to ROW, maintaining clearances
between transmission lines and
vegetation on and along
transmission ROW, and
3. Purpose: To maintain a reliable electric transmission system
by using a defense-in-depth strategy to manage vegetation
located on transmission rights of way (ROW) and minimize
encroachments from vegetation located adjacent to the ROW,
thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
This definition was added to ensure a
consistent understanding of the phrase.
Results based purpose, driven by Needs and
Goals.
NEED: To maintain a reliable electric
transmission system , preventing the risk of
those vegetation-related outages that could
lead to Cascading.
GOAL: To manage vegetation located on
transmission rights of way (ROW) and
minimize encroachments from vegetation
located adjacent to the ROW
2
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Standard FAC-003-1
reporting vegetation related
outages of the transmission
systems to the respective
Regional Reliability
Organizations (RRO) and the
North American Electric
Reliability Council (NERC).
4. Applicability:
4.1. Transmission Owner
4.2. Regional Reliability
Organization
4.3. This Standard shall
apply to all
transmission lines
operated at 200 kV
and above and to any
lower voltage lines
designated by the
RRO as critical to the
reliability of the
electric system in the
region.
Proposed Standard FAC-003-2 RBS Draft 4
4.1.
Functional Entities:
Observations
4.1.1 replaces 4.1.
4.1.1 Transmission Owners
4.2.
Facilities: Defined below (referred to as “applicable
lines”), including but not limited to those that cross lands owned
by federal , state, provincial, public, private, or tribal entities:
4.2.1. Each overhead transmission line operated at 200kV or
higher.
4.2.2. Each overhead transmission line operated below 200kV
identified as an element of an IROL under NERC Standard FAC014 by the Planning Coordinator.
4.2.3. Each overhead transmission line operated below 200 kV
identified as an element of a Major WECC Transfer Path in the
Bulk Electric System by WECC.
4.2.4. Each overhead transmission line identified above (4.2.1
through 4.2.3) located outside the fenced area of the
switchyard, station or substation and any portion of the span
of the transmission line that is crossing the substation fence.
3
4.2 has been removed, as the requirements
related to the RRO have been addressed in the
compliance section of the standard.
4.2 replaces 4.3. This is superior, as it raises
the bar on what lines need to be included
within the applicability of this standard.
To the extent the areas not covered in 4.2.4
need to be addressed, they should do so
under another project and possibly in a
separate standard, as the requirements for
vegetation management performed in these
areas by the GO and DP may be somewhat
different than those performed by a
Transmission Owner.
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Standard FAC-003-1
Proposed Standard FAC-003-2 RBS Draft 4
Rationale
The areas excluded in 4.2.4 were excluded based on
comments from industry for reasons summarized as
follows: 1) There is a very low risk from vegetation
in this area. Based on an informal survey, no TOs
reported such an event. 2) Substations, switchyards,
and stations have many inspection and
maintenance activities that are necessary for
reliability. Those existing process manage the
threat. As such, the formal steps in this standard are
not well suited for this environment. 3) NERC has a
project in place to address at a later date the
applicability of this standard to Generation Owners.
4) Specifically addressing the areas where the
standard does and does not apply makes the
standard clearer.
4
Observations
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
R1. The Transmission Owner shall prepare,
and keep current, a formal transmission
vegetation management program (TVMP).
The TVMP shall include the Transmission
Owner’s objectives, practices, approved
procedures, and work specifications1.
R3. Each Transmission Owner shall have
documented maintenance strategies or
procedures or processes or specifications it
uses to prevent the encroachment of
vegetation into the MVCD of its applicable
lines that include(s) the following:
R3 replaces R1.
Rationale
The documentation provides a basis for
evaluating the competency of the
Transmission Owner’s vegetation program.
There may be many acceptable
approaches to maintain clearances. Any
approach must demonstrate that the
Transmission Owner avoids vegetation-towire conflicts under all Ratings and all
Rated Electrical Operating Conditions. See
Figure 1 for an illustration of possible
conductor locations.
R1.1. The TVMP shall define a schedule for R6.
and the type (aerial, ground) of ROW
vegetation inspections. This schedule should
be flexible enough to adjust for changing
conditions. The inspection schedule shall be
based on the anticipated growth of vegetation
Each Transmission Owner shall perform a
Vegetation Inspection of 100% of its
applicable transmission lines (measured in
units of choice - circuit, pole line, line miles
or kilometers, etc.) at least once per
calendar year and with no more than 18
5
R6 replaces R1.1. R6 is superior because it
requires entities to take action (perform the
inspection), rather than just create a schedule.
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
and any other environmental or operational
factors that could impact the relationship of
vegetation to the Transmission Owner’s
transmission lines.
calendar months between inspections on
the same ROW.1
Rationale
Inspections are used by Transmission
Owners to assess the condition of the entire
ROW. The information from the assessment
can be used to determine risk, determine
future work and evaluate recentlycompleted work. This requirement sets a
minimum Vegetation Inspection frequency
of once per calendar year but with no more
than 18 months between inspections on the
same ROW. Based upon average growth
rates across North America and on common
utility practice, this minimum frequency is
reasonable. Transmission Owners should
consider local and environmental factors
that could warrant more frequent
inspections.
R1.2. The Transmission Owner, in the
TVMP, shall identify and document
clearances between vegetation and any
overhead, ungrounded supply conductors,
taking into consideration transmission line
voltage, the effects of ambient temperature
on conductor sag under maximum design
R3. Each Transmission Owner shall have
documented maintenance strategies
or procedures or processes or
specifications it uses to prevent the
encroachment of vegetation into the
MVCD of its applicable lines that
include(s)accounts for the following
1
Requirement R3 and Parts 3.1 and 3.2 replace
the concept of “Clearance 1,” as discussed in
R1.2 and R1.2.1.
When the Transmission Owner is prevented from performing a Vegetation Inspection within the timeframe in R6 due to a natural disaster, the TO is granted a time extension
that is equivalent to the duration of the time the TO was prevented from performing the Vegetation Inspection.
6
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
loading, and the effects of wind velocities on
conductor sway. Specifically, the
Transmission Owner shall establish
clearances to be achieved at the time of
vegetation management work identified
herein as Clearance 1, and shall also
establish and maintain a set of clearances
identified herein as Clearance 2 to prevent
flashover between vegetation and overhead
ungrounded supply conductors.
R1.2.1. Clearance 1 — The Transmission
Owner shall determine and document
appropriate clearance distances to be
achieved at the time of transmission
vegetation management work based upon
local conditions and the expected time frame
in which the Transmission Owner plans to
return for future vegetation management
work. Local conditions may include, but are
not
limited to: operating voltage, appropriate
vegetation management techniques,
fire risk, reasonably anticipated tree and
conductor movement, species types
and growth rates, species failure
characteristics, local climate and rainfall
patterns, line terrain and elevation, location
of the vegetation within the span,
and worker approach distance requirements.
Clearance 1 distances shall be
greater than those defined by Clearance 2
below.
3.1 Movement of applicable line
conductors under their Rating and all
Rated Electrical Operating Conditions;
3.2 Inter-relationships between
vegetation growth rates, vegetation
control methods, and inspection
frequency.
7
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
R1.2.2. Clearance 2 — The Transmission
Owner shall determine and document
specific radial clearances to be maintained
between vegetation and conductors
under all rated electrical operating
conditions. These minimum clearance
distances are necessary to prevent flashover
between vegetation and conductors and will
vary due to such factors as altitude and
operating voltage.
These Transmission Owner-specific
minimum clearance distances shall be no less
than those set forth in the Institute of
Electrical and Electronics Engineers (IEEE)
Standard 516-2003 (Guide for Maintenance
Methods on Energized Power Lines) and as
specified in its Section 4.2.2.3, Minimum Air
Insulation
Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system
transient overvoltage factors are not
known, clearances shall be derived from
Table 5, IEEE 516-2003, phase-to-ground
distances, with appropriate altitude
correction
factors applied.
R1.2.2.2 Where transmission system
R1 item 1 and R2 item 2 replace Clearance 2
with the Gallet Equations. These are
performance based, and superior to the existing
standard, as they require the entities to perform
an action (manage vegetation) rather than
creating a document.
R1. Each Transmission Owner shall manage
vegetation to prevent encroachments into
the MVCD of its applicable line(s) which are
either an element of an IROL, or an
element of a Major WECC Transfer Path;
operating within its Rating and all Rated
Electrical Operating Conditions of the types
shown below 2 [Violation Risk Factor: High]
[Time Horizon: Real-time]:
1. An encroachment into the MVCD as shown
in FAC-003-Table 2, observed in Real-time,
absent a Sustained Outage
R2. Each Transmission Owner shall manage
vegetation to prevent encroachments into
the MVCD of its applicable line(s) which are
not either an element of an IROL, or an
element of a Major WECC Transfer Path;
operating within its Rating and all Rated
Electrical Operating Conditions of the types
shown below2 [Violation Risk Factor:
2
This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to this reliability standard, including natural disasters such as
earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice
storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree, or installation, removal, or digging of vegetation. Nothing in this
footnote should be construed to limit the Transmission Owner’s right to exercise its full legal rights on the ROW.
3
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this
shall be considered the equivalent of a Real-time observation.
8
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Medium] [Time Horizon: Real-time]:
1. An encroachment into the MVCD as
shown in FAC-003-Table 2, observed in
Real-time, absent a Sustained Outage3,
transient overvoltage factors are known,
clearances shall be derived from Table 7,
IEEE 516-2003, phase-to-phase voltages,
with appropriate altitude correction factors
applied.
R1.3. All personnel directly involved in the
design and implementation of the TVMP shall
hold appropriate qualifications and training, as
defined by the Transmission Owner, to
perform their duties.
R1.3 is ambiguous (what is “appropriate”) and
unenforceable (what if the Transmission Owner
defines no qualifications or training), and was
not included in the new version of the standard.
R1.4. Each Transmission Owner shall develop
mitigation measures to achieve sufficient
clearances for the protection of the transmission
facilities when it identifies locations on the ROW
where the Transmission Owner is restricted from
attaining the clearances specified in Requirement
1.2.1.
R5 replaces R1.4. It is superior because it
requires the Transmission Owner to take action
(take corrective action), rather than to simply
develop mitigation measures.
R5.
When a Transmission Owner is constrained
from performing vegetation work on applicable
transmission lines operating within their Rating
and all Rated Electrical Operating Conditions,
and the constraint may lead to a vegetation
encroachment into the MVCD prior to the
implementation of the next annual work plan,
then the Transmission Owner shall take
corrective action to ensure continued
vegetation management to prevent
encroachments
9
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Rationale
Legal actions and other events may occur
which result in constraints that prevent
the Transmission Owner from performing
planned vegetation maintenance work.
In cases where the transmission line is put
at potential risk due to constraints, the
intent is for the Transmission Owner to
put interim measures in place, rather than
do nothing.
The corrective action process is not
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
R1.5. Each Transmission Owner shall establish
and document a process for the immediate
communication of vegetation conditions that
present an imminent threat of a transmission line
outage. This is so that action (temporary
reduction in line rating, switching line out of
service, etc.) may be taken until the threat is
relieved.
R4.
Each Transmission Owner, without
any intentional time delay, shall notify the
control center holding switching authority for
the associated applicable line when the
Transmission Owner has confirmed the
existence of a vegetation condition that is likely
to cause a Fault at any moment.
[VRF – Medium] [Time Horizon – Real-time]
10
R4 replaces R1.5. It is superior because it
requires the Transmission Owner to take action
(notify the control center) rather than document
a process.
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Rationale
This is to ensure expeditious communication
between the Transmission Owner and the
control center when a critical situation is
confirmed.
R2. The Transmission Owner shall create and
implement an annual plan for vegetation
management work to ensure the reliability
of the system. The plan shall describe the
methods used, such as manual clearing,
mechanical clearing, herbicide treatment,
or other actions. The plan should be
flexible enough to adjust to changing
conditions, taking into consideration
anticipated growth of vegetation and all
other environmental factors that may have
an impact on the reliability of the
transmission systems. Adjustments to the
plan shall be documented as they occur.
The plan should take into consideration the
time required to obtain permissions or
permits from landowners or regulatory
authorities. Each Transmission Owner shall
have systems and procedures for
documenting and tracking the planned
vegetation management work and ensuring
that the vegetation management work was
completed according to work
specifications.
R7. Each Transmission Owner shall complete 100% of
its annual vegetation work plan of applicable
lines to ensure no vegetation encroachments
occur within the MVCD. Modifications to the
work plan in response to changing conditions
or to findings from vegetation inspections may
be made (provided they do not allow
encroachment of vegetation into the MVCD)
and must be documented. The percent
completed calculation is based on the number
of units actually completed divided by the
number of units in the final amended plan
(measured in units of choice - circuit, pole line,
line miles or kilometers, etc.) Examples of
reasons for modification to annual plan may
include
•
Change in expected growth rate/
environmental factors
Circumstances that are beyond the
•
control of a Transmission Owner 3
•
Rescheduling work between growing
seasons
•
Crew or contractor availability/ Mutual
assistance agreements
3
R7 replaces R2. It is superior because it requires
entities to takes specific action (complete 100%
of its plan) rather than more generic language
(implement its plan). Entities that do not have a
plan would be unable to meet this requirement,
as they would have no evidence to demonstrate
compliance.
Circumstances that are beyond the control of a Transmission Owner include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides,
ice storms, floods, or major storms as defined either by the TO or an applicable regulatory body.
11
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
•
•
•
•
•
Identified unanticipated high priority
work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in
land use by the landowner
Emerging technologies
Rationale
This requirement sets the expectation that
the work identified in the annual work plan
will be completed as planned. It allows
modifications to the planned work for
changing conditions, taking into
consideration anticipated growth of
vegetation and all other environmental
factors, provided that those modifications
do not put the transmission system at risk of
a vegetation encroachment.
R3. The Transmission Owner shall report
quarterly to its RRO, or the RRO’s designee,
sustained transmission line outages determined
by the Transmission Owner to have been caused
by vegetation.
R3.1. Multiple sustained outages on an
individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the
actual number of outages within a 24hour period.
R3.2. The Transmission Owner is not required
to report to the RRO, or the RRO’s designee,
certain sustained transmission line outages
caused by vegetation: (1) Vegetation related
Periodic Data Submittal: The Transmission
Owner will submit a quarterly report to its
Regional Entity, or the Regional Entity’s designee,
identifying all Sustained Outages of applicable
lines operated within their Rating and all Rated
Electrical Operating Conditions as determined by
the Transmission Owner to have been caused by
vegetation, except as excluded in footnote 2, and
including as a minimum the following:
o
The name of the circuit(s), the date, time
and duration of the outage; the voltage of the
circuit; a description of the cause of the outage;
the category associated with the Sustained
12
Moved to compliance section of standard.
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
outages that result from vegetation falling into
lines from outside the ROW that result from
natural disasters shall not be considered
reportable (examples of disasters
that could create non-reportable outages include,
but are not limited to, earthquakes,
fires, tornados, hurricanes, landslides, wind
shear, major storms as defined either by
the Transmission Owner or an applicable
regulatory body, ice storms, and floods), and
(2) Vegetation-related outages due to human or
animal activity shall not be considered
reportable (examples of human or animal activity
that could cause a non-reportable
outage include, but are not limited to, logging,
animal severing tree, vehicle contact with tree,
arboricultural activities or horticultural or
agricultural activities, or removal or digging of
vegetation).
R3.3. The outage information provided by the
Transmission Owner to the RRO, or the
RRO’s designee, shall include at a minimum: the
name of the circuit(s) outaged, the date, time and
duration of the outage; a description of the cause
of the outage; other pertinent comments; and any
countermeasures taken by the Transmission
Owner.
R3.4. An outage shall be categorized as one of
the following:
R3.4.1. Category 1 — Grow-ins: Outages
caused by vegetation growing into lines
from vegetation inside and/or outside of the
ROW;
R3.4.2. Category 2 — Fall-ins: Outages
caused by vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages
caused by vegetation falling into lines from
Outage; other pertinent comments; and any
countermeasures taken by the Transmission
Owner.
A Sustained Outage is to be categorized as one of
the following:
o
Category 1A — Grow-ins: Sustained
Outages caused by vegetation growing into
applicable lines, that are identified as an element
of an IROL or Major WECC Transfer Path, by
vegetation inside and/or outside of the ROW;
o
Category 1B — Grow-ins: Sustained
Outages caused by vegetation growing into
applicable lines, but are not identified as an
element of an IROL or Major WECC Transfer Path,
by vegetation inside and/or outside of the ROW;
o
Category 2A — Fall-ins: Sustained Outages
caused by vegetation falling into applicable lines
that are identified as an element of an IROL or
Major WECC Transfer Path, from within the ROW;
o
Category 2B — Fall-ins: Sustained Outages
caused by vegetation falling into applicable lines,
but are not identified as an element of an IROL or
Major WECC Transfer Path, from within the ROW;
o
Category 3 — Fall-ins: Sustained Outages
caused by vegetation falling into applicable lines
from outside the ROW;
o
Category 4A — Blowing together: Sustained
Outages caused by vegetation and applicable
lines that are identified as an element of an IROL
or Major WECC Transfer Path, blowing together
from within the ROW.
o
Category 4B — Blowing together: Sustained
13
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
outside the ROW.
R4. The RRO shall report the outage
information provided to it by Transmission
Owner’s, as required by Requirement 3,
quarterly to NERC, as well as any actions
taken by the RRO as a result of any of the
reported outages.
Outages caused by vegetation and applicable
lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, blowing
together from within the ROW.
The Regional Entity will report the outage
information provided by Transmission Owners, as per
the above, quarterly to NERC, as well as any actions
taken by the Regional Entity as a result of any of the
reported Sustained Outages.
R1. Each Transmission Owner shall manage
vegetation to prevent encroachments into the
MVCD of its applicable line(s) which are either
an element of an IROL, or an element of a
Major WECC Transfer Path; operating within
their Rating and all Rated Electrical Operating
Conditions of the types shown below2:
1.
An encroachment into the MVCD as shown in
FAC-003-Table 2, observed in Real-time, absent
a Sustained Outage3 ,
2.
An encroachment due to a fall-in from inside
the ROW that caused a vegetation-related
Sustained Outage4 ,
3.
An encroachment due to the blowing together
of applicable lines and vegetation located
inside the ROW that caused a vegetationrelated Sustained Outage4,
4.
An encroachment due to vegetation growth
into the MVCD that caused a vegetation-related
Sustained Outage4.
14
New requirement.
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Rationale
Lines with the highest significance to reliability
are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage
vegetation which are listed in order of
increasing degrees of severity in non-compliant
performance as it relates to a failure of a
Transmission Owner's vegetation maintenance
program:
1. This management failure is found by routine
inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in
an otherwise sound program.
2. This management failure occurs when the
height and location of a side tree within the
ROW is not adequately addressed by the
program.
3. This management failure occurs when side
growth is not adequately addressed and may
be indicative of an unsound program.
4. This management failure is usually indicative
of a program that is not addressing the most
fundamental dynamic of vegetation
management, (i.e. a grow-in under the line). If
this type of failure is pervasive on multiple
li
it
id
h i f
C
d
R2.
Each Transmission Owner shall manage
15
New requirement.
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
1.
2.
3.
4.
vegetation to prevent encroachments into the
MVCD of its applicable line(s) which are not
either an element of an IROL, or an element of
a Major WECC Transfer Path; operating within
its Rating and all Rated Electrical Operating
Conditions of the types shown below2
[Violation Risk Factor: Medium] [Time Horizon:
Real-time]:
An encroachment into the MVCD, observed in
Real-time, absent a Sustained Outage3,
An encroachment due to a fall-in from inside
the ROW that caused a vegetation-related
Sustained Outage4,
An encroachment due to blowing together of
applicable lines and vegetation located inside
the ROW that caused a vegetation-related
Sustained Outage4,
An encroachment due to vegetation growth
into the MVCD that caused a vegetation-related
Sustained Outage4
16
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
Rationale
Lines with the highest significance to reliability
are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage
vegetation which are listed in order of
increasing degrees of severity in non-compliant
performance as it relates to a failure of a
Transmission Owner's vegetation maintenance
program:
1. This management failure is found by routine
inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in
an otherwise sound program.
2. This management failure occurs when the
height and location of a side tree within the
ROW is not adequately addressed by the
program.
3. This management failure occurs when side
growth is not adequately addressed and may
be indicative of an unsound program.
4. This management failure is usually indicative
of a program that is not addressing the most
fundamental dynamic of vegetation
management, (i.e. a grow-in under the line). If
this type of failure is pervasive on multiple
lines, it provides a mechanism for a Cascade.
17
FAC-003-1 Mapping to Proposed NERC Reliability Standard FAC-003-2 RBS Draft 4
August 22, 2011
2
This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to this reliability standard, including natural disasters such as
earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice
storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree, or installation, removal, or digging of vegetation. Nothing in this
footnote should be construed to limit the Transmission Owner’s right to exercise its full legal rights on the ROW.
3
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this
shall be considered the equivalent of a Real-time observation.
4
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage regardless of the actual number of outages within a 24-hour
period.
18
Project 2007-07 Vegetation Management
New and Modified Definitions
The following definitions are proposed as part of project 2007-07. They have been provided separately
for ease of reference.
Right-of-Way (ROW)
Current
A corridor of land on which electric lines may be located. The Transmission Owner may own the land in
fee, own an easement, or have certain franchise, prescription, or license rights to construct and
maintain lines.
Proposed
The corridor of land under a transmission line(s) needed to operate the line(s). The width of the
corridor is established by engineering or construction standards as documented in either construction
documents, pre-2007 vegetation maintenance records, or by the blowout standard in effect when the
line was built. The ROW width in no case exceeds the Transmission Owner’s legal rights but may be less
based on the aforementioned criteria.
Redline
A The corridor of land on which electric under a transmission line(s) needed to operate the line(s). The
width of the corridor is established by engineering or construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in
effect when the line was built.s may be located. The ROW width in no case exceeds the
s may be located. Transmission Owner’s legal rights but may be less based on the aforementioned
criteria. may own the land in fee, own an easement, or have certain franchise, prescription, or license
rights to construct and maintain lines.
Vegetation Inspection
Current
The systematic examination of a transmission corridor to document vegetation conditions.
Proposed
The systematic examination of vegetation conditions on a Right-of-Way and those vegetation
conditions under the Transmission Owner’s control that are likely to pose a hazard to the line(s) prior
to the next planned maintenance or inspection. This may be combined with a general line inspection.
Redline
The systematic examination of vegetation conditions on a Right-of-Way and those vegetation
conditions under the Transmission Owner’s control that are likely to pose a hazard to the line(s) prior
to the next planned maintenance or inspection. This may be combined with a general line inspection.a
transmission corridor to document vegetation conditions.
Minimum Vegetation Clearance Distance (MVCD)
Proposed (new)
The calculated minimum distance stated in feet (meters) to prevent flash-over between conductors
and vegetation, for various altitudes and operating voltages.
Project 2007-07 new and Modified Definitions
2
Project 2007-07 Vegetation Management
Consideration of Issues and Directives
Project 2007-07 Vegetation Management
Issue or Directive
Source
Consideration of Issue or Directive
FERC Order 693,
We will not direct NERC to submit a modification to the general
The standard applies to the following facilities, including
P706
limitation on applicability as proposed in the NOPR. However, we
but not limited to those that cross lands owned by
will require the ERO to address the proposed modification through
its Reliability Standards development process. As explained in the
NOPR, the Commission is concerned that the bright-line
applicability threshold of 200 kV will exclude a significant number
of transmission lines that could impact Bulk-Power System
reliability. Although the regional reliability organizations are given
discretion to designate lower voltage lines under the proposed
Reliability Standard, none have designated any operationally
significant lines even though there are lower voltage lines involving
IROL as suggested by Progress and SERC. We continue to be
concerned that this approach will not prospectively result in the
inclusion of all transmission lines that could impact Bulk-Power
System reliability.
federal, state, provincial, public, private, or tribal entities:
1 - Each overhead transmission line operated at 200kV or
higher.
2 - Overhead transmission line operated below 200kV
identified as an element of an IROL under NERC Standard
FAC-014 by the Planning Coordinator.
3 - Each overhead transmission line operated below 200
kV identified as an element of a Major WECC Transfer
Path in the Bulk Electric System by WECC.
4 - Each overhead transmission line identified above
located outside the fenced area of the switchyard, station
or substation and any portion of the span of the
transmission line that is crossing the substation fence.
In proposing to require the ERO to modify the Reliability Standard
to apply to Bulk-Power System transmission lines that have an
impact on reliability as determined by the ERO, we did not intend
to make this Reliability Standard applicable to fewer facilities than
it currently is with the 200 kV bright line applicability, but to
extend the applicability to lower voltage facilities that have an
impact on reliability. We support the suggestions by Progress
Energy, SERC and MISO to limit applicability to lower voltage lines
associated with IROL and these suggestions should be part of the
input to the Reliability Standards development process. Similarly,
the ERO should evaluate the suggestions proposed by LPPC, APPA
and Avista.
FERC Order 693,
P706
The standard applies to the following facilities, including
but not limited to those that cross lands owned by
federal, state, provincial, public, private, or tribal entities:
1 - Each overhead transmission line operated at 200kV or
higher.
2 - Overhead transmission line operated below 200kV
identified as an element of an IROL under NERC Standard
FAC-014 by the Planning Coordinator.
3 - Each overhead transmission line operated below 200
kV identified as an element of a Major WECC Transfer
Path in the Bulk Electric System by WECC.
4 - Each overhead transmission line identified above
located outside the fenced area of the switchyard, station
or substation and any portion of the span of the
transmission line that is crossing the substation fence.
FERC Order 693,
Accordingly, the Commission directs the ERO to develop a
Reliability Standard that defines the minimum clearance needed to P732
avoid sustained vegetation-related outages that would apply to
transmission lines crossing both federal land and non-federal land.
The standard includes Minimum Vegetation Clearance
Distances based on the Gallet equations, as specified in
FAC-003 Table 2.
The standard applies to facilities that meet specific
criteria, including (but not limited to) those that cross
lands owned by federal, state, provincial, public, private,
or tribal entities.
Project 2007-07 – Consideration of Issues and Directives
2
The Commission also directs the ERO to collect outage data for
transmission outages of lines that cross both federal and nonfederal lands, analyze it, and use the results of this analysis and
information to develop a Reliability Standard that would apply to
transmission lines crossing both federal and non-federal land.
Project 2007-07 – Consideration of Issues and Directives
FERC Order 693,
P732
The ERO is currently collecting and publishing all outage
data related to FAC-003. This data is received through
quarterly reporting and self reporting of violations.
Additionally, the TADS initiative is currently collecting
data on all automatic interruptions, including those
caused by vegetation, both on and off the right of way.
This action is equally applicable to federal and non-federal
lands. The SDT has requested the TADS project team to
modify its database to include fields to identify Federal
and non-Federal land transmission facilities such that this
data can be collected.
3
We recognize that many commenters would like a more precise
definition for the applicability of this Reliability Standard, and we
direct the ERO to develop an acceptable definition that covers
facilities that impact reliability but balances extending the
applicability of this standard against unreasonably increasing the
burden on transmission owners.
FERC Order 693,
P708
The standard applies to all Transmission Owners, for the
following facilities, including but not limited to those that
cross lands owned by federal, state, provincial, public,
private, or tribal entities:
1 - Each overhead transmission line operated at 200kV or
higher.
2 - Overhead transmission line operated below 200kV
identified as an element of an IROL under NERC Standard
FAC-014 by the Planning Coordinator.
3 - Each overhead transmission line operated below 200
kV identified as an element of a Major WECC Transfer
Path in the Bulk Electric System by WECC.
4 - Each overhead transmission line identified above
located outside the fenced area of the switchyard, station
or substation and any portion of the span of the
transmission line that is crossing the substation fence.
Project 2007-07 – Consideration of Issues and Directives
4
FirstEnergy and Xcel suggest that if the applicability of this
Reliability Standard is expanded, the Commission should allow
flexibility in complying with this Reliability Standard for lowervoltage facilities, or allow lower-voltage facilities one year before
the Reliability Standard is implemented. The ERO should consider
these comments when determining when it would request that
the modification of this Reliability Standard to go into effect.
FERC Order 693,
P709
The Implementation Plan requests that the standard
become effective as follows:
“The first calendar day of the first calendar quarter one
year after the date of the order approving the standard
from applicable regulatory authorities where such explicit
approval is required. Where no regulatory approval is
required, the standard becomes effective on the first
calendar day of the first calendar quarter one year after
Board of Trustees adoption.”
Additionally, the Implementation Plan proposes four
transition cases to address specific situations.
The Commission continues to be concerned with leaving complete
discretion to the transmission owners in determining inspection
cycles, which limits the effectiveness of the Reliability Standard.
Accordingly, the Commission directs the ERO to develop
compliance audit procedures, using relevant industry experts,
which would identify appropriate inspection cycles based on local
factors. These inspection cycles are to be used in compliance
auditing of FAC-003-1 by the ERO or Regional Entity to ensure such
inspection cycles and vegetation management requirements are
properly met by the responsible entities.
Project 2007-07 – Consideration of Issues and Directives
FERC Order 693,
P721
The VM SDT has tightened the Inspection Cycle
requirement. Minimum inspection frequency of once per
calendar year is now required.
5
FirstEnergy suggests that rights-of-way be defined to encompass
FERC Order 693,
the required clearance areas instead of the corresponding legal
P734
rights, and that the standards should not require clearing the
entire right-of-way when the required clearance for an existing line
does not take up the entire right-of-way. The Commission believes
this suggestion is reasonable and should be addressed by the ERO.
Accordingly, the Commission directs the ERO to address this
suggestion in the Reliability Standards development process.
It was pointed out that an entity did not need to be registered as a
TO for FAC-003-1 to apply to them, only that they have
transmission lines operated at 200 kV and above. This could
include radial lines as well as generation leads at the 200kV and
above level. This could mean functions other than TO would
require FAC-003-1 to be in the audit scope. How are you looking at
the applicability of FAC-003-1 as it applies to DPs, LSEs, GOs etc.
This could be applicable to many entities registered in multiple
regions.
TO's shall demonstrate compliance through self certification.
Compliance monitoring shall conduct an on-site audit every five
years or more frequently as deemed appropriate. Does this override the six year audit cycle for TO's?
Project 2007-07 – Consideration of Issues and Directives
The VMSDT developed a new definition of Active
Transmission Line ROW for inclusion in NERC Glossary.
This definition includes the statement “The ROW width in
no case exceeds the Transmission Owner’s legal rights but
may be less based on the aforementioned criteria.”
The Standard does not require the clearing the entire
legal easement for a particular parcel of land to ensure
reliability. Rather, the Standard requires vegetation
maintenance to adequately prevent outages from
vegetation on the right of way but also requires the TO to
prevent encroachment within the MVCD.
NERC Audit
Observation
Team
This is currently addressed through entity registration and
is also being addressed through Project 2010-07
Generator Requirements at the Transmission Interface
NERC Audit
Observation
Team
The standard has been updated with the most current
compliance information, eliminating this potential
concern.
6
With regards to the vegetation management standard, what type
of event would trigger a compliance investigation?
NERC Audit
Observation
Team
This question is outside the scope of the drafting team’s
work.
Format inconsistencies
Version 0 Team
The proposed standard has been formatted consistently.
RA vs. RRO
Version 0 Team
The proposed standard no longer refers to RAs or RROs.
Additional, the Planning Coordinator has replaced the
Region in a number of areas in which discretion might be
required (e.g., identifying the criticality of an element).
Too weak on compliance
Version 0 Team
The Compliance section of the proposed standard now
includes Time Horizons, Violation Severity Levels, and
Violation Risk Factors to support a stronger position
regarding compliance.
Project 2007-07 – Consideration of Issues and Directives
7
Violation Risk Factor and Violation Severity
Level Assignments
Project 2007-07 Vegetation Management
This document provides the drafting team’s justification for assignment of violation risk factors (VRFs)
and violation severity levels (VSLs) for each requirement in FAC-003-2 Vegetation Management.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support
the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the ERO Sanction Guidelines.
Justification for Assignment of Violation Risk Factors
The SDT applied the following NERC criteria when developing these VRFs:
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures; or, a requirement
in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures, or could hinder
restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if
violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system
instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
Violation Risk Factor & Violation Severity Level Assignments
1
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor and control the bulk electric system; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would
not, under the emergency, abnormal, or restorative conditions anticipated by the preparations,
be expected to adversely affect the electrical state or capability of the bulk electric system, or
the ability to effectively monitor, control, or restore the bulk electric system. A planning
requirement that is administrative in nature.
The SDT also considered consistency with the FERC Violation Risk Factor Guidelines for setting VRFs: 1
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of
Reliability Standards in these identified areas appropriately reflect their historical critical impact
on the reliability of the Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the Bulk-Power System: 2
−
−
−
−
−
−
−
−
−
−
−
−
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk
Factor assignments and the main Requirement Violation Risk Factor assignment.
1
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145
(2007) (“VRF Rehearing Order”).
2
Id. at footnote 15.
Violation Risk Factor & Violation Severity Level Assignments
2
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to
Requirements that address similar reliability goals in different Reliability Standards would be
treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular
Violation Risk Factor level conforms to NERC’s definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk
reliability objective, the VRF assignment for such Requirements must not be watered down to
reflect the lower risk level associated with the less important objective of the Reliability
Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The
team did not address Guideline 1 directly because of an apparent conflict between Guidelines 1 and 4.
Whereas Guideline 1 identifies a list of topics that encompass nearly all topics within NERC’s Reliability
Standards and implies that these requirements should be assigned a “High” VRF, Guideline 4 directs
assignment of VRFs based on the impact of a specific requirement to the reliability of the system. The
SDT believes that Guideline 4 is reflective of the intent of VRFs in the first instance and therefore
concentrated its approach on the reliability impact of the requirements.
VRF Justification
VRF for FAC-003-2, Requirements R1:
The SDT assigned this requirement a VRF of High.
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The Requirement states
transmission owners must manage vegetation for lines that represent a significant risk of
cascading, instability, or separation. The VRF is only applied at the Requirement level and each
Requirement Part is treated equally.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. The requirement mandates
measurable performance with regard to vegetation management to ensure that the risk of
cascading, separation, and instability is minimized. Other requirements with similar performance
based outcomes that could lead to cascading, instability, or separation carry a High VRF.
Violation Risk Factor & Violation Severity Level Assignments
3
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. IROLs and Major WECC
Transfer Paths by definition have an increased potential for leading to cascading, separation, or
instability. Therefore this requirement was assigned a High VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One Objective. The
requirement contains only one objective (to manage vegetation of lines that carry increased risk of
instability, cascading, or separation) and only one VRF was assigned.
VRF for FAC-003-2, Requirements R2:
The SDT assigned this requirement a VRF of Medium.
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The Requirement states
transmission owners must manage vegetation for lines that do not represent a significant risk of
cascading, instability, or separation. The VRF is only applied at the Requirement level and each
Requirement Part is treated equally.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. The requirement mandates
measurable performance with regard to vegetation management to ensure that the risk of
equipment damage is minimized. Other requirements similar performance based outcomes that
could lead to equipment damage carry a Medium VRF.
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Lines that are not IROLs and
Major WECC Transfer Paths by definition have less potential for leading to cascading, separation, or
instability. Therefore this requirement was assigned a Medium VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One Objective. The
requirement contains only one objective (to manage vegetation of lines that carry minimal risk
instability, cascading, or separation) and only one VRF was assigned.
VRF for FAC-003-2, Requirements R3:
The SDT assigned this requirement a VRF of Lower.
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The Requirement mandates the
Transmission Owner to have documented strategies, procedures, processes, or specifications. The
VRF is only applied at the Requirement level and each Requirement Part is treated equally.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. This requirement calls for an entity
to have documented strategies, procedures, processes, or specifications. This requirement is
administrative in nature, and is consistent with other standards requiring documentation.
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Failure to have a document is
not likely to directly affect the electrical state or the capability of the bulk electric system, or the
Violation Risk Factor & Violation Severity Level Assignments
4
ability to effectively monitor and control the bulk electric system. Development of the documents
is a requirement that is administrative in nature and is in a planning time frame that, if violated,
would not, under emergency, abnormal, or restorative conditions anticipated by the preparations,
be expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system.. Therefore this
requirement was assigned a Lower VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One Objective. R2
contains only one objective which is to have documents(s). Since the requirement is to have a
documents, only one VRF was assigned.
VRF for FAC-003-2, Requirements R4:
The SDT assigned this requirement a VRF of Medium.
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The Requirement specifies that
transmission owners must report vegetation conditions that are likely to cause a Fault to the
control center holding switching authority for the associated line. The VRFs are only applied at the
Requirement level and there are no Requirement Parts for separate consideration.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. The requirement mandates
notifications that could hinder the ability to effectively monitor and control the bulk electric
system. Other requirements that address with similar outcomes are also assigned Medium VRFs.
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Failure to report vegetation
conditions may affect the ability to effectively monitor and control the bulk electric system
Therefore this requirement was assigned a Medium VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One Objective. The
requirement contains only one objective (to report) , and only one VRF was assigned.
VRF for FAC-003-2, Requirements R5:
The SDT assigned this requirement a VRF of Medium.
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The Requirement mandates that a
Transmission Owner, when constrained from performing vegetation work that may lead to a
vegetation encroachment into the MVCD prior to the implementation of the next annual work plan,
must take corrective action to ensure continued vegetation management to prevent
encroachments. The VRF is only applied at the Requirement level and there are no Requirement
Parts for separate consideration.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. The requirement mandates
corrective action that, if not taken, could directly affect the electrical state or the capability of the
bulk electric system. Other requirements with similar outcomes are also assigned Medium VRFs.
Violation Risk Factor & Violation Severity Level Assignments
5
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Failure to take corrective action
could directly affect the electrical state or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system. Therefore this requirement was assigned a
Medium VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One Objective. The
requirement contains only one objective (to take corrective action), and only one VRF was
assigned.
VRF for FAC-003-2, Requirements R6:
The SDT assigned this requirement a VRF of Medium.
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The Requirement specifies that the
transmission owner must perform a Vegetation Inspection of 100% of its lines at least once per
calendar year. The VRFs are only applied at the Requirement level and there are no Requirement
Parts for separate consideration.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. The requirement mandates
inspections that, if not performed, could affect the ability to effectively monitor and control the
bulk electric system. Other requirements with similar outcomes are also assigned Medium VRFs.
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Failure to perform an inspection
could affect the ability to effectively monitor and control the bulk electric system. Therefore this
requirement was assigned a lower VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One Objective. The
requirement contains only one objective (to perform a Vegetation inspection), and only one VRF
was assigned.
VRF for FAC-003-2, Requirements R7:
The SDT assigned this requirement a VRF of Medium.
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The Requirement specifies that the
Transmission Owner must complete 100% of its annual vegetation work plan. The VRFs are only
applied at the Requirement level and there are no Requirement Parts for separate consideration.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. The requirement mandates
completion of work that, if not completed, could affect the electrical state or the capability of the
bulk electric system. Other requirements with similar outcomes are also assigned Medium VRFs.
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Failure to complete the annual
vegetation work plan could affect the electrical state or the capability of the bulk electric system.
Therefore this requirement was assigned a lower VRF.
Violation Risk Factor & Violation Severity Level Assignments
6
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One Objective. The
Requirement contains only one objective (to complete 100% of the annual vegetation work plan),
and only one VRF was assigned.
Justification for Assignment of Violation Severity Levels
In developing the VSLs, the SDT anticipated the evidence that would be reviewed during an audit, and
developed its VSLs based on the noncompliance an auditor may find during a typical audit. The SDT
based its assignment of VSLs on the following NERC criteria:
Lower
Missing a minor
element (or a small
percentage) of the
required
performance
The performance or
product measured
has significant value
as it almost meets the
full intent of the
requirement.
Moderate
Missing at least one
significant element
(or a moderate
percentage) of the
required
performance.
The performance or
product measured
still has significant
value in meeting the
intent of the
requirement.
High
Severe
Missing more than
one significant
element (or is missing
a high percentage) of
the required
performance or is
missing a single vital
component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant
elements (or a
significant
percentage) of the
required
performance.
The performance
measured does not
meet the intent of
the requirement or
the product delivered
cannot be used in
meeting the intent of
the requirement.
FERC’s VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for
each requirement meet the FERC Guidelines for assessing VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended Consequence of
Lowering the Current Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may
encourage a lower level of compliance than was required when levels of non-compliance were
used.
Violation Risk Factor & Violation Severity Level Assignments
7
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the
Determination of Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant
performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the Corresponding
Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A
Cumulative Number of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a
requirement is a separate violation. Section 4 of the Sanction Guidelines states that assessing
penalties on a per violation per day basis is the “default” for penalty calculations.
Violation Risk Factor & Violation Severity Level Assignments
8
VSLs for FAC-003-2 Requirement R1:
Compliance with
NERC’s VSL
Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should
Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
The proposed VSL uses
the same terminology as
used in the associated
requirement, and is,
therefore, consistent with
the requirement.
The VSL is based on
a single violation and
not cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R1
Meets NERC’s
VSL guidelines.
There is an
incremental
aspect to the
violation and the
VSLs follow the
guidelines for
incremental
violations..
This is a new
requirement, and
accordingly cannot
lower the current level
of compliance.
The proposed VSL does not use
any ambiguous terminology,
thereby supporting uniformity
and consistency in the
determination of similar
penalties for similar violations.
Violation Risk Factor & Violation Severity Level Assignments
9
VSLs for FAC-003-2 Requirement R2:
Compliance with
NERC’s VSL
Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should
Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based
on A Single
Violation, Not on A
Cumulative
Number of
Violations
The proposed VSL uses
the same terminology as
used in the associated
requirement, and is,
therefore, consistent with
the requirement.
The VSL is based
on a single
violation and not
cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R2.
Meets NERC’s
VSL guidelines.
There is an
incremental
aspect to the
violation and the
VSLs follow the
guidelines for
incremental
violations.
This is a new
requirement, and
accordingly cannot
lower the current level
of compliance.
The proposed VSL does not use
any ambiguous terminology,
thereby supporting uniformity
and consistency in the
determination of similar
penalties for similar violations.
Violation Risk Factor & Violation Severity Level Assignments
10
VSLs for FAC-003-3 Requirement R3
Compliance with
NERC’s Revised
VSL Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should
Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based
on A Single
Violation, Not on A
Cumulative
Number of
Violations
The proposed VSLs use
the same terminology as
used in the associated
requirement, and are,
therefore, consistent with
the requirement.
The VSLs are
based on a single
violation and not
cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R3.
Meets NERC’s
VSL guidelines.
There is an
incremental
aspect to the
violation and the
VSLs follow the
guidelines for
incremental
violations.
The previous standard
graded the VSLs based
on the completeness of
the TVMP. The new
VSL is structured
similarly, but has
omitted the “Low”
level, effectively raising
the minimum level of
compliance.
The proposed VSLs do not use
any ambiguous terminology,
thereby supporting uniformity and
consistency in the determination
of similar penalties for similar
violations.
Violation Risk Factor & Violation Severity Level Assignments
11
VSLs for FAC-003-3 Requirement R4:
Compliance with
NERC’s Revised
VSL Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should
Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based
on A Single
Violation, Not on A
Cumulative
Number of
Violations
The proposed VSLs use
the same terminology as
used in the associated
requirement, and are,
therefore, consistent with
the requirement.
The VSLs are
based on a single
violation and not
cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R4.
Meets NERC’s
VSL guidelines.
There is an
incremental
aspect to the
violation and the
VSLs follow the
guidelines for
incremental
violations.
The previous standard
does not require actual
communication, while
the new standard does.
Accordingly, this
should be treated as a
new requirement, and
therefore cannot lower
the current level of
compliance.
The proposed VSLs do not use
any ambiguous terminology,
thereby supporting uniformity and
consistency in the determination
of similar penalties for similar
violations.
Violation Risk Factor & Violation Severity Level Assignments
12
VSLs for FAC-003-3 Requirement R5:
Compliance with
NERC’s Revised
VSL Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should
Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based
on A Single
Violation, Not on A
Cumulative
Number of
Violations
The proposed VSLs use
the same terminology as
used in the associated
requirement, and are,
therefore, consistent with
the requirement.
The VSLs are
based on a single
violation and not
cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R5.
Meets NERC’s
VSL guidelines Severe: The
performance or
product measured
does not
substantively
meet the intent of
the requirement.
The only VSL is
Severe, and therefore,
the VSL cannot result in
a lower level of
compliance.
The proposed VSLs do not use
any ambiguous terminology,
thereby supporting uniformity and
consistency in the determination
of similar penalties for similar
violations.
Violation Risk Factor & Violation Severity Level Assignments
13
VSLs for FAC-003-3 Requirement R6:
Compliance with
NERC’s Revised
VSL Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should
Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based
on A Single
Violation, Not on A
Cumulative
Number of
Violations
The proposed VSLs use
the same terminology as
used in the associated
requirement, and are,
therefore, consistent with
the requirement.
The VSLs are
based on a single
violation and not
cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R6.
Meets NERC’s
VSL guidelines.
There is an
incremental
aspect to the
violation and the
VSLs follow the
guidelines for
incremental
violations.
The previous standard
does not require actual
inspections, while the
new standard does.
Accordingly, this
should be treated as a
new requirement, and
therefore cannot lower
the current level of
compliance.
The proposed VSLs do not use
any ambiguous terminology,
thereby supporting uniformity and
consistency in the determination
of similar penalties for similar
violations.
Violation Risk Factor & Violation Severity Level Assignments
14
VSLs for FAC-003-3 Requirement R7:
Compliance with
NERC’s Revised
VSL Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should
Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based
on A Single
Violation, Not on A
Cumulative
Number of
Violations
The proposed VSLs use
the same terminology as
used in the associated
requirement, and are,
therefore, consistent with
the requirement.
The VSLs are
based on a single
violation and not
cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R7.
Meets NERC’s
VSL guidelines.
There is an
incremental
aspect to the
violation and the
VSLs follow the
guidelines for
incremental
violations.
The VSLs in the
previous standard were
focused on
completeness of the
document, with the
“Severe” VSL only
reserved for entities that
did not have or
implement their plan.
The proposed VSLs are
graded based on the
amount of the plan
completed, giving a
clear indication that
partial completion is
still a violation,
establishing a level of
compliance in excess of
what was established
previously.
The proposed VSLs do not use
any ambiguous terminology,
thereby supporting uniformity and
consistency in the determination
of similar penalties for similar
violations.
Violation Risk Factor & Violation Severity Level Assignments
15
Technical, Policy and Regulatory Issues
Addressed by FAC-003 SDT
Q1: FERC generally requires that revised standards provide an adequate level of reliability in a
manner that is at least as effective and efficient as the previously balloted and approved
version of the standard. How does draft Standard FAC-003-2 meet this objective? Please
provide specific explanation of how the portfolio of proposed requirements provides a defensein-depth strategy for ensuring bulk power system reliability that is equally efficient and
effective to or superior to the current Standard, FAC-003-1 — Transmission Vegetation
Management Program. A specific explanation of how each requirement, when combined with
the other requirements of the draft standard, contributes to a defense-in-depth strategy will be
helpful.
A1: This Standard is more effective and efficient in ensuring an adequate level of reliability than
FAC-003-1 because it has the following attributes.
•
•
•
•
•
•
•
It removes the “fill-in-the-blank” ambiguity previously contained in FAC-003-1.
It separates performance requirements (R1, R2, R4, R5, R6, and part of R7) from
documentation requirements (R3 and the remainder of R7), and minimizes the burden
of those documentation requirements.
It has explicit and therefore clearer expectations to manage vegetation to: 1) prevent
observable vegetation encroachments inside the Minimum Vegetation Clearance
Distance (MVCD) and 2) prevent a confirmed Fault even in the absence of a Sustained
Outage (R1, R2).
It places more emphasis on those lines that pose the greatest risk to the reliability of the
interconnected transmission system. This is accomplished by converting the previous
FAC-00301 R1 into the new R1 and R2 and assigning the high VRF to the more important
lines in R1.
It requires the management of vegetation to prevent encroachments by specific types,
which are indicative of the quality of that management. Those quality-related
encroachment types also allow more specificity for determining the severity level of a
violation.
It establishes a clear, industry proven method for flash-over distance (clearance) that is
not subject to external standards established for other purposes (through use of the
Gallet Equations to establish the MCVD).
It has an unambiguous expectation for Vegetation Inspection intervals.
Technical, Policy and Regulatory Issues Addressed by FAC-003 SDT
1
•
•
•
•
It separates inspections and communications of imminent threats into individual and
clearer requirements that can be appropriately weighted by VRFs and VSLs (both of
these items were previously addressed in sub-requirements of FAC-003-1 R1).
It correctly moves reporting obligations from the requirements section (FAC-003-1 R3)
to the Additional Compliance Information Section.
It has additional supporting text in the Background, Rationale, and Guidelines and
Technical Basis sections to aid the industry in using the Standard and understanding
conductor dynamics and the interrelationship of vegetation growth, inspection
frequencies, and vegetation control methods.
It requires vegetation be managed with equal rigor over all lands regardless of the
ownership of those lands.
This standard utilizes three types of requirements to provide layers of protection to prevent
vegetation related outages that could lead to Cascading:
a) Performance-based defines a particular reliability objective or outcome to be
achieved. In its simplest form, a results-based requirement has four components: who,
under what conditions (if any), shall perform what action, to achieve what particular bulk
power system performance result or outcome?
b) Risk-based preventive requirements to reduce the risks of failure to acceptable
tolerance levels. A risk-based reliability requirement should be framed as: who, under what
conditions (if any), shall perform what action, to achieve what particular result or outcome
that reduces a stated risk to the reliability of the bulk power system?
c) Competency-based defines a minimum set of capabilities an entity needs to have to
demonstrate it is able to perform its designated reliability functions. A competency-based
reliability requirement should be framed as: who, under what conditions (if any), shall have
what capability, to achieve what particular result or outcome to perform an action to
achieve a result or outcome or to reduce a risk to the reliability of the bulk power system?
The defense-in-depth strategy for reliability standards development recognizes that each
requirement in a NERC reliability standard has a role in preventing system failures, and that
these roles are complementary and reinforcing. Reliability standards should not be viewed as a
body of unrelated requirements, but rather should be viewed as part of a portfolio of
requirements designed to achieve an overall defense-in-depth strategy and comport with the
quality objectives of a reliability standard.
This NERC Vegetation Management Standard (“standard”) uses a defense-in-depth approach to
improve the reliability of the electric Transmission System by:
•
Requiring that vegetation be managed to prevent vegetation encroachment inside the
flash-over clearance (R1 and R2);
Technical, Policy and Regulatory Issues Addressed by FAC-003 SDT
2
•
•
•
•
•
Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over conditions
including consideration of 1) conductor dynamics and 2) the interrelationships between
vegetation growth rates, control methods and the inspection frequency (R3);
Requiring timely notification to the appropriate control center of vegetation conditions
that could cause a flash-over at any moment (R4);
Requiring corrective actions to ensure that flash-over distances will not be violated due
to work constrains such as legal injunctions (R5);
Requiring inspections of vegetation conditions to be performed annually (R6); and
Requiring that the annual work needed to prevent flash-over is completed (R7).
For this standard, the requirements have been developed as follows:
•
Performance-based: Requirements 1 and 2
•
Competency-based: Requirement 3
•
Risk-based: Requirements 4, 5, 6 and 7
R3 serves as the first line of defense by ensuring that entities understand the problem they are
trying to manage and have fully developed strategies and plans to manage the problem. R1,
R2, and R7 serve as the second line of defense by requiring that entities carry out their plans
and manage vegetation. R6, which requires inspections, may be either a part of the first line of
defense (as input into the strategies and plans) or as a third line of defense (as a check of the
first and second lines of defense). R4 serves as the final line of defense, as it addresses cases in
which all the other lines of defense have failed.
Q2: The primary FERC directive in Order 693 is that the standard should specify minimum
clearances to avoid Sustained Outages under all applicable conditions. Where in the Revised
FAC-003-2 are references made to the ‘all applicable conditions’ issues? Is it understood that
the revised standard is intended to protect facilities during emergency conditions?
A2: There are numerous references in the Standard to ensure that facilities are protected for
all applicable conditions, including emergency conditions and conditions that would prevent the
entity from carrying out its annual work plan. Those references are provided below along with
a conclusion answer.
•
See R1 and R2 which include the phrase “...operating within its Rating and all Rated
Electrical Operating Conditions.”(Emphasis added)
•
Also see R3 which states:
Technical, Policy and Regulatory Issues Addressed by FAC-003 SDT
3
“Each Transmission Owner shall have documented maintenance strategies or
procedures or processes or specifications it uses to prevent the encroachment of
vegetation into the MVCD of its applicable lines that include(s) the following:
•
3.1
Accounts for the movement of applicable line conductors under their Rating and
all Rated Electrical Operating Conditions; ”
•
Also see R5 which states “When a Transmission Owner is constrained from performing
vegetation work on applicable lines operating within its Rating and all Rated Electrical
Operating Conditions, and the constraint may lead to a vegetation encroachment into
the MVCD prior to the implementation of the next annual work plan, then the
Transmission Owner shall take corrective action to ensure continued vegetation
management to prevent encroachments.”
•
Also see Periodic Data Submittal: The Transmission Owner will submit a quarterly
report to its Regional Entity, or the Regional Entity’s designee, identifying all Sustained
Outages of applicable lines operated within their Rating and all Rated Electrical
Operating Conditions
•
Also see Guideline and Technical Basis discussion for Requirements R1, R2 and R3,
which reinforces the concept that applicable line clearances are to be observed
throughout a line’s Rating and under all Rated electrical Operating Conditions.
The MVCD is the minimum clearance needed under all Rating and Rated Electrical Operating
Conditions. The Rated Electrical Operating Condition is defined in the glossary as “the
specified or reasonably anticipated conditions under which the electrical system or an
individual electrical circuit is intend/designed to operate.’ As such if there is an emergency
rating for a line, it would be covered by this standard.
Q3: Cost and cost effectiveness management have been raised as issues by stakeholders, state
regulators and some FERC commissioners. How will the Revised FAC-003-2 affect companies’
abilities to perform ROW maintenance in the most cost effective manner that does not
compromise reliability? Will the Revised FAC-003-2 facilitate or restrict companies from
ensuring cost effective ROW maintenance compared to FAC-003-1?
A3: This is a Results Based Standard. It addresses core rules to ensure an adequate level of
reliability and removes fill-in-the-blank requirements, as well as requirements for excessive
documentation. It allows efficiency in Vegetation Inspections by allowing them to be combined
with other line inspections, and it focuses more on “what” to do than “how” to do it.
Altogether, this allows the applicable entity the latitude to choose the most cost effective
methods to achieve compliance.
Technical, Policy and Regulatory Issues Addressed by FAC-003 SDT
4
Q4: FAC-003-1 identifies two clearances in R1.2.1 and R1.2.2: a clearance to be achieved when
performing vegetation management work (Clearance 1), and a minimum clearance to prevent
flashover (Clearance 2). Revised FAC-003-2 only identifies the minimum clearance to prevent
flashover (based on the Gallet equations), and does not identify a clearance to be achieved
when performing vegetation management work. How does the new standard ensure that
vegetation management work is performed that would provide a similar level of performance
as is currently required? Does the removal of Clearance 1 provide public interest benefits or
cost savings that should be considered by regulatory authorities and other stakeholders? i.e.,
there is a trade off from C1 & C2 to MVCD so how do we find comfort with this?
A4: The MVCD was chosen to replace Clearance 2 because it defines the distance that will
prevent a flash-over based on tested and proven principles. The FAC-003-1 Clearance 2 was
inappropriately based on worker safety considerations; FAC-003 is not a worker safety
standard. The Revised FAC-003-2 is now based on science, and not on another ANSI safety
standard which may change for reasons beyond the scope of this Standard.
Clearance 1 is an entity-specific fill-in-the blank requirement; as such, it was removed.
R3 requires that the entity’s documented maintenance strategies must account for the
movement of the conductors under their Rating(s) and all Rated Electrical Operating
Conditions. This is superior to the previous Clearance 1, as it leaves the necessary latitude for
the applicable entity to exercise its full easement rights to manage vegetation at the time the
work is performed (through methods such as use of herbicides or mechanical means, which
may result in the complete elimination of the vegetation). Such exercise of full easements rights
is often more efficient than pruning to a Clearance 1. In some cases property owners have
incorrectly interpreted Clearance 1 as a limitation on the applicable entities’ vegetation
management rights. Such incorrect interpretations can exacerbate the execution of best work
practices. If an applicable entity was not exercising its full rights due to external pressures or
due to the assumption that Clearance 1 was fully sufficient at the time of maintenance, that
entity is now (under FAC-003-2) relieved of that assumption, which will lead more directly to
the consideration of the most cost effective vegetation management method(s).
FAC-003-2 Requirement R5 states that when the applicable entity is constrained from
performing vegetation work that may lead to an encroachment into the MVCD prior to the
implementation of the next annual work plan that the entity shall take corrective action to
ensure continued vegetation management to prevent encroachments. This ensures that the
clearance obtained at the time work is performed will be fully adequate.
R6 requires an Annual Inspection which by its definition is “The systematic examination of
vegetation conditions on a Right-of-Way and those vegetation conditions under the
Transmission Owner’s control that are likely to pose a hazard to the line(s) prior to the next
planned maintenance or inspection”. Therefore this inspection will identify annually those
vegetation conditions that require attention regardless of how, when or to what clearance
distance the work was last performed. As such the required inspection provides the
Technical, Policy and Regulatory Issues Addressed by FAC-003 SDT
5
mechanism to allow the applicable entity to address any work that must be performed even in
advance of the next planned maintenance. Requirement R7 requires that the work plan be
executed to ensure that no vegetation encroachments occur within the MVCD.
Therefore, separately and collectively R3, R5, R6 and R7 are superior to the previous
requirement to establish a Clearance 1.
Q5: FAC-003-1 R1.3 required a transmission vegetation management program that mandated
personnel involved in the establishment of the TVMP hold appropriate qualifications and
training. How is this requirement addressed in the Revised FAC-003-2 or otherwise addressed
in other NERC reliability standards?
A5: The FAC-003-1 requirement for “appropriate” qualifications and training was ambiguous
and therefore removed. Applicable entities (as well as contractors that are retained by
applicable entities to perform vegetation management) are subject to numerous state and
federal environmental and worker safety regulations related to right of way work. Imposing
additional NERC requirements for “appropriate” qualifications and training on personnel and
contractors that may perform right of way maintenance is not helpful to reliability, and overly
burdensome. To the extent such personnel qualifications are needed, they would be better
addressed in the PER standards.
Q6: In one respect, revised FAC-003-2 appears to reduce applicability of the Standard. Section
4.2.4 indicates the Standard only applies to those transmission lines “outside the fenced area of
the switchyard, station or substation or any portion of the span the transmission line that is
crossing the substation fence.” These areas are currently within the scope of FAC-003-1, and
removing them from the Standard would appear to create a reliability gap. Is this correct? How
is this reliability gap addressed?
A6: Transmission line right of way maintenance programs do not normally extend inside those
fenced areas, and some of those areas require special access permissions for entry. There are
no reported or known vegetation related outages that have occurred in those areas. The
fenced areas under lines are typically either paved or maintained as grassy areas. The lines
within fenced areas are usually very short in length as compared to the miles of line outside the
fenced areas. The lands within the fenced area are typically held fee-simple, precluding the
need for special easements to maintain vegetation. That land is typically maintained such that
buses, switchgear, ground-mat grids, touch and step potentials mitigation, and switchyard
maintenance are of highest priority and therefore tree growth is not allowed. The maintenance
of those fenced areas is often performed by other specialized contractors that do not maintain
transmission line Right-of-Way. The ownership of the line often changes at the switchyard
fence. For all those reasons it is neither necessary nor practical to have this Standard apply
Technical, Policy and Regulatory Issues Addressed by FAC-003 SDT
6
inside those areas based on the premise that such a limitation would lower the bar or create a
reliability gap.
Q7: Revised FAC-003-2 has a minimum inspection cycle requirement. Order 693 did not ask for
a minimum inspection cycle. What is the technical need for this requirement? Does the
addition of this requirement provide reliability benefits that offset changes to other
requirements?
A7: In 693 the Commission noted its concern about minimizing outages and expressed support
for a realistic inspection cycle. The Commission further directed the ERO to develop compliance
audit procedures, using relevant industry experts, which would identify appropriate inspection
cycles based on local factors. However, the Commission also expressed its support for a realistic
inspection cycle and expressed concern when entities performed inspections on cycles of less
than every 3 years or even “as needed”. The Commission expressed concern with leaving
complete discretion to the transmission owners in determining inspection cycles which could
limit the effectiveness of the Reliability Standard.
The Team received industry feedback regarding their desire to perform vegetation surveys in
conjunction with other line inspections, which are typically annual surveys. The Team then
chose to request industry to comment on the adequacy of annual Vegetation Inspections with
the condition that the Vegetation Inspection could be performed in conjunction with other
inspections. Industry comments were highly supportive of this approach.
The annual inspection cycle requirement is viewed by the Team as realistic, clear, unambiguous,
easily performed, and not overly burdensome, since inspections can be performed aerially, on
the ground, and in conjunction with other inspections. Regional Entities can develop Regional
Standards or supplements to require increased frequencies in their regions if they determine
that their regional vegetation growth rates justify such an increase.
Development of compliance audit procedures that account for local factors was considered and
vetted by the Team. The Team concluded that the substantial variability in local factors would
place undue burden on the ERO to develop continent-wide compliance audit procedures that
would be clear and unambiguous. Furthermore the Team felt that waiting on the development
of audit procedures and the implementation of those audit procedures could place Applicable
Transmission Lines at greater risk than the proposed annual inspection cycle in FAC-003-2
which will provide a timelier “find-and-fix” solution to emerging problems with existing
corrective and preventative maintenance processes. The Team suggests that the Annual
Inspection requirement will ensure that applicable entities “find those conditions...likely to
pose a hazard to the line prior to the next planned maintenance or inspection.” This alternative
approach accomplishes the reliability objective targeted by the Commission of identifying
appropriate inspection cycles based on local factors.
Technical, Policy and Regulatory Issues Addressed by FAC-003 SDT
7
Q8: Revised FAC-003-2 requires in R7 that the Transmission Owner “complete 100% of its
annual vegetation work plan of applicable lines.” What is required to be included in the plan?
How does this differ from what is required under FAC-003-1 R1 and R2?
A8: The annual work plan will need to include the planned vegetation maintenance work
necessary to ensure no vegetation encroachments occur within the MVCD. Regarding how this
approach differs from FAC-003-1 Requirement 1 (which is about the documentation of practices
and is silent on annual work planning), FAC-003-2 addresses similar documentation in
Requirement R3. As far as how this approach differs from R2 in FAC-003-1, this FAC-003-2
Requirement 7 is not about details of creation of a plan with prescriptive descriptions of “how
to” contents; it focuses instead on the necessary end results: specifically, work execution
necessary to ensure no vegetation encroachments occur within the MVCD.
R7 continues to allow adjustments or modifications to the work plan and gives various
examples to aid users of the Standard.
Q9: It appears that the SDT based the VSLs for R1 and R2 on the reliability consequences of an
encroachment, rather than whether or not an encroachment occurred. NERC standards
address consequences as an aspect of risk through the Violation Risk Factor, rather than the
VSL. Why is the team choosing to attempt to address reliability consequences in both the VRF
and the VSL?
A9: The action verb in R1 and R2 is to “manage.” The Subject Matter Experts on the team, with
industry feedback, recognized that the types of encroachments provide a valuable method to
determine the effectiveness of a vegetation program’s ability to manage vegetation effectively.
The most egregious vegetation management failure, and the most predictable, is to allow
vegetation that is directly under the line to continue growing until it contacts the conductor. An
entity that is unable to meet this obligation either does not have a vegetation program of
significant value or doers but is not implementing it faithfully.
The next most obvious vegetation management failure mode would be vegetation that has
grown adjacent to the line sufficiently close such that the line and vegetation could be blown
together. In this case, the entity is likely implementing a relatively effective program, but was
unable to identify this particular risk.
Less obvious and less predictable vegetation management failures are caused by falling trees
that are tall enough to lodge into the line and cause a Sustained Outage. This is due to the
challenges in predicting the various causes for and the numerous ways that trees fail (decay,
erosion, defects, excavation, wind forces) and fall and the likely direction (up to 360 degrees
Technical, Policy and Regulatory Issues Addressed by FAC-003 SDT
8
available) that the tree will fall. An entity can have a very effective program, but fail to mitigate
a risk of such occurrence.
Along with the difficulties just stated, it is deemed an even lesser vegetation maintenance
failure to not find and remove every single tree before it has grown just enough to fall near the
line and cause a brief Fault when it falls; or growth that reaches within the MVCD, but has not
caused a fault. Again, an entity can have a very effective program, but fail to mitigate a risk of
such occurrence.
Accordingly, the Team believes that the type and result of encroachment is indicative of an
entity’s overall performance and ability to “manage” vegetation.
Q10: Revised FAC-003-2 under R1 assigns a high VRF to those lines that are part of an IROL
and/or are a WECC transfer path. Encroachment violations for all other lines are assigned a
Medium VRF under R2. In the previous version of the standard, all lines were subject to the
same requirements (i.e., the clearances were specified for all lines in R1.2, and clearances for all
lines were expected to be maintained under R2). Splitting these elements into two different
requirements, with two different VRFs, may create the perception that FAC-003-2 is “lowering
the bar” by either reducing performance requirements or reducing potential penalties. How
does the standard ensure that this “lowering” of the bar will not occur? Alternately, if this
“lowering” is intentional, why is this reduction in expected performance or penalties reasonable
and in the public interest?
A10: The reliability risk incurred by the outage of a transmission line within the interconnected
transmission network is higher for some lines than for others. NERC’s VRF definitions indicate
that a High Violation Risk Factor is only appropriate for:
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk
electric system at an unacceptable risk of instability, separation, or cascading failures;
or, a requirement in a planning time frame that, if violated, could, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of
failures, or could place the bulk electric system at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
In FERC’s May 18, 2007 Order on Violation Risk Factors, FERC identified Guideline 5, which
states that where a single requirement co-mingles a higher risk reliability objective and a lesser
risk reliability objective, the VRF assignment must not be “watered down” to reflect the lower
risk level associated with the less important objective. By not drawing a distinction between
those lines with the ability to cause instability, separation, and cascading and those that do not,
the previous standard co-mingled these objectives, and appropriately had a VRF of High
Technical, Policy and Regulatory Issues Addressed by FAC-003 SDT
9
assigned. However, the Team has chosen to eliminate that co-mingling, has split the
requirement, and has accordingly assigned the appropriate VRFs to the separate requirements.
From a practical perspective, FAC-003-2 continues to find applicable entities in violation for all
the types of encroachments that they were subject to in FAC-003-1. FAC-003-2 requires all of
the sub-200 kV IROL and WECC Major Transfer Path lines be included in the applicability, which
provide more specificity than what was required in the previous version of the standard. There
is now a clear inclusion of violations for those Faults confirmed-after-the-fact, as well as for
confirmed MVCD encroachments that are found and removed prior to a Fault. Given the VRF
definitions, FERC’s guidance, and the above additional considerations, the Team believes FAC003-2 continues to require an appropriate level of performance.
Technical, Policy and Regulatory Issues Addressed by FAC-003 SDT
10
Standards Announcement
Project 2007-07 Vegetation Management
Now Open: Recirculation Ballot October 4-13, 2011
Now available
Project 2007-07 – Vegetation Management
A recirculation ballot window for FAC-003-2 – Transmission Vegetation Management and its associated
implementation plan is open through 8 p.m. on Thursday, October 13, 2011.
Instructions
Members of the ballot pool associated with this project may log in and submit their votes.
In the recirculation ballot, votes are counted by exception. Only members of the ballot pool may cast a ballot;
all ballot pool members may change their prior votes. A ballot pool member who failed to cast a ballot during
the last ballot window may cast a ballot in the recirculation ballot window. If a ballot pool member does not
participate in the recirculation ballot, that member’s last vote cast in the successive ballot that ended on
February 28, 2011 will be carried over and used to determine if there are sufficient affirmative votes for this
standard to pass.
Background
FAC-003-1 is being revised to address several fill-in-the-blank requirements, directives from Order 693, and
issues raised by stakeholders. A successive ballot closed in February 2011 and achieved a quorum of 79.28%
and an approval of 79.34%. The drafting team has posted its consideration of comments from the successive
ballot and has been working to address a set of questions posed by Standards Committee chairman Allen
Mosher, aimed at documenting the technical justification for the proposed requirements and verifying that
the team has addressed the associated directives from Order 693
Documents for this project, including clean and redline to the last posted versions of the standard,
implementation plan, and technical reference and the drafting team’s responses to the technical, policy, and
regulatory questions posed by Chairman Mosher have been posted on the project webpage.
Next Steps
Voting results will be posted and announced after the ballot window closes. If the recirculation ballot achieves
a quorum and ballot pool approval, the standard will be presented to the NERC Board of Trustees for
adoption.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend
our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement
Project 2007-07 Transmission Vegetation Management
Recirculation Ballot Results
Now available
Ballot Results for FAC-003-2 Transmission Vegetation Management
A recirculation ballot on revisions to FAC-003-2 – Transmission Vegetation Management concluded on
Thursday, October 13, 2011. The standard was approved by the associated ballot pool.
Voting statistics for the standard are listed in the table below, and the Ballot Results Web page
provides a link to the detailed results.
Standard
Ballot Results
FAC-003-2 – Transmission
Vegetation Management
Quorum: 87.17%
Approval: 86.25 %
Next Steps
The standard will be presented to the NERC Board of Trustees for adoption.
Background
FAC-003-1 is being revised to address several fill-in-the-blank requirements, directives from Order 693,
and issues raised by stakeholders. A successive ballot closed in February 2011 and achieved a quorum
of 79.28% and an approval of 79.34%. The drafting team has posted its consideration of comments
from the successive ballot and has posted answers to a set of questions posed by Standards Committee
chairman Allen Mosher.
Documents for this project, including clean and redline to the last posted versions of the standard,
implementation plan, and technical reference and the drafting team’s responses to the technical,
policy, and regulatory questions posed by Chairman Mosher have been posted on the project webpage.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend
our thanks to all those who participate. For more information or assistance, please contact Monica Benson
at [email protected].
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
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Standards Announcement – Ballot Results 2007-07
2
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Ballot Results
Ballot Name: Project 2007-07 Vegetation Management_rc
Password
Ballot Period: 10/4/2011 - 10/13/2011
Ballot Type: recirculation
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Total # Votes: 265
Register
Total Ballot Pool: 304
Quorum: 87.17 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
86.25 %
Vote:
Ballot Results: The Standard has Passed
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Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
90
9
74
22
54
35
0
7
6
7
304
#
Votes
1
0.3
1
1
1
1
0
0.4
0.6
0.5
6.8
#
Votes
Fraction
68
3
51
14
34
23
0
4
6
4
207
Negative
Fraction
0.84
0.3
0.823
0.778
0.872
0.852
0
0.4
0.6
0.4
5.865
Abstain
No
# Votes Vote
13
0
11
4
5
4
0
0
0
1
38
0.16
0
0.177
0.222
0.128
0.148
0
0
0
0.1
0.935
2
3
7
3
3
0
0
2
0
0
20
7
3
5
1
12
8
0
1
0
2
39
Individual Ballot Pool Results
Segment
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1
1
1
1
1
1
1
Organization
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Baltimore Gas & Electric Company
Member
Rodney Phillips
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Scott J Kinney
Gregory S Miller
https://standards.nerc.net/BallotResults.aspx?BallotGUID=c933f5ba-b282-4b00-b169-83aa435fc710[10/14/2011 3:59:24 PM]
Ballot
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Comments
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NERC Standards
1
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1
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1
1
1
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1
1
1
1
1
1
1
1
1
1
BC Transmission Corporation
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
CenterPoint Energy
Central Maine Power Company
City of Vero Beach
City Utilities of Springfield, Missouri
Cleco Power LLC
Commonwealth Edison Co.
Consolidated Edison Co. of New York
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
E.ON U.S.
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Gainesville Regional Utilities
GDS Associates, Inc.
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lake Worth Utilities
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Long Island Power Authority
Manitoba Hydro
Metropolitan Water District of Southern
California
MidAmerican Energy Co.
National Grid
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Gordon Rawlings
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Paul Rocha
Brian Conroy
Randall McCamish
Jeff Knottek
Danny McDaniel
Daniel Brotzman
Christopher L de Graffenried
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Larry Monday
George S. Carruba
Ralph F Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Luther E. Fair
Claudiu Cadar
Harold Taylor
Gordon Pietsch
Ajay Garg
Bernard Pelletier
Ted Hobson
Michael Gammon
Stanley T Rzad
Walt J Gill
Larry E Watt
John W Delucca
Doug Bantam
Robert Ganley
Joe D Petaski
Ernest Hahn
Terry Harbour
Saurabh Saksena
Richard L. Koch
Arnold J. Schuff
Henry G. Masti
David Boguslawski
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Michael T. Quinn
Brad Chase
Lawrence R. Larson
Chifong Thomas
Mark Sampson
Ronald Schloendorn
John C. Collins
Frank F Afranji
Richard J Kafka
Larry D Avery
Brenda L Truhe
Sammy Roberts
Laurie Williams
Kenneth D. Brown
Chad Bowman
Tim Kelley
Robert Kondziolka
Terry L Blackwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=c933f5ba-b282-4b00-b169-83aa435fc710[10/14/2011 3:59:24 PM]
Affirmative
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Negative
Abstain
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Negative
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Negative
Negative
Negative
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Negative
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Negative
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Abstain
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NERC Standards
1
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3
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3
3
3
3
3
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3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
SCE&G
Seattle City Light
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
BC Transmission Corporation
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
Alabama Power Company
Allegheny Power
Ameren Services
American Electric Power
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Blue Ridge Power Agency
Bonneville Power Administration
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Leesburg
Cleco Utility Group
ComEd
Consolidated Edison Co. of New York
Constellation Energy
Consumers Energy
Consumers Power Inc.
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Power Corporation
Gainesville Regional Utilities
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
Manitoba Hydro
Henry Delk, Jr.
Pawel Krupa
Richard McLeon
Dana Cabbell
Horace Stephen Williamson
William Hutchison
James Jones
Gary W Cox
Noman Lee Williams
Larry Akens
Keith Carman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Faramarz Amjadi
Charles B Manning
Kim Warren
Jason L Marshall
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Richard J. Mandes
Bob Reeping
Mark Peters
Raj Rana
Steven Norris
James V. Petrella
Pat G. Harrington
Duane S Dahlquist
Rebecca Berdahl
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Phil Janik
Bryan Y Harper
Bruce Krawczyk
Peter T Yost
Carolyn Ingersoll
David A. Lapinski
Roman Gillen
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Kevin Querry
Joe McKinney
Lee Schuster
Kenneth Simmons
Anthony L Wilson
Scott S. Barfield-McGinnis
Sam Kokkinen
Gwen S Frazier
Michael D. Penstone
Charles Locke
Gregory D Woessner
Mace Hunter
Bruce Merrill
Kenneth Silver
Charles A. Freibert
Greg C. Parent
https://standards.nerc.net/BallotResults.aspx?BallotGUID=c933f5ba-b282-4b00-b169-83aa435fc710[10/14/2011 3:59:24 PM]
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Affirmative
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Abstain
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Abstain
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Negative
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Negative
Abstain
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NERC Standards
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3
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3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
MEAG Power
MidAmerican Energy Co.
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
OTP Wholesale Marketing
PacifiCorp
PECO Energy an Exelon Co.
Platte River Power Authority
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Public Utility District No. 2 of Grant County
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
South Carolina Electric & Gas Co.
Southern California Edison Co.
Springfield Utility Board
Tampa Electric Co.
Turlock Irrigation District
Umatilla Electric Cooperative
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
American Public Power Association
City of Clewiston
City of New Smyrna Beach Utilities
Commission
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Madison Gas and Electric Co.
Modesto Irrigation District
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Wisconsin Energy Corp.
AEP Service Corp.
Amerenue
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Chelan County Public Utility District #1
City of Grand Island
City of Tallahassee
City Water, Light & Power of Springfield
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
Steven Grego
Thomas C. Mielnik
Don Horsley
Steven M. Jackson
John S Bos
Marilyn Brown
Michael Schiavone
William SeDoris
David Anderson
David Burke
Ballard K Mutters
Bradley Tollerson
John Apperson
Vincent J. Catania
Terry L Baker
Robert Reuter
Jeffrey Mueller
Kenneth R. Johnson
Greg Lange
James Leigh-Kendall
Ken Dizes
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
Hubert C Young
David Schiada
Jeff Nelson
Ronald L Donahey
Casey Hashimoto
Steve Eldrige
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Allen Mosher
Kevin McCarthy
Tim Beyrle
David Frank Ronk
Rick Syring
Daniel Herring
Frank Gaffney
Thomas Richards
Guy Andrews
Bob C. Thomas
Joseph DePoorter
Spencer Tacke
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Anthony Jankowski
Brock Ondayko
Sam Dwyer
Edward F. Groce
Clement Ma
Francis J. Halpin
John Yale
Jeff Mead
Alan Gale
Karl E. Kohlrus
Wilket (Jack) Ng
James B Lewis
Bob Essex
https://standards.nerc.net/BallotResults.aspx?BallotGUID=c933f5ba-b282-4b00-b169-83aa435fc710[10/14/2011 3:59:24 PM]
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
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Negative
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Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
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Negative
Negative
Affirmative
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Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
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Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
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Affirmative
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Negative
Affirmative
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NERC Standards
5
5
5
5
5
5
5
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5
5
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5
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5
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5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Dominion Resources, Inc.
Duke Energy
East Kentucky Power Coop.
Entergy Corporation
Exelon Nuclear
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
Public Service Enterprise Group Incorporated
Reedy Creek Energy Services
Sacramento Municipal Utility District
Salt River Project
Seattle City Light
Seminole Electric Cooperative, Inc.
South California Edison Company
South Carolina Electric & Gas Co.
South Mississippi Electric Power Association
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers Northwestern
Division
U.S. Bureau of Reclamation
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Bonneville Power Administration
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Eugene Water & Electric Board
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
New York Power Authority
Northern Indiana Public Service Co.
OTP Wholesale Marketing
PacifiCorp
Mike Garton
Robert Smith
Stephen Ricker
Stanley M Jaskot
Michael Korchynsky
Kenneth Dresner
David Schumann
Cynthia E Sulzer
Donald Gilbert
Scott Heidtbrink
Mike Blough
Dennis Florom
Charlie Martin
S N Fernando
David Gordon
Christopher Schneider
Gerald Mannarino
Michael K Wilkerson
Mahmood Z. Safi
Stacie Hebert
Richard J. Padilla
Sandra L. Shaffer
Gary L Tingley
Tim Hattaway
Mark A Heimbach
Wayne Lewis
Dominick Grasso
Bernie Budnik
Bethany Hunter
Glen Reeves
Michael J. Haynes
Brenda K. Atkins
Ahmad Sanati
Richard Jones
Jerry W Johnson
Scott M Helyer
George T. Ballew
Barry Ingold
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
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View
Negative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
View
View
Affirmative
Negative
Affirmative
Affirmative
Karl Bryan
Martin Bauer
Leonard Rentmeester
Liam Noailles
Edward P. Cox
Brenda S. Anderson
Matthew D Cripps
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Daniel Mark Bedbury
Pulin Shah
Mark S Travaglianti
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Thomas Saitta
Paul Shipps
Eric Ruskamp
Daryn Barker
Daniel Prowse
Thomas Papadopoulos
Joseph O'Brien
Bruce Glorvigen
Gregory D Maxfield
https://standards.nerc.net/BallotResults.aspx?BallotGUID=c933f5ba-b282-4b00-b169-83aa435fc710[10/14/2011 3:59:24 PM]
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
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NERC Standards
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8
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10
10
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
RRI Energy
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
JDRJC Associates
Pacific Northwest Generating Cooperative
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Public Service Commission of South Carolina
Utah Public Service Commission
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Western Electricity Coordinating Council
John T Sturgeon
Peter Dolan
Hugh A. Owen
Trent Carlson
Mike Hummel
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Matt H Bullard
Marjorie S. Parsons
Affirmative
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Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
John Stonebarger
David F. Lemmons
Roger C Zaklukiewicz
James A Maenner
Jim Cyrulewski
Margaret Ryan
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Donald Nelson
Affirmative
Diane J Barney
Affirmative
Jerome Murray
Philip Riley
Ric Campbell
Dan R Schoenecker
Alan Adamson
Guy V. Zito
Jacquie Smith
Carter B. Edge
Stacy Dochoda
Louise McCarren
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=c933f5ba-b282-4b00-b169-83aa435fc710[10/14/2011 3:59:24 PM]
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Affirmative
Legal and Privacy : 609.452.8060 voice : 609.452.9550 fax : 116-390 Village Boulevard : Princeton, NJ 08540-5721
Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
Copyright © 2010 by the North American Electric Reliability Corporation. : All rights reserved.
View
Exhibit H
Standard Drafting Team Roster for NERC Standards Development Project 2007-07
Vegetation Management
VMSDT Bios
Ron Adams is General Manager, Right of Way Management at Duke Energy in Charlotte, NC.
His current responsibilities include operational management of both Transmission and
Distribution Rights of Way, which consist of over 100,000 miles of overhead T&D facilities. He
has held many positions in his 26 year career, such as Substation Engineer, Industrial Marketing
Specialist, Power Quality Engineer, Technical Services Manager, Manager of Design
Engineering, Manager Engineering, Transmission Construction Manager, Transmission
Operations Manager, and previously Director Vegetation Management Carolinas.
Mr. Adams is a Senior Member of IEEE, a former EPRI Innovator Award recipient for his Power
Quality work, and a former Chair of the Canadian Electricity Association Work Group for
Substation Life Cycle Management. He holds a Bachelor of Science degree in Electrical
Engineering from Clemson University, and is a registered professional engineer in the states of
North and South Carolina.
Tom Anderson is presently Lead Forester of Lincoln Electric System's Vegetation Management
Team. Tom has worked at Lincoln Electric System (LES) since 1974. He has been involved with
or supervised the installation and maintenance of LES's overhead and underground facilities at
all distribution and transmission line voltages, and coordinated and completed LES’s first TVMP
and annual work plans for compliance with FAC-003-1. Mr. Anderson has supervised Locating
and Troubleshooting Technicians and Thermography Technicians, and has also served as Trainer
of Apprentice Line Technicians, 1st Class Line Technicians, and T&D Dispatchers.
Mr. Anderson has served as President of the International Brotherhood of Electrical Workers
(IBEW) Local 1536 for 12 years. He has competed in the IBEW International Lineman Rodeo,
and as a part of the LES team, has been awarded First Place for Underground Splicing. He has
also been judge of the “Hurt Man Rescue” for several years in the American Public Power
Association Line Technician Rodeo.
Mr. Anderson has served on the Board of Advisors for the Northeast Community College in
Norfolk, Nebraska. During this period, Tom attempted to develop an Associate Degree program
for Line Clearance Arborists, recognizing that the industry needs better trained and qualified
personnel n this area.
Mr. Anderson has Bachelor of Arts degrees in Human Resources and in Industrial Management
from Doane College. He also has an Associate of Arts degree in Computer Programming from
Southeast Community College System, and is a NERC Certified Operator for LES transmission
system.
Paul S. Beaulieu is a Professional Engineer with Finley Engineering Company. He has been
involved in the electric utility industry for the past 28 years. Prior to joining Finley, he worked
with Kansas City Power & Light (Great Plains Energy), a Midwest investor owned utility.
Mr. Beaulieu’s has significant experience with design and construction of transmission,
substation, and distribution projects ranging from 12 kV to 345kV, to managing transmission,
(69kV and above) construction and maintenance resources over 47 counties across two states.
His broad range of design experience for 34kV through 345kV transmission system projects
includes: route selection, right of way descriptions, implementation and usage of transmission
line design software, NESC code compliance determination, transmission line strength and
loading profiles, structure and foundation design, bill of material and construction contracts and
specifications. Additionally, he has provided the mechanical/civil design for 34 kV through
345kV substations including plans for grading and drainage, roadways, manholes and duct
banks, foundations, apparatus layout, structure specifications, yard and interior lighting,
lightning protection, station grounding, fencing design, control house development including
foundation design, electrical layout, HVAC, plumbing, and house material specifications.
Mr. Beaulieu has also provided leadership to an efficiently run construction and maintenance
organization. He had oversight responsibility for C&M activities, GIS integration, and
Transmission Vegetation Management for 3,400 miles of transmission lines. Ultimately, he was
responsible for new transmission construction and maintenance projects including ongoing asset
management programs of the systems with an estimated plant value of $700 Million, assuring
proper Project Scope and Cost Development and Project Management and Closeout.
Mr. Beaulieu earned his Master of Science in Mechanical and Aerospace Engineering from the
University of Missouri Columbia (Emphasis Material Science, Fatigue and Fracture Mechanics)
and his Bachelor of Science in Mechanical Engineering from the University of Missouri Kansas
City. Additionally he earned an Associates of Science in Drafting Technology from Longview
Community College.
Stephen Cieslewicz is President and Chief Consultant at CN Utility Consulting Inc. With more
than 30 years of industry experience, Mr. Cieslewicz has established himself as a leading expert
in utility vegetation management (UVM). This includes designing and running one of the
nation’s largest UVM programs (PG&E), managing large scale UVM related research projects,
performing the industry’s largest UVM benchmarking, and researching laws and regulations
applicable to UVM. In working with utilities, regulators and service providers around the world,
Mr. Cieslewicz has been directly involved in the bulk of tree and power line issues of note. He
was a principal UVM investigator for the Joint U.S./Canada Power Systems Outage Task Force,
a principal author of all UVM related reports following the August 14, 2003 blackout, and has
been directly involved with the crafting or interpretation of UVM standards, best practices, and
laws and regulations throughout the US and abroad.
An ISA Certified Arborist and Utility Specialist, Mr. Cieslewicz has testified as an expert at
many significant legal, regulatory and legislative hearings. He is a past president of the Utility
Arborist Association (UAA) and a recipient of numerous awards, including the UAA Utility
Arborist Award, UAA President’s Award, and certificates of appreciation from the U.S. and
Canadian governments. Mr. Cieslewicz is also a well known speaker and author on UVM issues,
and was recently selected by Green Media (publisher of Arbor Age, Landscape and Irrigation,
Outdoor Power Equipment and Sports Turf) as one of eight most influential people in the green
industry.
Orville Cocking is currently the Section Manager of the Transmission Line Maintenance Group
at Consolidated Edison of New York, overseeing Transmission Line Maintenance and the
Transmission Vegetation Management Program (TVMP). He has spent the last six years working
in positions of increasing responsibilities in Central Engineering and Transmission Operations.
He spent the 9 years prior to joining Consolidated Edison performing structural analysis of
transmission and other unique structures as an engineering consultant.
Mr. Cocking has a Bachelor of Science degree in Civil Engineering, and is a licensed
professional engineer in the states of New York, Delaware, and New Jersey.
Richard Dearman is a Senior Advisor on NERC Compliance at the Tennessee Valley
Authority. Mr. Dearman has held numerous positions in engineering, maintenance and
management within transmission and distribution since 1971. He has supported FEMA with
investigations of disaster recovery claims on three occasions in Minnesota, Illinois, and
Tennessee. In 1997, Mr. Dearman led a team within TVA that resulted in the reorganization and
centralization of the TVA right-of-way maintenance program. He was assigned the management
responsibility for the program at that that time, and held that position until April 2010. The
interruption rate due to vegetation related outages declined to record low levels under Mr.
Dearman’s management. His 17 years management experience in transmission line right of way
maintenance culminated in responsibility for TVA's full program oversight for over 17,000 miles
of transmission lines with annual expenditures in excess of $19M in FY 2009.
Mr. Dearman served on the NERC Outage Investigation Team as a transmission industry
expert/representative to perform field investigations of tree related interruptions that were
associated with the August 14, 2003 blackout. He was the first Chairman of the SERC
Vegetation Management Subcommittee inn 2004, and held that position for 5 years.
Mr. Dearman has participated in two industry peer reviews of transmission system vegetation
maintenance programs sponsored by the North American Transmission Forum, and has led an
EPRI project to reduce Human Errors in Switching Safety and Reliability. He has also led
numerous safety and human performance improvement initiatives, projects, and investigations at
TVA. He is well known within TVA for his investigative abilities to determine causes for
transmission system interruptions, including (but not limited to) suspected and actual vegetation
related outages.
Mr. Dearman holds a Bachelor of Science degree in Electrical Engineering, as well as an Master
in Business Administration degree, and is a Registered Professional Engineer
Randall F. Gann
Randall Gann is the Manager of Power Delivery Contract Services for Alabama Power
Company. He has held this position for the past 10 years. Part of Mr. Gann’s responsibilities
while holding this position has included vegetation management for 70,000 miles of distribution
voltage lines and over 10,000 miles of transmission voltage lines. Prior to this, Mr. Gann held
positions as Manager of Transmission Line Design and Transmission Line Construction for 8
years. He has worked the remainder of his career in various supervisory and engineering
positions for Alabama Power Company in distribution and transmission operations and
maintenance; and also Nuclear Generation Construction. Mr. Gann has over 40 years
experience with the Southern Company, and is a member of the Vegetation Management SubCommittee reporting to the SERC Operating Committee.
Mr. Gann holds a Bachelor of Science degree from Auburn University in Electrical Engineering
and is a registered Professional Engineer in the State of Alabama.
Jeff Hackman is Manager – Transmission Operations for Ameren. In this role, he has
responsibility for Transmission and Balancing Authority Operations, EMS support for
Operations, Transmission Construction and Maintenance, Transmission Vegetation
Management, Transmission Design, and Transmission Project Management. Mr. Hackman has
been with Ameren or its predecessor companies since 1980. He has held many positions with
increasing responsibility in transmission planning, design, and operations. Mr. Hackman has also
held supervisory or management positions in distribution line design and distribution operations,
including overhead and underground maintenance and construction activities. He has also
performed studies to support power plant operation, and was responsible for engineering and
design for distribution gas service in one of Ameren’s divisions.
Mr. Hackman has conducted research and published/presented papers on insulation degradation
and insulator design to prevent flashover in contaminated environments. He was the Missouri
Society of Professional Engineers – St Louis Chapter “Young Engineer of the Year,” and is
currently a Senior Member of the IEEE. Hackman received earned his Bachelor of Science
degree in Electrical Engineering from the University of Missouri – Rolla (now Missouri
University of Science & Technology), and a Master of Arts degree in Business Administration
from Webster University. He is a registered professional engineer in Missouri.
David Morrell is a Utility Environmental Analyst with the New York State Department of
Public Service (the Department). He holds an Associate of Applied Science degree in Land
Management and a Bachelor of Science in Forestry degree, with a specialization in Forest
Resource Management.
Mr. Morrell has been with the NYS Department of Public Service for 21 years. Much of this
time has been spent overseeing NY's Investor Owned Utilities ROW vegetation management
programs pursuant to the Departments regulations. Mr. Morrell served on the first NERC
vegetation standard drafting team, has written a number of the Departments recent regulations
pertaining to ROW management, sits on ROW management training committees, and has
authored a number of peer reviewed papers regarding issues in ROW management. Mr. Morell
worked in the utility industry in the areas of T&D vegetation management and inspection for 5
years prior to joining the Department .
Mr. Morrell is a Certified ROW Pesticide Applicator and has received Departmental awards and
recognitions for outstanding performance.
John Pinney is currently the Lead Transmission Forester for Progress Energy Florida, and been
involved in utility vegetation management for the past 16 years. He is in charge of Progress
Energy Florida’s transmission vegetation management program and responsible the associated
compliance program and documentation. Additionally, Mr. Pinney has worked for two utilities in
the past in supervisory and management roles related to vegetation management for transmission
and distribution.
A certified arborist, Mr. Pinney also holds membership in the International Society of
Arboriculture and the Utility Arborists Association, and holds a pesticide applicators license in
the state of Florida.
John Schechter is Manager of American Electric Power’s Protection & Control Engineering
office in Columbus, Ohio. Mr. Schechter has been with American Electric Power (AEP) or its
operating companies since 1980. He has held many positions with increasing responsibility over
the past thirty years, in areas of substation operation, construction, maintenance, and
engineering. Mr. Schechter has also held supervisory or managerial positions in distribution line
design, distribution service dispatching, and overhead and underground distribution maintenance
and construction. For five years, he was responsible for the asset condition and forestry program
for AEP’s 35,000-mile transmission system, including over 8,000 miles of line operating above
200kV, and was accountable to state regulatory commission staff for the performance and
compliance of AEP’s transmission line assets.
Mr. Schechter served on the ECAR VM task force and has conducted presentations to promote
vegetation standards at compliance workshops conducted by ERCOT, Southwest Power Pool and
ReliabilityFirst. Mr. Schechter received his Bachelor of Science degree in electrical engineering
from the University of Cincinnati, his Master of Science degree in electric power systems
engineering from The Ohio State University, and his Master of Business Administration degree
from the University of Notre Dame. He is a registered professional engineer in the states of
Indiana and Ohio.
John Tamsberg is currently Manager of Transmission Vegetation Management for Florida
Power and Light (FPL), where he manages the vegetation on 6,700 miles of Transmission in
Florida and at 950 miles for NextEra Energy at sites across the US and Canada. Prior to his 25
years at FPL, Mr. Tamsberg spent 15 years working in state government, managing timber for
the South Carolina Commission of Forestry and working for the Florida Division of Forestry in
forest management, urban forestry and fire suppression.
With over 40 year’s total experience in forestry and vegetation management, Mr. Tamsberg has
served on a number of Urban Forestry and Landscape Advisory Boards. He served the
International Society of Arboriculture on the Certification Test Committee, is past president of
the Florida Urban Forestry Council, and is currently a member of the Arborist Certification
Ethics Committee.
Mr. Tamsberg has a Bachelor of Science degree in Forestry from Clemson University, and is a
Certified Arborist.
Stephen Tankersley is Operations Manager of Pacific Gas and Electric Company's (PG&E)
Vegetation Management Department. He has been with PG&E for 34 years, holding a variety of
positions of increasing responsibility in Engineering & Construction, Project Management,
Financial and Business Systems Process Engineering, and most recently Vegetation
Management, where he has served in his current position since 1999.
Mr. Tankersley has significant previous expertise in formal project/program management;
process engineering; utility construction productivity; and computer systems design,
development and implementation; and has used this expertise building PG&E's UVM program.
PG&E has one of the largest UVM programs in the nation, covering 70,000 sq. miles with
114,000 miles of overhead distribution and 20,000 miles of transmission, and operates under the
strictest UVM regulatory environment in the country. Mr. Tankersley is a frequent speaker on
topics related to UVM business operations, operating UVM programs in California's regulatory
environment, and building effective UVM programs, and frequently contributes to UVM
industry publications. Most recently, the Utility Arborist Association published an article by Mr.
Tankerlsey discussing “Best Management Practices for Project Management Applied to Utility
Vegetation Management.”
Ron Turley is currently a Special Programs Manager for the Western Area Power
Administration. He has 30 years experience in the electrical utility industry with the U.S.
Department of Energy. Turley has over 28 years of management experience overseeing various
combinations of engineering, construction and maintenance functions for high voltage
transmission and substation facilities interconnecting Federal hydroelectric generation facilities
such as Hoover, Glen Canyon and Flaming Gorge Dams in the Colorado River drainage basin.
One of his current responsibilities involves the development and management of a vegetation
management program for Western’s Rocky Mountain Region which involves over 5000 miles of
high voltage transmission across seven western states.
Mr. Turley was appointed by former Colorado Governor Ritter and retained by current Governor
Hickenlooper on the Colorado Governor’s Forest Health Advisory Council. He has frequently
served as a technical industry expert to the Department of the Agriculture, U.S. Forest Service
and Department of the Interior, Bureau of Land Management. Turley also serves on a number of
other public organizations involved with the management of declining forest health and wildland
fire issues affecting forested landscapes across the western United States and Canada. Mr.
Turley holds a Bachelor of Science degree in Biological Science from the State University of
New York at Binghamton and a Master of Science degree in Civil Engineering from Colorado
State University.
Gary White is a Vegetation Management Program Manager – Forester for Oncor Electric
Delivery LLC. Oncor’s T&D system consists of approximately 113,000 miles of distribution
facilities and 15,000 miles of transmission. For the last six years, Mr. White has been in the
Asset Management – Maintenance Strategy and Planning workgroup responsible for VM
strategy and planning. Prior to this position, Mr. White held various positions within Oncor’s
Vegetation Management workgroup for 24 years. He worked for a national line clearance
company for 4 years prior to joining Oncor.
Mr. White holds a Bachelor of Science-Forestry degree from Stephen F. Austin State University.
He holds a Texas Department of Agriculture Non Commercial Applicators license. He is a
member of the International Society of Arboriculture (ISA) and a Certified Arborist and Utility
Specialist through the ISA. He is a member of the Utility Arborists Association and a charter
member and past president of the International Society of Arboriculture -Texas Chapter.
Phil Whitmer is the Transmission Compliance Manager for Georgia Power Company. He
joined Georgia Power in 1980. During his career, he served ten years in Distribution
Engineering, seven years in Industrial Marketing, six years in Transmission Line and Substation
Maintenance, eight years in Transmission System Operations, and one year in Compliance.
Mr. Whitmer holds a Bachelor of Science degree in Electrical Engineering from the Georgia
Institute of Technology and a Master in Business Administration degree from Augusta State
University. He also obtained his Certified Energy Manager certification in 1996.
Ken Wright is Lead Superintendent, Transmission Maintenance at Tucson Electric Power
Company (TEP) in Tucson, AZ. His current responsibilities include Transmission Line
Maintenance in Arizona and New Mexico and Distribution Line Vegetation Management in
Arizona. He has held several positions in his 35 year career at TEP, including Substation Civil
Engineer, Gas Engineer, Transmission Engineer, Superintendent-Transmission Line C&M, Civil
& Transmission Engineering Manager and T & D Construction & Maintenance Manager.
Taking an early retirement in 1996, Mr. Wright opened and managed the Tucson Office for
Engineering Consultants, Inc. and returned to TEP in 2002 to head up the Transmission Line
Design, Maintenance and Construction Department. Mr. Wright is a member of the American
Society of Civil Engineers. He is a Registered Civil Engineer and Registered Land Surveyor in
Arizona, sits on two Boards of Director for non-profit organizations, and holds a Bachelor of
Science degree in Civil Engineering from The University of Arizona.
Exhibit I
Transmission Vegetation Management – FAC-003-2 Technical Reference Document
Transmission Vegetation
Management
Standard FAC-003-2 Technical Reference
Prepared by the
North American Electric Reliability Corporation
Vegetation Management Standard Drafting Team for NERC
Project 2007-07
September 30, 2011
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Ta b le o f Co n t e n t s
Disclaimer........................................................................................................................................ 3
Introduction .................................................................................................................................... 4
Preface ............................................................................................................................................ 8
Effective Dates & Special States of Transition ................................................................................ 9
Definition of Terms ....................................................................................................................... 12
Applicability of the Standard ........................................................................................................ 14
Requirements R1 and R2 .............................................................................................................. 17
Requirement R3 ............................................................................................................................ 20
ANSI A300 – Best Management Practices for Tree Care Operations ........................................... 25
Requirement R4 ............................................................................................................................ 30
Requirement R5 ............................................................................................................................ 32
Requirement R6 ............................................................................................................................ 34
Requirement R7 ............................................................................................................................ 36
Appendix 1: Clearance Distance Derivation by the Gallet Equation ........................................... 39
Table 1 — Minimum Vegetation Clearance Distances (MVCD) .................................................... 44
List of Acronyms and Abbreviations ................................................................................................ii
References ......................................................................................................................................iii
2
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Dis cla im e r
This supporting document is supplemental to the reliability standard FAC-003-2 — Transmission
Vegetation Management and does not contain mandatory requirements subject to compliance
review. Throughout this document, for ready reference, there are “copies” in italic font of the
wording in the Standard. Any “copy” of any part of the Standard in this document should be
cross checked to the Standard and if any difference exists, then the Standard’s exact wording
should be considered the intended wording for this document.
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
3
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
I n t ro d u ct io n
This document is intended to provide supplemental information and guidance for complying
with the requirements of Reliability Standard FAC-003-2.
The purpose of the Standard is to improve the reliability of the electric transmission system by
preventing those vegetation related outages that could lead to Cascading.
Compliance with the Standard is mandatory and enforceable.
4
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Sp e cia l No t e : Th e Ap p lica t io n o f t h e Re s u lt s -Ba s e d
Ap p ro a ch t o FAC-0 0 3 -2
In its three-year assessment as the ERO, NERC acknowledged stakeholder comments and
committed to:
i) addressing quality issues to ensure each reliability standard has a clear statement of
purpose, and has outcome-focused requirements that are clear and measurable;
and
ii) eliminating requirements that do not have an impact on bulk power system
reliability.
In 2010, the Standards Committee approved a recommendation to use Project 2007-07
Vegetation Management as a first proof of concept for developing results-based standards.
This standard is not intended to address outages such as those due to vegetation fall-ins or
blow-ins from outside the Right-of-Way, vandalism, human activities or acts of nature.
Operating experience indicates that trees that have grown out of specification have contributed
to Cascading, especially under heavy electrical loading conditions.
This standard utilizes three types of requirements to provide layers of protection to prevent
vegetation related outages that could lead to Cascading:
a)
b)
c)
Performance-based defines a particular reliability objective or outcome to be
achieved. In its simplest form, a results-based requirement has four components:
who, under what conditions (if any), shall perform what action, to achieve what
particular result or outcome?
Risk-based preventive requirements to reduce the risks of failure to acceptable
tolerance levels. A risk-based reliability requirement should be framed as: who,
under what conditions (if any), shall perform what action, to achieve what
particular result or outcome that reduces a stated risk to the reliability of the bulk
power system?
Competency-based defines a minimum set of capabilities an entity needs to
have to demonstrate it is able to perform its designated reliability functions. A
competency-based reliability requirement should be framed as: who, under what
conditions (if any), shall have what capability, to achieve what particular result or
outcome to perform an action to achieve a result or outcome or to reduce a risk to
the reliability of the bulk power system?
The defense-in-depth strategy for reliability standards development recognizes that each
requirement in a NERC reliability standard has a role in preventing system failures, and that
these roles are complementary and reinforcing. Reliability standards should not be viewed as a
body of unrelated requirements, but rather should be viewed as part of a portfolio of
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
5
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
requirements designed to achieve an overall defense-in-depth strategy and comport with the
quality objectives of a reliability standard.
This NERC Vegetation Management Standard (“standard”) uses a defense-in-depth approach to
improve the reliability of the electric Transmission System by:
•
Requiring that vegetation be managed to prevent vegetation encroachment inside the
flash-over clearance (R1 and R2);
•
Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over conditions
including consideration of 1) conductor dynamics and 2) the interrelationships between
vegetation growth rates, control methods and the inspection frequency (R3);
•
Requiring timely notification to the appropriate control center of vegetation conditions
that could cause a flash-over at any moment (R4);
•
Requiring corrective actions to ensure that flash-over distances will not be violated due
to work constrains such as legal injunctions (R5);
•
Requiring inspections of vegetation conditions to be performed annually (R6); and
•
Requiring that the annual work needed to prevent flash-over is completed (R7).
For this standard, the requirements have been developed as follows:
•
Performance-based: Requirements 1 and 2
•
Competency-based: Requirement 3
•
Risk-based: Requirements 4, 5, 6 and 7
R3 serves as the first line of defense by ensuring that entities understand the problem they are
trying to manage and have fully developed strategies and plans to manage the problem. R1,
R2, and R7 serve as the second line of defense by requiring that entities carry out their plans
and manage vegetation. R6, which requires inspections, may be either a part of the first line of
defense (as input into the strategies and plans) or as a third line of defense (as a check of the
first and second lines of defense). R4 serves as the final line of defense, as it addresses cases in
which all the other lines of defense have failed.
Major outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations.
Adherence to the standard requirements for applicable lines on any kind of land or easement,
whether they are Federal Lands, state or provincial lands, public or private lands, franchises,
easements or lands owned in fee, will reduce and manage this risk. For the purpose of the
standard the term “public lands” includes municipal lands, village lands, city lands, and a host of
other governmental entities.
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Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
The standard addresses vegetation management along applicable overhead lines and does not
apply to underground lines, submarine lines or to line sections inside an electric station
boundary.
The standard focuses on transmission lines to prevent those vegetation related outages that
could lead to Cascading. It is not intended to prevent customer outages due to tree contact
with lower voltage distribution system lines. For example, localized customer service might be
disrupted if vegetation were to make contact with a 69kV transmission line supplying power to
a 12kV distribution station. However, this standard is not written to address such isolated
situations which have little impact on the overall electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses an
increased outage risk, especially when numerous transmission lines are operating at or near
their Rating. This can present a significant risk of consecutive line failures when lines are
experiencing large sags thereby leading to Cascading. Once the first line fails the shift of the
current to the other lines and/or the increasing system loads will lead to the second and
subsequent line failures as contact to the vegetation under those lines occurs. Conversely,
most other outage causes (such as trees falling into lines, lightning, animals, motor vehicles,
etc.) are not an interrelated function of the shift of currents or the increasing system loading.
These events are not any more likely to occur during heavy system loads than any other time.
There is no cause-effect relationship which creates the probability of simultaneous occurrence
of other such events. Therefore these types of events are highly unlikely to cause large-scale
grid failures. Thus, this standard places the highest priority on the management of vegetation
to prevent vegetation grow-ins.
The drafting team reviewed and edited version 1 of FAC-003-1 to remove prescriptive and
administrative language in order to distill the technical requirements down to their essential
reliability content. Explanatory text is offered within two special sections, Background and
Guideline and Technical Basis, to aid in understanding the standard and its requirements.
Rationale text boxes and other text boxes are also inserted throughout the standard to aid
understanding the sections. The Effective Dates section covers five special cases for lines that
undergo specific transitions as or after the standard has reached the general effective date.
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Preface
The NERC Vegetation Management Standard Drafting Team (VM SDT) acknowledges those
across the industry who contributed to the development of this Standard and companion
Technical Reference document. This Technical Reference document is intended to provide
supplemental explanatory background and guidance related to requirements contained in the
Standard but does not in itself contain requirements subject to compliance review.
The Standard requires the Transmission Owner to have documentation of the maintenance
strategies or procedures or processes or specifications it uses to be successful in managing
vegetation. This allows the Transmission Owner to exercise substantial flexibility in designing
its overall program to meet its specific needs provided that the Transmission Owner also meets
the purpose of the Standard.
While there are many approaches to vegetation management, the VMSDT supports industry
best practices contained in ANSI A300 (Part 7) – Integrated Vegetation Management (IVM)
practices on Utility Rights-of-way, as well as the companion publication Best Management
Practices – Integrated Vegetation Management, as an effective strategy to maintain compliance
with this Standard. ANSI A300 (Part 7), approved by industry consensus in 2006, contains many
elements needed for an effective vegetation management. Those elements are similar to the
requirements in this Standard. One key element is the “wire zone – border zone” concept.
Supported by over 50 years of continuous research, wire zone – border zone is a proven
method to manage vegetation on transmission rights-of-ways and is an industry accepted best
practice to help ensure electric system reliability.
The VM SDT believes that Transmission Owners who adopt and effectively implement IVM
principles, particularly the “wire zone – border zone” concept, are far less likely to experience a
vegetation caused outage than those who do not.
8
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Effective Dates & Special States of Transition
The first sentence of the Effective Dates section is standard language used in most NERC
standards to cover the general effective date and is sufficient to cover the vast majority of
situations. Five special cases are needed to cover effective dates for individual lines which
undergo transitions after the general effective date. These special cases cover the effective
dates for those lines which are initially becoming subject to the standard, those lines which are
changing their applicability within the standard, and those lines which are changing in a manner
that removes their applicability to the standard. The text for each of these five cases is copied
from the standard and is shown below in italic font. An explanation of the need for each special
exception follows each copied text section.
1. A line operated below 200kV, designated by the Planning Coordinator as an element
of an Interconnection Reliability Operating Limit (IROL) or designated by the Western
Electricity Coordinating Council (WECC) as an element of a Major WECC Transfer
Path, becomes subject to this standard the latter of: 1) 12 months after the date the
Planning Coordinator or WECC initially designates the line as being an element of an
IROL or an element of a Major WECC Transfer Path, or 2) January 1 of the planning
year when the line is forecast to become an element of an IROL or an element of a
Major WECC Transfer Path.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to
become elements of an IROL or Major WECC Transfer Path in a future Planning Year (PY). For
example, studies by the Planning Coordinator in 2011 may identify a line to have that
designation beginning in PY 2021, ten years after the planning study is performed. It is not
intended for the Standard to be immediately applicable to, or in effective for, that line until that
future PY begins. The effective date provision for such lines ensures that the line will become
subject to the standard on the January 1 of the PY specified with an allowance of at least 12
months for the Transmission Owner to make the necessary preparations to achieve compliance
on that line. The table below has some explanatory examples of the application.
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
9
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Date that
Planning Study is
completed
PY the line
will become
an IROL
element
Date 1
Date 2
The latter of Date 1
or Date 2
05/15/2011
2012
05/15/2012
01/01/2012
05/15/2012
05/15/2011
2013
05/15/2012
01/01/2013
01/01/2013
05/15/2011
2014
05/15/2012
01/01/2014
01/01/2014
05/15/2011
2021
05/15/2012
01/01/2021
01/01/2021
Effective Date
2. A line operated below 200 kV currently subject to this standard as a designated
element of an IROL or a Major WECC Transfer Path which has a specified date for the
removal of such designation will no longer be subject to this standard effective on
that specified date.
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or
Major WECC Transfer Path may be removed from that designation due to system
improvements, changes in generation, changes in loads or changes in studies and analysis of
the network.
3. A line operated at 200 kV or above, currently subject to this standard which is a
designated element of an IROL or a Major WECC Transfer Path and which has a
specified date for the removal of such designation will be subject to Requirement R2
and no longer be subject to Requirement R1 effective on that specified date
Case 3 is needed because a line operating at 200 kV or above that once was designated as an
element of an IROL or Major WECC Transfer Path may be removed from that designation due to
system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network. Such changes result in the need to apply R1 to that line until that date
is reached and then to apply R2 to that line thereafter.
4. An existing transmission line operated at 200kV or higher which is newly acquired by
an asset owner and which was not previously subject to this standard becomes
subject to this standard 12 months after the acquisition date.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be
acquired by a Transmission Owner from a third party such as a Distribution Provider or other
end-user who was using the line solely for local distribution purposes, but the Transmission
owner, upon acquisition, is incorporating the line into the interconnected electrical energy
transmission network which will thereafter make the line subject to the standard.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
5. An existing transmission line operated below 200kV which is newly acquired by an
asset owner and which was not previously subject to this standard becomes subject
to this standard 12 months after the acquisition date of the line if at the time of
acquisition the line is designated by the Planning Coordinator as an element of an
IROL or by WECC as an element of a Major WECC Transfer Path.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by a
Transmission Owner from a third party such as a Distribution Provider or other end-user who
was using the line solely for local distribution purposes, but the Transmission owner, upon
acquisition, is incorporating the line into the interconnected electrical energy transmission
network. In this special case the line upon acquisition was designated as an element of an
Interconnection Reliability Operating Limit (IROL) or an element of a Major WECC transfer Path.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Definition of Terms
Right-of-Way (ROW)*
The corridor of land under a transmission line(s)
The current glossary definition of this NERC
needed to operate the line(s). The width of the
term is modified to address the issues set forth
corridor is established by engineering or
in Paragraph 734 of FERC Order 693.
construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout
standard in effect when the line was built. The ROW width in no case exceeds the Transmission
Owner’s legal rights but may be less based on the aforementioned criteria.
The current NERC glossary definition of Right of Way has been modified to address the matter
set forth in Paragraph 734 of FERC Order 693. The Order pointed out that Transmission Owners
may in some cases own more property or rights than are needed to reliably operate
transmission lines. This modified definition represents a slight but significant departure from
the strict legal definition of “right of way” in that this definition is based on engineering and
construction considerations that establish the width of a corridor from a technical basis. The
pre-2007 maintenance records are included to allow the use of such vegetation widths if there
were no engineering or construction standards that referenced the width of right of way to be
maintained for vegetation on a particular line but the evidence exists in maintenance records
for a width that was in fact maintained prior to this standard becoming mandatory. Such
widths may be the only information available for lines that had limited or no vegetation
easement rights and were typically maintained primarily to ensure public safety. This standard
does not require additional easement rights to be purchased to satisfy a minimum right of way
width that did not exist prior to this standard becoming mandatory.
This definition does not imply that danger tree rights beyond the constructed and maintained
width are incorporated in the definition; therefore fall-ins from outside the ROW but within an
area with danger tree rights would not be considered fall-ins from within the ROW.
Vegetation Inspection*
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the Transmission Owner’s control
that are likely to pose a hazard to the line(s) prior
to the next planned maintenance or inspection. This
may be combined with a general line inspection.
The inspection includes the identification of any
vegetation that may pose a threat to reliability
12
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
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prior to the next planned maintenance or inspection work, considering the current location of
the conductor and other possible locations of the conductor due to sag and sway for rated
conditions.
This definition allows both maintenance inspections and vegetation inspections to be
performed concurrently.
* This is a modification to a defined term in the NERC glossary and will be incorporated into the
NERC glossary of terms with final approval of this standard revision.
See the Guidelines and Technical Basis section on Requirement R6 contained within the
Standard for more details on inspections.
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a
method has been in the design of high voltage transmission lines. Keeping vegetation away
from high voltage conductors by this distance will prevent voltage flash-over to the vegetation.
See the explanatory text below for Requirement R3 and associated Figures 1, 2 and 3. Details
of the equations and an example calculation are provided in Appendix 1below of the Technical
Reference document. Table 1in Appendix 1 below provides MVCD values for various voltages
and altitudes.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Applicability of the Standard
4. Applicability
4.1. Functional Entities:
Transmission Owners
4.2. Facilities: Defined below (referred to as “applicable lines”), including but not
limited to those that cross lands owned by federal 1, state, provincial, public,
private, or tribal entities:
4.2.1 Each overhead transmission lines operated at 200kV or higher.
4.2.2 Each overhead transmission lines operated below 200kV identified as an
element of an IROL under NERC Standard FAC-014 by the Planning
Coordinator.
4.2.3 Each overhead transmission lines operated below 200 kV identified as an
element of a Major WECC Transfer Paths in the Bulk Electric System by
WECC.
Rationale
4.2.4 Each overhead transmission
The areas excluded in 4.2.4 were excluded based
line identified above (4.2.1
on comments from industry for reasons
through 4.2.3) located
summarized as follows: 1) There is a very low risk
outside the fenced area of
from vegetation in this area. Based on an informal
the switchyard, station or
survey, no TOs reported such an event. 2)
substation and any portion of
Substations, switchyards, and stations have many
the span of the transmission
inspection and maintenance activities that are
line that is crossing the
necessary for reliability. Those existing process
manage the threat. As such, the formal steps in this
substation fence.
4.3. Enforcement: The reliability
obligations of the applicable entities
and facilities are contained within
the technical requirements of this
standard
standard are not well suited for this environment.
3) NERC has a project in place to address at a later
date the applicability of this standard to
Generation Owners. 4) Specifically addressing the
areas where the standard does and does not apply
makes the standard clearer.
In Order 693, FERC discussed the 200 kV bright-line test of applicability. While FERC did not
change the 200 kV bright-line, the Commission remained concerned that there may be some
transmission lines operating at lesser voltages that could have significant impact on the Bulk
Electric System that should therefore be subject to this standard.
1
EPAct 2005 section 1211c: “Access approvals by Federal agencies”.
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NERC Standard FAC-014 has the stated purpose, “To ensure that System Operating Limits (SOLs)
used in the reliable planning and operation of the Bulk Electric System (BES) are determined
based on an established methodology or methodologies.” FAC-014 requires Reliability
Coordinators, Planning Coordinators, and Transmission Planners to have a methodology to
identify all lines that might comprise an IROL. Thus, these entities would identify sub-200 kV
lines that qualify as part of an IROL and should be subject to FAC-003-2.
Although all three entities may prepare the list of elements, the list as provided by the Planning
Coordinator function is the more appropriate choice for this Standard. The Time Horizon
needed to plan vegetation management work does not lend itself to the operating horizon of a
Reliability Coordinator. Additionally, the Planning Coordinator has a wider-area view than the
Transmission Planner and could thus identify any elements of importance to a sub-set of its
area that might be missed by a Transmission Planner.
Transmission Owners, who do not already get the list of circuits included in the definition of an
IROL, can get them from the Planning Coordinator. Specifically R5 of FAC-014 specifies that
“The Reliability Coordinator, Planning Authority (Coordinator) and Transmission Planner shall
each provide its SOLs and IROLs to those entities that have a reliability-related need for those
limits and provide a written request that includes a schedule for delivery of those limits”
Vegetation-related Sustained Outages that occur due to natural disasters are beyond the
control of the Transmission Owner. These events are not classified as vegetation-related
Sustained Outages and are therefore exempt from the Standard. Transmission lines are not
designed to withstand the impacts of natural disasters such as flood, drought, earthquake,
major storms, fire, hurricane, tornado, landslides, ice storms, etc. In the aftermath of
catastrophic system damage from natural disasters the Transmission Owner’s focus is on
electric system restoration for public safety and critical support infrastructure.
Sustained Outages due to human or animal activity are beyond the control of the Transmission
Owner. These outages are not classified as vegetation-related Sustained Outages and are
therefore exempt from the Standard. Examples of these events may include new plantings by
outside parties of tall vegetation under the transmission line planted since the last Vegetation
Inspection, tree contacts with line initiated by vehicles, logging activities, etc.
The foregoing exemptions are addressed in a new footnote 2. Referred to collectively as force
majeure events and activities, this footnote applies to requirements R1 and R2 in FAC-003-2.
The reliability objective of this NERC Vegetation Management Standard (“Standard”) is to
prevent vegetation-related outages which could lead to Cascading by effective vegetation
maintenance while recognizing that certain outages such as those due to vandalism, human
errors and acts of nature are not preventable. Operating experience clearly indicates that trees
that have grown out of specification could contribute to a cascading grid failure, especially
under heavy electrical loading conditions.
Serious outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations. To
properly reduce and manage this risk, it is necessary to apply the Standard to applicable lines
on any kind of land or easement, whether they are Federal Lands, state or provincial lands,
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
public or private lands, franchises, easements or lands owned in fee. For the purposes of the
Standard and this Technical Reference document, the term “public lands” includes municipal
lands, village lands, city lands, and land owned by a host of other governmental entities.
The Standard addresses vegetation management along applicable overhead lines that serve to
connect one electric station to another. However, it is not intended to be applied to lines
sections inside the electric station fence or other boundary of an electric station, submarine or
underground lines.
The Standard is intended to reduce the risk of Cascading involving vegetation. It is not intended
to prevent customer outages from occurring due to tree contact with all transmission lines and
voltages. For example, localized customer service might be disrupted if vegetation were to
make contact with a 69kV transmission line supplying power to a 12kV distribution station.
However, this Standard is not written to address such isolated situations which have little
impact on the overall Bulk Electric System.
Vegetation growth is constant and always present. Unmanaged vegetation below numerous
transmission lines that are operating at or near their Rating is highly problematic. This situation
has led to multiple subsequent line failures and Cascading. Conversely, most other outage
causes (such as trees falling into lines, lightning, animals, motor vehicles, etc.) are statistically
intermittent. These events are not any more likely to occur during heavy system loads than any
other time. There is no cause-effect relationship which creates the probability of simultaneous
occurrence of other such events. Therefore these types of events are highly unlikely to cause
large-scale grid failures. Thus, this Standard’s emphasis is on vegetation grow-ins.
In preparing the original vegetation management standard in 2005, industry stakeholders set
the threshold for applicability of the standard at 200kV. This was because an unexpected loss
of lines operating at above 200kV has a higher probability of initiating a widespread blackout or
cascading outages compared with lines operating at less than 200kV.
The original NERC Standard FAC-003-1 also allowed for application of the standard to “critical”
circuits (critical from the perspective of initiating widespread blackouts or cascading outages)
operating below 200kV. While the percentage of these circuits is relatively low, it remains a
fact that there are sub-200kV circuits whose loss could contribute to a widespread outage.
Given the very limited exposure and unlikelihood of a major event related to these lowervoltage lines, it would be an imprudent use of resources to apply the Standard to all sub-200kV
lines. The drafting team, after evaluating several alternatives, selected the IROL and WECC
Major Transfer Path criteria to determine applicable lines below 200 kV that are subject to this
standard.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Requirements R1 and R2
R1. Each Transmission Owner shall manage
vegetation to prevent encroachments into
the Minimum Vegetation Clearance
Distance (MVCD) of its applicable line(s)
which are either an element of an IROL, or
an element of a Major WECC Transfer
Path; operating within its Rating and all
Rated Electrical Operating Conditions of
the types shown below 2:
1. An encroachment into the MVCD as
shown in FAC-003-Table 2, observed
in Real-time, absent a Sustained
Outage 3,
2. An encroachment due to a fall-in from
inside the Right-of-Way (ROW) that
caused a vegetation-related Sustained
Outage 4,
3. An encroachment due to the blowing
together of applicable lines and
vegetation located inside the ROW
that caused a vegetation-related
Sustained Outage4,
4. An encroachment due to vegetation
growth into the MVCD that caused a
vegetation-related Sustained Outage4.
R2. Each Transmission Owner shall manage
vegetation to prevent encroachments into
the MVCD of its applicable line(s) which
are not either an element of an IROL, or
an element of a Major WECC Transfer
2
Rationale for R1 and R2:
Lines with the highest significance to
reliability are covered in R1; all other lines are
covered in R2.
Ra tio n a le fo r th e typ e s o f fa ilu re to
m a n a g e ve g e ta tio n wh ic h a re lis te d in
o rd e r o f in c re a s in g de g re e s o f s e ve rity
in n o n -c o m p lia n t p e rfo rm a n c e a s it
re la te s to a fa ilu re o f a Tra n s m is s io n
Owne r's ve g e ta tio n m a in te n a n c e
p ro g ra m :
1. This management failure is found by
routine inspection or Fault event
investigation, and is normally symptomatic of
unusual conditions in an otherwise sound
program.
2. This management failure occurs when the
height and location of a side tree within the
ROW is not adequately addressed by the
program.
3. This management failure occurs when side
growth is not adequately addressed and may
be indicative of an unsound program.
4. This management failure is usually
indicative of a program that is not addressing
the most fundamental dynamic of vegetation
management, (i.e. a grow-in under the line).
If this type of failure is pervasive on multiple
lines, it provides a mechanism for a Cascade.
This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to this reliability standard,
including natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either
by the Transmission Owner or an applicable regulatory body, ice storms, and floods; human or animal activity such as logging, animal
severing tree, vehicle contact with tree, or installation, removal, or digging of vegetation. Nothing in this footnote should be construed to
limit the Transmission Owner’s right to exercise its full legal rights on the ROW.
3
If a later confirmation of a Fault by the Transmission Owner shows that a vegetation encroachment within the MVCD has occurred from
vegetation within the ROW, this shall be considered the equivalent of a Real-time observation.
4
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage regardless of the actual
number of outages within a 24-hour period.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Path; operating within its Rating and all Rated Electrical Operating Conditions of the types
shown below2:
1. An encroachment into the MVCD as shown in FAC-003-Table 2, observed in Real-time,
absent a Sustained Outage3,
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage4,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage4,
4. An encroachment due to vegetation growth into the MVCD that caused a vegetationrelated Sustained Outage4
M1. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-time observations of any MVCD encroachments. (R1)
M2. Each Transmission Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R2. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained
Outages associated with encroachment types 2 through 4 above, or records
confirming no Real-time observations of any MVCD encroachments. (R2)
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the prevention of vegetation encroachments within a minimum distance of
transmission lines. Content-wise, R1 and R2 are the same requirements; however, they apply to
different Facilities. Both R1 and R2 require each Transmission Owner to manage vegetation to
prevent encroachment within the MVCD of transmission lines. R1 is applicable to lines that are
identified as an element of an IROL or Major WECC transfer path. R2 is applicable to all other
lines that are not an element of an IROL, and not an element of a Major WECC Transfer Path.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation
management for an applicable line that is an element of an IROL or Major WECC Transfer Path
is a greater risk to the interconnected electric transmission system than applicable lines that
are not an element of an IROL or a Major WECC Transfer Path. Applicable lines that are not an
element of an IROL or Major WECC Transfer Path do require effective vegetation management,
but these lines are comparatively less operationally significant. As a reflection of this difference
in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and Medium for R2.
R1 and R2 state that if vegetation encroaches within the distances in Table 1 in Appendix 1 of
this supplemental Technical Reference document, it is in violation of the standard. Table
1below, which is the same as Table 2 in the standard, tabulates the distances necessary to
prevent spark-over based on the Gallet equations as described more fully in Appendix 1 below.
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These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating and
Rated Electrical Operating Condition (potentially in violation of other standards), the
occurrence of a clearance encroachment may occur solely due to that condition. For example,
emergency actions taken by a Transmission Operator or Reliability Coordinator to protect an
Interconnection may cause excessive sagging and an outage. Another example would be ice
loading beyond the line’s Rating and Rated Electrical Operating Condition. Such vegetationrelated encroachments and outages are not violations of this standard.
Evidence of failures to adequately manage vegetation include real-time observation of a
vegetation encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related
encroachment resulting in a Sustained Outage due to a fall-in from inside the ROW, or a
vegetation-related encroachment resulting in a Sustained Outage due to the blowing together
of the lines and vegetation located inside the ROW, or a vegetation-related encroachment
resulting in a Sustained Outage due to a grow-in. Faults which do not cause a Sustained outage
and which are confirmed to have been caused by vegetation encroachment within the MVCD
are considered the equivalent of a Real-time observation for violation severity levels.
With this approach, the VSLs for R1 and R2 are structured such that they directly correlate to
the severity of a failure of a Transmission Owner to manage vegetation and to the
corresponding performance level of the Transmission Owner’s vegetation program’s ability to
meet the objective of “preventing the risk of those vegetation related outages that could lead
to Cascading.” Thus violation severity increases with a Transmission Owner’s inability to meet
this goal and its potential of leading to a Cascading event. The additional benefits of such a
combination are that it simplifies the standard and clearly defines performance for compliance.
A performance-based requirement of this nature will promote high quality, cost effective
vegetation management programs that will deliver the overall end result of improved reliability
to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For
example initial investigations and corrective actions may not identify and remove the actual
outage cause then another outage occurs after the line is re-energized and previous high
conductor temperatures return. Such events are considered to be a single vegetation-related
Sustained Outage under the standard where the Sustained Outages occur within a 24 hour
period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over,
for various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will prevent transmission outages.
If the TO has applicable lines operated at nominal voltage levels not listed in Table 2, then the
TO should use the next largest clearance distance based on the next highest nominal voltage in
the table to determine an acceptable distance.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Requirement R3
R3. Each Transmission Owner shall have
documented maintenance strategies or
procedures or processes or specifications it
uses to prevent the encroachment of
vegetation into the MVCD of its applicable
transmission lines that accounts for the
following:
3.1 Movement of applicable line
conductors under their Facility Rating
and all Rated Electrical Operating
Conditions;
Rationale
The documentation provides a basis for
evaluating the competency of the
Transmission Owner’s vegetation program.
There may be many acceptable approaches
to maintain clearances. Any approach must
demonstrate that the Transmission Owner
avoids vegetation-to-wire conflicts under all
Rated Electrical Operating Conditions. See
Figure 1 for an illustration of possible
conductor locations.
3.2 Inter-relationships between vegetation growth rates, vegetation
control methods, and inspection frequency.
M3. The maintenance strategies or procedures or processes or specifications
provided demonstrate that the Transmission Owner can prevent encroachment
into the MVCD considering the factors identified in the requirement. (R3)
Requirement R3 is a competency based requirement concerned with the maintenance
strategies, procedures, processes, or specifications, a Transmission Owner uses for vegetation
management.
An adequate transmission vegetation management program formally establishes the approach
the Transmission Owner uses to plan and perform vegetation work to prevent transmission
Sustained Outages and minimize risk to the transmission system. The approach provides the
basis for evaluating the intent, allocation of appropriate resources and the competency of the
Transmission Owner in managing vegetation. There are many acceptable approaches to
manage vegetation and avoid Sustained Outages. However, the Transmission Owner must be
able to show the documentation of its approach and how it conducts work to maintain
clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach a
Transmission Owner chooses to use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance
or maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the Transmission Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
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4. an annual work plan
The conductor’s position in space at any point in time is continuously changing in reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figures 1, 2, and 3 below.
Conductor Dynamics
In order for a Transmission Owner to develop a specific maintenance approach, it is important
to understand the dynamics of a line conductor’s movements. This paper will first address the
complexities inherent in observing and predicting conductor movement, particularly for field
personnel. It will then present some examples of maintenance approaches which Transmission
Owners may consider that take into account these complexities, and the practical approaches
that can be utilized by field personnel.
Additionally, it is important the Transmission Owner consider all conductor locations, the
MVCD, and vegetation growth between maintenance activities when developing a maintenance
approach.
Understanding Conductor Position and Movement
The conductor’s position in space at any point in time is continuously changing as a reaction to
a number of different loading variables. Changes in vertical and horizontal conductor
positioning are the result of thermal and physical loads applied to the line. Thermal loading is a
function of line current and the combination of numerous variables influencing ambient heat
dissipation including wind velocity/direction, ambient air temperature and precipitation.
Physical loading applied to the conductor affects sag and sway by combining physical factors
such as ice and wind loading.
As a consequence of these loading variables, the conductor’s position in space is dynamic and
moving. When calculating the range of conductor positions, the Transmission Owner should use
the same design criteria and assumptions that are used to establish Ratings and System
Operating Limits (SOLs), as described in other standards. Typically, the greatest conductor
movements occur at mid-span. As the conductor moves through various positions, a spark-over
zone surrounding the conductor moves with it. The radius of the spark-over zone may be found
by referring to Table 1 below. For illustrations of this zone and conductor movements, Figures
1, 2 and 3 below are provided. At the time of making a field observation, however, it is very
difficult to precisely know where the conductor is in relation to its wide range of all possible
positions. Therefore, Transmission Owners must adopt maintenance approaches that account
for this dynamic situation.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Figure 1
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Figure 2
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Figure 3
A cross-section view of a single conductor at a given point along the span is
shown with six possible conductor positions due to movement resulting from
thermal and mechanical loading.
Selecting a Maintenance Approach
In order to maintain adequate separation between vegetation and transmission line
conductors, the Transmission Owner must craft a maintenance strategy that keeps vegetation
well away from the spark-over zone mentioned above. In fact, it is generally necessary to
incorporate a variety of maintenance strategies. For example, one Transmission Owner may
utilize a combination of routine cycles, traditional IVM techniques and long-term planning.
Another Transmission Owner may place a higher reliance on frequent inspections and follow-up
remediation as opposed to a set cyclical approach. This variation of approaches is further
warranted when factors, such as terrain, vegetation types, weather and climate, and any,
environmental, legal or other land use constraints, must be considered in developing a
Transmission Owner’s specific approach to satisfying R3.
The following describes some strategies which may be utilized by a Transmission Owner. A
Transmission Owner’s basic maintenance approach in relatively flat terrain could be to remove
all incompatible vegetation from the ROW if it has the right to do so and has no constraints. In
mountainous terrain, however, this strategy could change to managing vegetation based on
vegetation-to-conductor clearances, since it might not be necessary to remove vegetation in a
valley that is far below the conductors at maximum sag.
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If faced with easement constraints on a line design with sufficient ground clearance, the
approach could be to allow vegetation such as fruit trees, but only up to a given height at
maturity (for example 10 feet from the ground). If constraints cannot be overcome and if design
clearances are sufficient, an exception to the Transmission Owner’s 10-foot guideline might be
made. If an approach is chosen to manage vegetation based primarily on clearance distances it
could include an inspection regimen to regularly ensure that impending clearance problems are
identified early for rectification.
ANSI A3 0 0 – Be s t Ma n a g e m e n t Pra ct ice s fo r Tr e e Ca r e Op e r a t io n s
A description of ANSI A-300, part 7, is offered below to illustrate another maintenance
approach that could be used in developing a comprehensive transmission vegetation
management program.
Introduction
Integrated Vegetation Management (IVM) is a best management practice conveyed in the
American National Standard for Tree Care Operations, Part 7 (ANSI 2006) and the International
Society of Arboriculture Best Management Practices: Integrated Vegetation Management
(Miller 2007). IVM is consistent with the requirements in FAC-003-02, and it provides
practitioners with what industry experts consider to be appropriate techniques to apply to
electric right-of-way projects in order to meet or exceed the Standard.
IVM is a system of managing plant communities whereby managers set objectives; identify
compatible and incompatible vegetation; consider action thresholds; and evaluate, select and
implement the most appropriate control method or methods to achieve set objectives. The
choice of control method or methods should be based on the environmental impact and
anticipated effectiveness; along with site characteristics, security, economics, current land use
and other factors.
Planning and Implementation
Best management practices provide a systematic way of planning and implementing a
vegetation management program. While designed primarily with transmission systems in mind,
it is also applicable to distribution projects. As presented in ANSI A300 part 7 and the ISA best
management practices, IVM consists of 6 elements:
1)
2)
3)
4)
5)
6)
Set Objectives
Evaluate the Site
Define Action Thresholds
Evaluate and Select Control Methods
Implement IVM
Monitor Treatment and Quality Assurance
The setting of objectives, defining action thresholds, and evaluating and selecting control
methods all require decisions. The planning and implementation process is cyclical and
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
continuous, because vegetation is dynamic and managers must have the flexibility to adjust
their plans. Adjustments may be made at each stage as new information becomes available
and circumstances evolve.
Set Objectives
Objectives should be clearly defined and documented. Examples of objectives can
include promoting safety, preventing sustained outages caused by vegetation growing
into electric facilities, maintaining regulatory compliance, protecting structures and
security, restoring electric service during emergencies, maintaining access and clear
lines of sight, protecting the environment, and facilitating cost effectiveness.
Objectives should be based on site factors, such as workload and vegetation type, in
addition to human, equipment and financial resources. They will vary from utility to
utility and project to project, depending on line voltage and criticality, as well as
topographical, environmental, fiscal and political considerations. However, where it is
appropriate, the overriding focus should be on environmentally-sound, cost effective
control of species that potentially conflict with the electric facility, while promoting
compatible, early successional, sustainable plant communities.
Work Load Evaluations
Work-load evaluations are inventories of vegetation that could have a bearing on
management objectives. Work load assessments can capture a variety of vegetation
characteristics, such as location, height, species, size and condition, hazard status,
density and clearance from conductors. Assessments should be conducted considering
voltage, conductor sag from ambient temperatures and loading, and the potential
influence of wind on line sway.
Evaluate and Select Control Methods
Control methods are the process through which managers achieve objectives. The most
suitable control method best achieves management objectives at a particular site. Many
cases call for a combination of methods. Managers have a variety of controls from
which to choose, including manual, mechanical, herbicide and tree growth regulators,
biological, and cultural options.
Manual Control Methods
Manual methods employ workers with hand-carried tools, including chainsaws,
handsaws, pruning shears and other devices to control incompatible vegetation. The
advantage of manual techniques is that they are selective and can be used where others
may not be. On the other hand, manual techniques can be inefficient and expensive
compared to other methods.
Mechanical Control Methods
Mechanical controls are done with machines. They are efficient and cost effective,
particularly for clearing dense vegetation during initial establishment, or reclaiming
neglected or overgrown right of way. On the other hand, mechanical control methods
can be non-selective and disturb sensitive sites.
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Tree Growth Regulator and Herbicide Control Methods
Tree growth regulators and herbicides can be effective for vegetation management.
Tree growth regulators (TGRs) are designed to reduce growth rates by interfering with
natural plant processes. TGRs can be helpful where removals are prohibited or
impractical by reducing the growth rates of some fast-growing species.
Herbicides control plants by interfering with specific botanical biochemical pathways.
Herbicide use can control individual plants that are prone to re-sprout or sucker after
removal. When trees that re-sprout or sucker are removed without herbicide treatment,
dense thickets develop, impeding access, swelling workloads, increasing costs, blocking
lines-of-site, and deteriorating wildlife habitat. Treating suckering plants allows early
successional, compatible species to dominate the right-of-way and out-compete
incompatible species, ultimately reducing work.
Cultural Control Methods
Cultural methods modify habitat to discourage incompatible vegetation and establish
and manage desirable, early successional plant communities. Cultural methods take
advantage of seed banks of native, compatible species lying dormant on site. In the long
run, cultural control is the most desirable method where it is applicable.
A cultural control known as cover-type conversion provides a competitive advantage to
short-growing, early successional plants, allowing them to thrive and eventually outcompete unwanted tree species for sunlight, essential elements and water. The early
successional plant community is relatively stable, tree-resistant and reduces the amount
of work, including herbicide application, with each successive treatment.
Wire-Border Zone
The wire-border zone technique is a management philosophy that can be applied
through cultural control. W.C. Bramble and W.R. Byrnes developed it in the mid-1980s
out of research begun in 1952 on a transmission right-of-way in the Pennsylvania State
Game Lands 33 Research and Demonstration project (Yahner and Hutnik (2004).
The wire zone is the section of a utility transmission right-of-way directly under the
wires and extending outward about 10 feet on each side. The wire zone is managed to
promote a low-growing plant community dominated by grasses, herbs and small shrubs
(under 3 feet in height at maturity). The border zone is the remainder of the right-ofway. It is managed to establish small trees and tall shrubs (under 25 feet in height at
maturity). When properly managed, diverse, tree-resistant plant communities develop
in wire and border zones. The communities not only protect the electric facility and
reduce long-term maintenance, but also enhance wildlife habitat, forest ecology and
aesthetic values.
Although the wire-border zone is a best practice in many instances, it is not necessarily
universally suitable. For example, standard wire-border zone prescriptions may be
unnecessary where lines are high off the ground, such as across low valleys or canyons,
so the technique can be modified without sacrificing reliability.
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One way to accommodate variances in topography is to establish different regions
based on wire height. For example, over canyon bottoms or other areas where
conductors are 100 feet or more above the ground, only a few trees are likely to be tall
enough to conflict with the lines. In those cases, trees that potentially interfere with the
transmission lines can be removed selectively on a case-by-case basis.
In areas where the wire is lower, perhaps between 50-100 feet from the ground, a
border zone community can be developed throughout the right-of-way. Note that in
many cases, conductor attachment points are more than 50 feet off the ground, so a
border zone community can be cultivated near structures. Where the line is less than
50 feet off the ground, managers could apply a full wire-border zone prescription.
An environmental advantage of this type of modification is stream protection. Streams
often course through the valleys and canyons where lines are likely to be elevated.
Leaving timber or border zone communities in canyon bottoms helps shelter this
valuable habitat, enabling managers to achieve environmentally sensitive objectives.
Implement IVM
All laws and regulations governing IVM practices and specifications written by qualified
vegetation managers must be followed. Integrated vegetation management control
methods should be implemented on regular work schedules, which are based on
established objectives and completed assessments. Work should progress systematically,
using control measures determined to be best for varying conditions at specific locations
along a right-of-way. Some considerations used in developing schedules include the
importance and type of line, vegetation clearances, workloads, growth rate of
predominant vegetation, geography, accessibility, and in some cases, time lapsed since
the last scheduled work.
Clearances Following Work
Clearances following work should be sufficient to meet management objectives,
including preventing trees from entering the Minimum Vegetation Clearance Distance,
electric safety risks, service-reliability threats and cost.
Monitor Treatment and Quality Assurance
An effective program includes documented processes to evaluate results. Evaluations
can involve quality assurance while work is underway and after it is completed.
Monitoring for quality assurance should begin early to correct any possible
miscommunication or misunderstanding on the part of crewmembers. Early and
consistent observation and evaluation also provides an opportunity to modify the plan,
if need be, in time for a successful outcome.
Utility vegetation management programs should have systems and procedures in place
for documenting and verifying that vegetation management work was completed to
specifications. Post-control reviews can be comprehensive or based on a statistically
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representative sample. This final review points back to the first step and the planning
process begins again.
Summary of A-300 example
Integrated Vegetation Management offers among others, a systematic way of planning and
implementing a vegetation management program as presented in ANSI A300 Part 7. This
methodology enables a program to comply with the NERC Transmission Vegetation
Management Program standard (FAC-003-2). Managers should select control options to best
promote management objectives.
Vegetation Inspections
The standard in R6 establishes the frequency of vegetation inspections. These inspections can
be used to “evaluate the site” as referred to in the second element of ANSI A300 Part 7. This
necessary frequency may need to be less than the annually based on anticipated growth rates
of the local vegetation, length of the growing season for the geographical area, limited ROW
width, rainfall amounts, etc.
Annual Work Plan
Requirement R7 of the Standard addresses the execution of the annual work plan. A
comprehensive approach that exercises the full extent of legal rights is superior to incremental
management in the long term because it reduces overall encroachments, and it ensures that
future planned work and future planned inspection cycles are sufficient at all locations on the
ROW. Removal is superior to pruning. Removal minimizes the possibility of conflicts between
energized conductors and vegetation. When this is not possible, the approach should be to use
vegetation maintenance methods to work towards or achieve the maximum use of the ROW.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Requirement R4
R4. Each Transmission Owner, without any
intentional time delay, shall notify the
control center holding switching
authority for the associated applicable
transmission line when the Transmission
Owner has confirmed the existence of a
vegetation condition that is likely to
cause a Fault at any moment.
Rationale
This is to ensure expeditious communication
between the Transmission Owner and the
control center when a critical situation is
confirmed.
M4. Each Transmission Owner that has a confirmed vegetation condition likely to cause a Fault
at any moment will have evidence that it notified the control center holding switching
authority for the associated transmission line without any intentional time delay. Examples
of evidence may include control center logs, voice recordings, switching orders, clearance
orders and subsequent work orders. (R4)
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the
Transmission Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4
involves the notification of potentially threatening vegetation conditions, without any
intentional delay, to the control center holding switching authority for that specific
transmission line. Examples of acceptable unintentional delays may include communication
system problems (for example, cellular service or two-way radio disabled), crews located in
remote field locations with no communication access, delays due to severe weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of a Transmission Owner’s employee who personally identifies such a threat in the
field. Confirmation could also be made by sending out an employee to evaluate a situation
reported by a landowner.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an assessment
of the possible sag or movement of the conductor while operating between no-load conditions
and its rating.
The Transmission Owner has the responsibility to ensure the proper communication between
field personnel and the control center to allow the control center to take the appropriate action
until the vegetation threat is relieved. Appropriate actions may include a temporary reduction
in the line loading, switching the line out of service, or positioning the system in recognition of
the increasing risk of outage on that circuit. The notification of the threat should be
communicated in terms of minutes or hours as opposed to a longer time frame for corrective
action plans (see R5).
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All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some Transmission Owners may have a danger tree identification
program that identifies trees for removal with the potential to fall near the line. These trees
would not require notification to the control center unless they pose an immediate fall-in
threat.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Requirement R5
R5. When a Transmission Owner is constrained
from performing vegetation work on an
applicable line operating within their
Rating and all Rated Electrical Operating
Conditions, and the constraint may lead to
a vegetation encroachment into the MVCD
prior to the implementation of the next
annual work plan, then the Transmission
Owner shall take corrective action to
ensure continued vegetation management
to prevent encroachments.
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
Transmission Owner from performing
planned vegetation maintenance work.
In cases where the transmission line is put at
potential risk due to constraints, the intent
is for the Transmission Owner to put interim
measures in place, rather than do nothing.
The corrective action process is not
M5. Each Transmission Owner has evidence of
intended to address situations where a
the corrective action taken for each
planned work methodology cannot be
constraint where an applicable
performed but an alternate work
transmission line was put at potential
methodology can be used.
risk. Examples of acceptable forms of
evidence may include initially-planned
work orders, documentation of constraints from landowners, court orders, inspection
records of increased monitoring, documentation of the de-rating of lines, revised work
orders, invoices, or evidence that a line was de-energized. (R5)
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
Transmission Owner for the mitigation of Sustained Outage risk when temporarily constrained
from performing vegetation maintenance. The intent of this requirement is to deal with
situations that prevent the Transmission Owner from performing planned vegetation
management work and, as a result, have the potential to put the transmission line at risk.
Constraints to performing vegetation maintenance work as planned could result from legal
injunctions filed by property owners, the discovery of easement stipulations which limit the
Transmission Owner’s rights, or other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
Transmission Owner is not under any immediate time constraint for achieving the management
objective, can easily reschedule work using an alternate approach, and therefore does not need
to take interim corrective action.
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However, in situations where transmission line reliability is potentially at risk due to a
constraint, the Transmission Owner is required to take an interim corrective action to mitigate
the potential risk to the transmission line. A wide range of actions can be taken to address
various situations. General considerations include:
•
Identifying locations where the Transmission Owner is constrained from performing
planned vegetation maintenance work which potentially leaves the transmission line
at risk.
•
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
•
Documenting and tracking the specific action taken for each location.
•
In developing the specific action to mitigate the potential risk to the transmission
line the Transmission Owner could consider location specific measures such as
modifying the inspection and/or maintenance intervals. Where a legal constraint
would not allow any vegetation work, the interim corrective action could include
limiting the loading on the transmission line.
•
The Transmission Owner should document and track the specific corrective action
taken at each location. This location may be indicated as one span, one tree or a
combination of spans on one property where the constraint is considered to be
temporary.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Requirement R6
R6. Each Transmission Owner shall perform a
Vegetation Inspection of 100% of its
applicable lines (measured in units of
choice - circuit, pole line, line miles or
kilometers, etc.) at least once per calendar
year and with no more than 18 months
between inspections on the same ROW. 5
Rationale
Inspections are used by Transmission Owners
to assess the condition of the entire ROW. The
information from the assessment can be used
to determine risk, determine future work and
evaluate recently-completed work. This
requirement sets a minimum Vegetation
Inspection frequency of once per calendar
year but with no more than 18 months
between inspections on the same ROW.
Based upon average growth rates across
North America and on common utility
practice, this minimum frequency is
reasonable. Transmission Owners should
consider local and environmental factors that
could warrant more frequent inspections.
M6. Each Transmission Owner has evidence
that it conducted Vegetation Inspections
of the transmission line ROW for all
applicable lines at least once per calendar
year but with no more than 18 months
between inspections on the same ROW.
Examples of acceptable forms of evidence
may include completed and dated work orders, dated invoices, or dated inspection
records. (R6)
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections that fits general industry practice. In addition, the fact that Vegetation
Inspections can be performed in conjunction with general line inspections further facilitates a
Transmission Owner’s ability to meet this requirement. However, the Transmission Owner may
determine that more frequent inspections are needed to maintain reliability levels, dependent
upon such factors as anticipated growth rates of the local vegetation, length of the growing
season for the geographical area, limited ROW width, and rainfall amounts. Therefore it is
expected that some transmission lines may be designated with a higher frequency of
inspections.
Footnote 5 is added to address the situation where a Transmission Owner through no fault of
its own, would be unable to complete the vegetation inspection within the allotted time period.
This would include the situation of mutual aid as well as disasters to the Transmission Owner’s
own system.
5
When the Transmission Owner is prevented from performing a Vegetation Inspection within the timeframe in R6 due to a natural disaster,
the TO is granted a time extension that is equivalent to the duration of the time the TO was prevented from performing the Vegetation
Inspection.
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The VSL for Requirement R6 has VSL categories ranked by the percentage of the required ROW
inspections completed. To calculate the percentage of inspection completion, the Transmission
Owner may choose units such as: line miles or kilometers, circuit miles or kilometers, pole line
miles, ROW miles, etc.
For example, when a Transmission Owner operates 2,000 miles of applicable transmission lines
this Transmission Owner will be responsible for inspecting all the 2,000 miles of lines at least
once during the calendar year. If one of the included lines was 100 miles long, and if it was not
inspected during the year, then the amount failed to inspect would be 100/2000 = 0.05 or 5%.
The “Low VSL” for R6 would apply in this example.
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Requirement R7
R7.
Each Transmission Owner shall complete
Rationale
100% of its annual vegetation work plan
of applicable lines to ensure no
This requirement sets the expectation that
vegetation encroachments occur within
the work identified in the annual work plan
the MVCD. Modifications to the work
will be completed as planned. It allows
plan in response to changing conditions
modifications to the planned work for
or to findings from vegetation inspections
changing conditions, taking into
may be made (provided they do not allow
consideration anticipated growth of
encroachment of vegetation into the
vegetation and all other environmental
MVCD) and must be documented. The
factors, provided that those modifications
percent completed calculation is based on do not put the transmission system at risk of
the number of units actually completed
a vegetation encroachment.
divided by the number of units in the final
amended plan (measured in units of
choice - circuit, pole line, line miles or kilometers, etc.) Examples of reasons for
modification to annual plan may include:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of a Transmission Owner 6
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
M7. Each Transmission Owner has evidence that it completed its annual vegetation work plan.
Examples of acceptable forms of evidence may include a copy of the completed annual
work plan (including modifications if any), dated work orders, dated invoices, or dated
inspection records. (R7)
R7 is a risk-based requirement. The Transmission Owner is required to implement its work plan
for vegetation management to accomplish the purpose of this Standard. Modifications to the
work plan in response to changing conditions or to findings from vegetation inspections may be
made and documented provided they do not put the transmission system at risk. The annual
6
Circumstances that are beyond the control of a Transmission Owner include but are not limited to natural disasters such as earthquakes, fires,
tornados, hurricanes, landslides, ice storms, floods, or major storms as defined either by the TO or an applicable regulatory body.
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work plan requirement is not intended to necessarily require a “span-by-span”, or even a “lineby-line” detailed description of all work to be performed. It is only intended to require that the
Transmission Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation
into the MVCD.
For example, when a Transmission Owner identifies 1,000 miles of applicable transmission lines
to be completed in the TO’s annual plan, the Transmission Owner will be responsible
completing those identified miles. If a TO makes a modification to the annual plan that does
not put the transmission system at risk of an encroachment the annual plan may be modified.
If 100 miles of the annual plan is deferred until next year the calculation to determine what
percentage was completed for the current year would be: 1000 – 100 (deferred miles) = 900
modified annual plan, or 900 / 900 = 100% completed annual miles. If a TO only completed 875
of the total 1000 miles with no acceptable documentation for modification of the annual plan
the calculation for failure to complete the annual plan would be: 1000 – 875 = 125 miles failed
to complete then, 125 miles (not completed) / 1000 total annual plan miles = 12.5% failed to
complete.
The ability to modify the work plan allows the Transmission Owner to change priorities or
treatment methodologies during the year as conditions or situations dictate. For example
recent line inspections may identify unanticipated high priority work, weather conditions
(drought) could make herbicide application ineffective during the plan year, or a major storm
could require redirecting local resources away from planned maintenance or work may be
deferred to a subsequent year because of slower-than-expected growth. This situation may
also include complying with mutual assistance agreements by moving resources off the
Transmission Owner’s system to work on another system. Any of these examples could result
in acceptable deferrals or additions to the annual work plan. Modifications to the annual work
plan must always ensure the reliability of the electric Transmission system.
In general, the vegetation management maintenance approach should use the full extent of the
Transmission Owner’s legal rights on the ROW. A comprehensive approach that exercises the
full extent of legal rights on the ROW is superior to incremental management in the long term
because it reduces the overall potential for encroachments, and it ensures that future planned
work and future planned inspection cycles are sufficient.
When developing the annual work plan the Transmission Owner should allow time for
procedural requirements to obtain permits to work on federal, state, provincial, public, tribal
lands. In some cases the lead time for obtaining permits may necessitate preparing work plans
more than a year prior to work start dates. Transmission Owners may also need to consider
those special landowner requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the Transmission
Owner, evidence of successful annual work plan execution could consist of signed-off work
orders, signed contracts, printouts from work management systems, spreadsheets of planned
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versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence
may include photographs and walk-through reports.
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Appendix 1: Clearance Distance Derivation by the
Gallet Equation
The Gallet Equation is a well-known method of computing the required strike distance for
proper insulation coordination, and has the ability to take into account various air gap
geometries, as well as non-standard atmospheric conditions. When the Gallet Equation and
conservative probabilistic methods are combined, i.e. deterministic design, spark-over
probabilities of 10-6 or less are achieved. This approach is well known for its conservatism and
was used to design the first 500 kV and 765 kV lines in North America [1]. Thus, the
deterministic design approach using the Gallet Equation is used for the standard to compute
the minimum strike distance between transmission lines and the vegetation that may be
present in or along the transmission corridor.
Method Explanation (Gallet Equation)
In 1975 G. Gallet published a benchmark paper that provided a method to compute the critical
flashover voltage (CFO) of various air gap geometries [4]. The Gallet Equation uses various “gap
factors” to take into account various air gap geometries. Various gap factor values are provided
in [1]. If the vegetation in a transmission corridor, e.g. a tree, is assumed electrically to be a
large structure then the CFO of such an air gap geometry can be computed for dry or wet
conditions using a well established equation proposed by Gallet [1],[2],[4],
CFOA = k w ⋅ k g ⋅ δ m ⋅
3400
8
1+
D
(1)
where,
kw
is defined as the factor that takes into account wet or
dry conditions
(dry = 1.0 and wet = 0.96) and phase arrangement (multiply by 1.08 for outside
phase), e.g. outside phase and wet conditions = (0.96)(1.08) = 1.037,
kg
is defined as the gap factor (1.3 for conductor to large structure),
D
is the strike distance (m),
CFOA
is the CFO for the relative air density (kV).
δ
is defined as the relative air density and is approximately equal to (2) where A
is the altitude in km,
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NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
δ =e
−
A
8.6
(2)
=
m 1.25G0 ( G0 − 0.2 )
(3)
CFOs
500 ⋅ D
(4)
3400
8
1+
D
(5)
G0 =
CFOs = k w ⋅ k g ⋅
where CFOS is the CFO for standard atmospheric conditions (kV). Using (1)-(5), the required CFOA can be
computed using an iterative process.
Once the CFOA is known, deterministic methods can be used to determine the required
clearance distance. If we let the maximum switching overvoltage be equal to the withstand
voltage of the air gap (CFOA - 3σ) then the CFOA can be written as (6).
CFOA =
Vm
σ
1− 3
CFOA
(6)
where
Vm is equal to the maximum switching overvoltage, i.e. the value that has a 0.135% chance of being
exceeded,
σ is the standard deviation of the air gap insulation,
CFOA is the critical flashover voltage of the air gap insulation under non-standard atmospheric conditions.
The ratio of σ to the CFOA given in (6) can be assumed to be 0.05 (5%) [1]. Thus, (6) can be
written as (7).
CFOA =
Vm
0.85
(7)
Substituting (7) into (1) we arrive at (8).
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ m ⋅
40
3400
8
1+
D
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
(8)
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Equation 8 relates the maximum transient overvoltage, Vm, to the air gap distance, D. Using (8)
to compute the required clearance distance for the specified air gap geometry (conductor to
large structure) results in a probability of flashover in the range of 10-6.
Transient Overvoltage
In general, the worst case transient overvoltages occurring on a transmission line are caused by
energizing or re-energizing the line with the latter being the extreme case if trapped charge is
present. The intent of FAC-003 is to keep a transmission line that is in service from becoming
de-energized (i.e. tripped out) due to sparkover from the line conductor to nearby vegetation.
Thus, the worst case scenarios that are typically analyzed for insulation coordination purposes
(e.g. line energization and re-energization) can be ignored. For the purposes of FAC-003-2, the
worst case transient overvoltage then becomes the maximum value that can occur with the line
energized. Determining a realistic value of transient overvoltage for this situation is difficult
because the maximum transient overvoltage factors listed in the literature are based on a
switching operation of the line in question. In other words, these maximum overvoltage values
(e.g. the values listed in [2], [3] and [5]) are based on the assumption that the subject line is
being energized, re-energized or de-energized. These operations, by their very nature, will
create the largest transient overvoltages. Typical values of transient overvoltages of in-service
lines, as such, are not readily available in the literature because the resulting level of
overvoltage is negligible compared with the maximum (e.g. re-energizing a transmission line
with trapped charge). A conservative value for the maximum transient overvoltage that can
occur anywhere along the length of an in-service ac line is approximately 2.0 p.u.[2]. This value
is a conservative estimate of the transient overvoltage that is created at the point of application
(e.g. a substation) by switching a capacitor bank without a pre-insertion device (e.g. closing
resistors). At voltage levels where capacitor banks are not very common (e.g. 362 kV), the
maximum transient overvoltage of an “in-service” ac line are created by fault initiation on
adjacent ac lines and shunt reactor bank switching. These transient voltages are usually 1.5 p.u.
or less [2]. It is well known that these theoretical transient overvoltages will not be
experienced at locations remote from the bus at which they were created; however, in order to
be conservative, it will be assumed that all nearby ac lines are subjected to this same level of
overvoltage. Thus, a maximum transient overvoltage factor of 2.0 p.u. for 302 kV and below
and 1.4 p.u. for ac transmission lines 362 kV and above is used to compute the required
clearance distances for vegetation management purposes.
The overvoltage characteristics of dc transmission lines vary somewhat from their ac
counterparts. The referenced empirically derived transient overvoltage factor used to calculate
the minimum clearance distances from dc transmission lines to vegetation for the purpose of
FAC-003-2 will be 1.8 p.u.[3].
Example Calculation
An example calculation is presented below using the proposed method of computing the
vegetation clearance distances. It is assumed that the line in question has a maximum
operating voltage of 550 kVrms line-to-line. Using a per unit transient overvoltage factor of 1.4,
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
41
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
the result is a peak transient voltage of 629 kVcrest. It is further assumed that the line in
question operates at a maximum altitude of 7000 feet (2.134 km) above sea level.
The required withstand voltage of the air gap must be equal to or greater than 629 kVcrest.
Since the altitude is above sea level, (1) - (5) have to be iterated on to achieve the desired
result. Equation (9) can be used as an initial guess for the clearance distance.
8
3400 ⋅ k w ⋅ k g
Di =
Vm
0.85
(9)
−1
For our case here, Vm is equal to 629 kV, kw = 1.037 and kg = 1.3. Thus,
Di =
8
3400 ⋅ k w ⋅ k g
Vm
0.85
=
−1
(10)
8
= 1.535m
3400 ⋅ 1.037 ⋅ 1.3
−1
629
0.85
Using (2)-(5) and (8) the withstand voltage of the air gap is next computed. This value will then
be compared to the maximum transient overvoltage.
CFOS = k w ⋅ k g ⋅
−
GO =
3400
3400
= 1.037 ⋅ 1.3 ⋅
= 737.7 kV
8
8
1+
1.535
D
A
−
2.134
8.6
8.6
=
δ e=
e =
0.78
(12)
CFOS
737.7
=
= 0.961
500 ⋅ D (500 ) ⋅ (1.535 )
(13)
m = 1.25 ⋅ GO (GO − 0.2 ) = 1.25 ⋅ 0.961(0.961 − 0.2 ) = 0.915
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ
m
(11)
1+
3400
3400
0.915
⋅
= (0.85 )(1.037 )(1.3 )(0.78 )
8
8
1+
1+
D
1.535
(14)
= 499.8 kV
(15)
The calculated Vm is less than 629 kV; thus, the clearance distance must be increased. A few
iterations using (2)-(5) and (8) are required until the computed Vm ≥ 629 kV. For this case it was
found that D = 1.978 m (6.49 feet) yielded Vm = 629.3 kV. Using this clearance distance the
following values were computed for the final iteration.
42
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
CFOS = k w ⋅ k g ⋅
−
3400
3400
= 1.037 ⋅ 1.3 ⋅
= 908.5 kV
8
8
1+
1+
D
1.978
A
−
2.134
8.6
8.6
=
δ e=
e =
0.78
GO =
(17)
(18)
CFOS
908.5
=
= 0.919
500 ⋅ D (500 ) ⋅ (1.978 )
m = 1.25 ⋅ GO (GO − 0.2 ) = 1.25 ⋅ 0.919(0.919 − 0.2 ) = 0.825
Vm = 0.85 ⋅ k w ⋅ k g ⋅ δ m ⋅
(16)
3400
3400
= (0.85 )(1.037 )(1.3 )(0.78 )0.825
8
8
1+
1+
D
1.978
(19)
= 629.3kV
(20)
Therefore, the minimum vegetation clearance distance for a maximum line to line ac operating
voltage of 550 kV at 7000 feet above sea level is 1.978 m (6.49 feet). Table 1 provides
calculated distances for various altitudes and maximum system operating ac voltages.
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
43
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Ta b le 1 — Min im u m Ve g e t a t io n Cle a ra n ce Dis t a n ce s ( MVCD) 7
For Alternating Current Voltages (feet)
MVCD
(feet)
MVCD
(feet)
MVCD feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
Over sea
level up to
500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over
10000 ft
up to
11000 ft
( AC )
Nominal
System
Voltage (KV)
( AC )
Maximum
System
Voltage (kV) 8
765
800
8.2ft
8.33ft
8.61ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
500
550
5.15ft
5.25ft
5.45ft
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
345
362
3.19ft
3.26ft
3.39ft
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
287
302
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
230
242
3.03ft
3.09ft
3.22ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
161*
169
2.05ft
2.09ft
2.19ft
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
138*
145
1.74ft
1.78ft
1.86ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
115*
121
1.44ft
1.47ft
1.54ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
88*
100
1.18ft
1.21ft
1.26ft
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
69*
72
0.84ft
0.86ft
0.90ft
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
* Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above).
7
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will be achieved at time of vegetation
maintenance.
8
Where applicable lines are operated at nominal voltages other than those listed, The Transmission Owner should use the maximum system voltage to determine the appropriate clearance for that line.
44
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Table 1 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level
Over 152.4m
Over 304.8m
up to
Over 609.6m
Over 914.4m
up to
Over 1219.2m
up to
Over 1524 m
Over 1828.8m
up to
Over 2133.6m
up to
Over 2438.4m
up to
Over 2743.2m
up to
Over 3048m
up to
3352.8m
1219.2m
1524m
2133.6m
2438.4m
2743.2m
3048m
up to
up to
152.4m
304.8m
up to
609.6m
up to
914.4m
1828.8m
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
69*
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
45
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
Table 1 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
46
Over sea
level up to
500 ft
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
Over 500 ft
up to
1000 ft
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage (kV)
( DC )
Nominal
Pole to
Ground
Voltage (kV)
( DC )
Nominal
Pole to
Ground
Voltage (kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage (kV)
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000 ft
up to 7000
ft
Over 7000 ft
up to 8000
ft
Over 8000 ft
up to 9000
ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over 152.4
m up to
304.8 m
(Over 304.8
m up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to 1219.2m
(Over
1219.2m up
to 1524m
(Over 1524
m up to
1828.8 m)
(Over
1828.8m up
to 2133.6m)
(Over
2133.6m up
to 2438.4m)
(Over
2438.4m up
to 2743.2m)
(Over
2743.2m up
to 3048m)
(Over
3048m up to
3352.8m)
±750
14.12ft
(4.30m)
14.31ft
(4.36m)
14.70ft
(4.48m)
15.07ft
(4.59m)
15.45ft
(4.71m)
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.91ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
±600
10.23ft
(3.12m)
10.39ft
(3.17m)
10.74ft
(3.26m)
11.04ft
(3.36m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
13.54ft
(4.13m)
±500
8.03ft
(2.45m)
8.16ft
(2.49m)
8.44ft
(2.57m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
±400
6.07ft
(1.85m)
6.18ft
(1.88m)
6.41ft
(1.95m)
6.63ft
(2.02m)
6.86ft
(2.09m)
7.09ft
(2.16m)
7.33ft
(2.23m)
7.56ft
(2.30m)
7.80ft
(2.38m)
8.03ft
(2.45m)
8.27ft
(2.52m)
8.51ft
(2.59m)
±250
3.50ft
(1.07m)
3.57ft
(1.09m)
3.72ft
(1.13m)
3.87ft
(1.18m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5.00ft
(1.52m)
5.17ft
(1.58m)
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
List of Acronyms and Abbreviations
ANSI
American National Standards Institute
IEEE
Institute of Electrical and Electronics Engineers
IVM
Integrated Vegetation Management
NERC
North American Electric Reliability Corporation
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
ii
NERC S ta n d a rd FAC-003-2 Te c h n ic a l Re fe re n c e
References
Andrew Hileman, Insulation Coordination for Power System, Marcel Dekker, New York, NY
1999
EPRI, EPRI Transmission Line Reference Book 345 kV and Above, Electric Power Research
Council, Palo Alto, Ca. 1975.
IEEE Std. 516-2003 IEEE Guide for Maintenance Methods on Energized Power Lines
G. Gallet, G. Leroy, R. Lacey, I. Kromer, General Expression for Positive Switching Impulse
Strength Valid Up to Extra Long Air Gaps, IEEE Transactions on Power Apparatus and
Systems, Vol. pAS-94, No. 6, Nov./Dec. 1975.
IEEE Std. 1313.2-1999 (R2005) IEEE Guide for the Application of Insulation Coordination.
2007 National Electric Safety Code
EPRI, HVDC Transmission Line Reference Book, EPRI TR-102764 , Project 2472-03, Final Report,
September 1993
ANSI. 2001. American National Standard for Tree Care Operations – Tree, Shrub, and Other
Plant Maintenance – Standard Practices (Pruning). Part 1. American National Standards
Institute, NY
ANSI. 2006. American National Standard for Tree Care Operations – Tree, Shrub, and Other
Plant Maintenance – Standard Practices (Integrated Vegetation Management a. Electric
Utility Rights-of-way). Part 7. American National Standards Institute, NY.
Cieslewicz, S. and R. Novembri. 2004. Utility Vegetation Management Final Report. Federal
Energy Regulatory Commission. Commissioned to support the Federal Investigation of the
August 14, 2003 Northeast Blackout. Federal Energy Regulatory Commission, Washington,
DC. pg. 39.
Kempter, G.P. 2004. Best Management Practices: Utility Pruning of Trees. International
Society of Arboriculture, Champaign, IL
Miller, R.H. 2007. Best Management Practices: Integrated Vegetation Management. Society of
Arboriculture, Champaign, IL.
Yahner, R.H. and R.J. Hutnik. 2004. Integrated Vegetation Management on an electric
transmission right-of-way in Pennsylvania, U.S. Journal of Arboriculture. 30:295-300
Results-based Initiative Ad Hoc Group. Acceptance Criteria of a Reliability Standard.
iii
Transmission Vegetation Management | Standard FAC-003-2 Technical Reference – September 30, 2011
| File Type | application/pdf |
| File Title | December xx, 2011 |
| Author | Holly Hawkins |
| File Modified | 2011-12-21 |
| File Created | 2011-12-21 |